CHRD 10-K & 10-Q changes, risk factors and insider trading

Global geopolitical tensions may create heightened volatility in crude oil, NGL and natural gas prices and could adversely affect our business, financial condition and results of operations.

OnOil Februaryand 24,gas 2022,prices Russianare militaryimpacted forcesby commencedgeopolitical atensions militaryand operationconflict, insuch as conflicts between Russia and Ukraine, and the sustained conflict and disruptionhostilities in the regionMiddle that has occurred since this date is expected to continue. Additionally, on October 7, 2023, Hamas, a U.S.-designated terrorist organization, launched a series of coordinated attacks from the Gaza Strip onto Israel. On October 8, 2023, Israel formally declared war on Hamas. The parties entered into truces to pause the conflictEast and have periodically resumed hostilities; accordingly, the state of the conflict remains fluidpolitical and unpredictable.military Additionally, Iranian-backed Houthi rebels have conducted several attacks against commercial shippingdevelopments in theSouth Red Sea and conflict has occurred and continues to occur in Lebanon, Syria and Yemen. Hostilities could continue to escalate in Lebanon and Syria and spread across the Middle East.America. Although the length, impact and outcome of the military conflicts between Russia and Ukraine and betweenelsewhere Hamasin andthe IsraelMiddle East are highly unpredictable, these conflicts could lead to significant market and other disruptions, including significant volatility in commodity prices and supply of energy resources, instability in financial markets, supply chain interruptions, political and social instability and other material and adverse effects on macroeconomic conditions. It is not possible at this time to predict or determine the ultimate consequence of these regional conflicts. These conflicts and their broader impacts could have a lasting impact on the short- and long-term operations and financial condition of our business and the global economy.

Events involving limited liquidity, defaults, non-performance or other adverse developments that affect financial institutions, transactional counterparties or other companies in the financial services industry or the financial services industry generally, or concerns or rumors about any events of these kinds or other similar risks, have in the past and may in the future lead to market-wide liquidity problems. For example, in 2023, the failures, closure and receivership of Silicon Valley Bank, Silvergate Bank, Signature Bank and First Republic Bank impacted financial markets. Although we did not have any funds deposited with these banks, we regularly maintain domestic cash deposits in FDIC-insured banks, which exceed the FDIC insurance limits. The failure of a bank, or events involving limited liquidity, defaults, non-performance or other adverse conditions in the financial markets impacting the financial institutions with which we conduct business, or concerns or rumors about such events, may lead to disruptions in access to our bank deposits, impair the ability of the banks participating in our current or future credit agreements from honoring their commitments to us or otherwise adversely impact our liquidity and financial performance. We regularly maintain domestic cash deposits in FDIC-insured banks, which exceed the FDIC insurance limits. There can be no assurance that our deposits in excess of the FDIC or other comparable insurance limits will be backstopped by the U.S. or applicable foreign government, or that any bank or financial institution with which we do business will be able to obtain needed liquidity from other banks, government institutions or by acquisition in the event of a failure or liquidity crisis.

Disruptions to the broader economy and financial markets, including the Federal Reserve’s actions with respect to interest rates and the timing of any anticipated decrease in rates following the September 2024 rate reduction, as well as the potential for a U.S.or government shutdown (such as the near shutdown in December 2024 related to debt ceiling legislation),shutdowns may also reduce our ability to access capital or result in such capital being available on less favorable terms. Higher interest rates or costs and tighter financial and operating covenants may make it more difficult to acquire financing on acceptable terms or at all. Any of these impacts, or any other impacts resulting from the factors described above or other related or similar factors, could have material adverse impacts on our liquidity, financial condition, results of operations and cash flows.

A substantial or extended decline in commodity prices, for crude oil and, to a lesser extent, NGLsNGL and natural gas, may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The prices we receive for our crude oil and, to a lesser extent, NGLsNGL and natural gas, heavily influence our revenue, profitability, cash flow from operations, access to capital and future rate of growth. Crude oil, NGLsNGL 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, NGLsNGL and natural gas have been volatile, including declines and thesevolatility during 2025. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following:

•worldwide and regional economic and political conditions impacting the global supply and demand for crude oil, NGLsNGL and natural gas;

•the price and quantity of imports of foreign crude oil, NGLsNGL and natural gas;

•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;

•the ability for the United States to continue to export crude oil, natural gas, and NGLsNGL;

•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, NGLsNGL and natural gas and related infrastructure;

•price and availability of competitors’ supplies of crude oil, NGLsNGL and natural gas;

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, NGLsNGL 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 crude oil, which could adversely affect our business, financial condition, results of operations and cash flows.

•limitations in the market for crude oil, NGLsNGL 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 generatecontribute theto highest possiblemaximizing returns. Risks that we face while drilling include, but are not limited to, the following:

•the ability to run tools and other equipment consistently through the horizontal wellbore.

•actual prices we receive for crude oil, NGLsNGL and natural gas;

If crude oil, NGL and natural gas prices decline, or for an extended period of time remain at depressed levels, we may be required to take write-downs of the carrying values of our oil and gas properties and goodwill.properties.

We review our proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. In addition, we assess our unproved properties periodically for impairment on a prospect-by-prospect basis based on remaining lease terms, drilling results or future plans to develop acreage. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and gas properties, which may result in a decrease in the amount available under our revolving credit facility. These circumstances could also indicate that the carrying amount of our goodwill may exceed the fair value, which could result in a future goodwill impairment.

Substantially all of our producing properties and operations are located in the Williston BasinBasin, making us vulnerable to risks associated with operating in a concentrated geographic area.

Our producing properties are geographically concentrated in the Williston Basin in northwestern North Dakota and northeastern Montana. As a result, we may be disproportionately exposed to the impact of economics in the Williston Basin or delays or interruptions of production from those wells caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of crude oil, NGLsNGL 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, NGLsNGL 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, NGLsNGL 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.

Various federal agencies within the U.S. Department of the Interior (the “Department of the Interior”), particularly the BIA and the Office of Natural Resource Revenue, along with the Three Affiliated Tribes of the Fort Berthold Indian Reservation (“MHA Nation”), promulgate and enforce regulations pertaining to operations on the Fort Berthold Indian Reservation. In addition, the MHA Nation is a sovereign nation having the right to enforce laws and regulations independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees, approvals and other conditions that apply to lessees, operators and contractors conducting operations on the Fort Berthold Indian Reservation. Lessees and operators conducting operations on tribal lands may be subject to the MHA Nation’s court system. The Department of the Interior previously issued an official opinion stating that the minerals beneath the Missouri River riverbed located on the Fort Berthold Indian Reservation belong to the MHA Nation and not the State of North Dakota, overturning a 2020 Trump-agency decision that gave the State of North Dakota ownership. The case is now back on remand before the D.C. Federal District Court and other subsequent related motions and claims have been made, the outcome of each of which is uncertain and cannot be predicted. One or more of these factors may increase our costs of doing business on the Fort Berthold Indian Reservation and may have an adverse impact on our ability to effectively transport products within the Fort Berthold Indian Reservation or to conduct our operations on such lands.

We depend upon a limited number of midstream providers for a large portion of our midstream services, and our failure to obtain and maintain access to the necessary infrastructure from these providers to successfully deliver crude oil, natural gas and NGLsNGL to market may adversely affect our earnings, cash flows and results of operations.

Our delivery of crude oil, NGLsNGL and natural gas depends upon the availability, proximity and capacity of pipelines, other transportation facilities and gathering and processing facilities primarily owned by a limited number of midstream service providers. The capacity of transmission, gathering and processing facilities may be insufficient to accommodate potential production from existing and new wells, which may result in substantial discounts in the prices we receive for our crude oil, NGLsNGL 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, NGLsNGL 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, NGLsNGL and natural gas to market. To the extent these services are delayed or unavailable, we would be unable to realize revenue from wells served by such facilities until suitable arrangements are made to market our production. Additionally, we may be subject to price increases from time to time, including in connection with renewals. Our failure to obtain these services on acceptable terms could materially harm our business.

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. AThe Corps completed the final EIS in December 2025 and formal decision by the Corps is expected byduring the endfirst quarter of 20252026; however, we cannot guarantee when the Corps may ultimately complete these actions. We regularly use DAPL in addition to other outlets to market our crude oil to end markets. Our risk is not concentrated at DAPL as we have alternative outlets to sell our crude oil production using multiple modes of transportation; however, in the event DAPL were to cease operating, we would anticipate Williston Basin crude oil prices to weaken materially before improving as the market adapts to rail transportation.

Drilling locations are scheduled to be drilled over several years and may not yield crude oil, NGLsNGL or natural gas in commercially viable quantities.

Our drilling locations are in various stages of evaluation, ranging from a location which is ready to drill to a location that will require substantial additional interpretation. There is no way to predict in advance of drilling and testing whether any particular location will yield crude oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether crude oil or natural gas will be present or, if present, whether crude oil, NGLsNGL or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of crude oil, NGLsNGL 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.

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, NGLsNGL 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.

We may enter into arrangements with respect to existing or future drilling locations that result in a greater proportion of our locations being operated by others. As a result, we may have limited ability to exercise influence over the operations or future development of the drilling locations operated by our partners. Dependence on the operator could prevent us from realizing our target returns for those locations. Our non-operated activity is expected to increase in 2025 and beyond relative to prior years. The success and timing of exploration and development activities operated by our partners will depend on a number of factors that will be largely outside of our control, including:

Our ability to conduct business can be impacted by changes in tariffs, changes or repeals of trade agreements or the imposition of other trade restrictions or retaliatory actions imposed by various governments. For example, during 2025, the new Trump Administration hasenacted proposedand to significantly increasemodified tariffs on certain foreign imports into the United StatesStates, and any new tariffs have beentrade and continuetariff policies continued to beevolve rapidlythroughout andthe actively evolving.year. The state,scope, duration and scopeeconomic impact of anyexisting tariffstariffs, enactedas arewell as the potential for additional changes or retaliatory measures by other governments, remain uncertain and unpredictable. Other effects of these changes, including responsive actions from governments and the unpredictability of U.S. governmental action and response, could also have significant impacts on our financial results. We cannot predict what further action may be taken with respect to tariffs or trade relations between the U.S. and other governments, and any further changes in U.S. or international trade policy could have an adverse impact on our business.

Failure to comply with federal, state and local laws and regulations could adversely affect our ability to produce, gather and transport our crude oil, NGLsNGL and natural gas and may result in substantial penalties.

Our operations are substantially affected by federal, state and local laws and regulations, particularly as they relate to the regulation of crude oil, NGL and natural gas production and transportation. These laws and regulations include regulation of crude oil, NGL and natural gas exploration and production and related operations, including a variety of activities related to the drilling of wells, and the interstate transportation of crude oil, NGLsNGL 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, NGLsNGL and natural gas and fluids as a result of drilling activities in the United States, there have been a variety of regulatory initiatives at the federal and state levels to restrict crude oil, NGL and natural gas drilling operations in certain locations. Any increased regulation or suspension of crude oil, NGL and natural gas exploration and production, or revision or reinterpretation of existing laws and regulations, that arise out of these incidents or otherwise could result in delays and higher operating costs. Such costs or significant delays could have a material adverse effect on our business, financial condition and results of operations. With regard to our physical purchases and sales of energy commodities, we must also comply with anti-market manipulation laws and related regulations enforced by FERC, the CFTC and the FTC. To the lesser extent we are a shipper on interstate pipelines, we must comply with the FERC-approved tariffs of such pipelines and with federal policies related to the use of interstate pipeline capacity. Should we fail to comply with all applicable statutes, rules, regulations and orders of FERC, the CFTC or the FTC, we could be subject to substantial penalties and fines.

We expect to continue to consider acquisitions, dispositions, investments in joint ventures, partnerships and other strategic alternatives with the objective of maximizing stockholder value. Our Board of Directors and our management may from time to time be engaged in evaluating potential transactions and other strategic alternatives. In addition, from time to time, we may engage financial advisors, enter into non-disclosure agreements, conduct discussions, and undertake other actions that may result in one or more transactions. Although there would be uncertainty that any of these activities or discussions would result in definitive agreements or the completion of any transaction, we may devote a significant amount of our management resources to analyzing and pursuing such a transaction, which could negatively impact our operations, and may impair our ability to retain and motivate key personnel. In addition, we may incur significant costs in connection with seeking such transactions or other strategic alternatives regardless of whether the transaction is completed. In the event that we consummate an acquisition, disposition, partnership or other strategic transaction in the future, we cannot be certain that we would fully realize the potential benefit of such a transaction and cannot predict the impact that such strategic transaction might have on our operations or stock price. Any potential transaction would be dependent upon a number of factors that may be beyond our control, including, among other factors, pricing volatility, market conditions, industry trends, regulatory limitations and the interest of third parties in us and our assets. There can be no assurance that the exploration of strategic alternatives will result in any specific action or transaction. Further, any such strategic alternative may not ultimately lead to increased stockholder value. We do not undertake to provide updates or make further comments regarding the evaluation of strategic alternatives, unless otherwise required by law.

Stakeholder and market attention to matters related to corporate responsibilityresponsibility, including in the oil and gas industry, may impact our business and ability to secure financing.

Businesses across all industries are facing scrutiny from some stakeholders related to corporate responsibility and ESG practices. Further, there are a number of state-level anti-ESG initiatives in the U.S. that may conflict with other regulatory requirements or various stakeholders’ expectations. Businesses that do not adapt to or comply withignore evolving investor or stakeholder expectations and standards, which are continuing to evolve, or businesses that are perceived to have not responded appropriately to the growing concern for issues related to ESG, corporate responsibility or in some instances anti-ESG sentiment, regardless of whether there is a legal requirement to do so, may suffer from reputational damage, and the business, financial condition and/or stock price of such business entity could be materially and adversely affected. Attention to climate change, societal expectations on companies to address climate change, investor and societal expectations regarding voluntary disclosures related to ESG or corporate responsibility, mandatory disclosures and consumer demand for alternative forms of energy may result in increased costs, reduced demand for our products, reduced profits, increased legislative and judicial scrutiny, investigations and litigation, reputational damage and negative impacts on our access to capital markets. To the extent that societal pressures or political or other factors are involved, it is possible that we could be subject to additional governmental investigations, private litigation or activist campaigns as stockholders may attempt to effect changes to our business or governance practices.

AsIn part of our ongoing effortresponse to enhanceregulatory ourrequirements ESGor practicesstakeholder related to corporate responsibility, our Board of Directors has established the Safetyexpectations and Sustainabilityindustry Committee, which is charged with overseeing our ESG policies related to corporate responsibility. Committee members are expected to review the implementation and effectiveness of our ESG programs and policies. Additionally, to help strengthen our ESG performance, we have implemented compensation practices focused on value creation and aligned with stockholders’ interests. Additionally, whilestandards, 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.arrangements. In addition, voluntary disclosures regarding ESG matters, as well as any ESG disclosures currently required or required in the future, could result in private litigation or government investigation or enforcement action regarding the sufficiency or validity of such disclosures. Moreover, failure or a perception (whether or not valid) of failure to implement ESG strategies related to corporate responsibility or achieve ESG goals or commitments, including any GHG emission reduction or carbon intensity goals or commitments, could result in private litigation and damage our reputation, cause investors or consumers to lose confidence in us and negatively impact our operations. Notwithstanding our election to pursue aspirational ESG-related targets in the future, we may receive pressure from investors, lenders or other groups to adopt more aggressive climate or other ESG-related goals or conversely to abandon ESG related goals. We cannot guarantee that we will be able to implement such goals because of potential costs or technical or operational obstacles. Additionally, interest on the part of investors and regulators in factors related to ESG and corporate responsibility and stakeholders’ demand for, and scrutiny of, disclosure related to ESG and corporate responsibility has also increased the risk that companies could be perceived as, or accused of, making inaccurate or misleading statements regarding their claims related to corporate responsibility, goal, targets, efforts or initiatives, often referred to as “greenwashing.” Such perception or accusation could damage our reputation and result in litigation or regulator actions.

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Companies in the energy industry, and in particular those focused on oil or natural gas extraction, often do not score as well under such assessments compared to companies in other industries. 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, whileWhile we may participate in various voluntary frameworks and certification programs to improve the ESG profile of our operations and services, we cannot guarantee that such participation or certification will have the intended results on our ESG profile. Unfavorable ESG ratings and activism directed at shifting funding away from companies with energy-related assets could lead to increased negative sentiment toward us, our customers and our industry.

These negative sentiments and responses to initiatives aimed at limiting climate change and reducing air pollution could lead to the diversion of investment to other industries, which could result in downward pressure on the stock prices of oil and gas companies, including ours, and limit our access to and increase costs of capital for potential acquisitions or development projects, all of which could impact our future financial results. Additionally, to the extent matters related to corporate responsibility negatively impact our reputation, we may not be able to compete as effectively or recruit or retain employees, which may adversely affect our operations.

We face risks related to pandemics, epidemics, outbreaks or other public health events (such as the COVID-19 pandemic) that are outside of our control and could significantly disrupt our operations and adversely affect our business and financial condition. For example, the global outbreak of COVID-19 during 2020 negatively impacted demand for crude oil and natural gas because of reduced global and national economic activity levels. In response to any future public health crisis (like COVID-19),crisis, there may be wide-ranging actions taken by international, federal, state and local public health and governmental authorities to contain and combat the outbreak and spread of such public health crisis in regions across the United States and the world.

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, NGLsNGL and natural gas that we are ultimately able to produce in commercial quantities, which adversely impacts our revenues and profitability.

Our ability to produce crude oil, NGLsNGL 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, NGLsNGL and natural gas and secure and retain trained personnel.

Our ability to acquire additional drilling locations and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, market crude oil, NGLsNGL 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.

Chord Energy CorporationCorporation, a Delaware corporation (together with itsour consolidated subsidiaries, the “CompanyCompany,” “Chord,” “we,” “us,” or “Chordour”), is an independent exploration and production (“E&P”) company engaged in the acquisition, exploration, development and production of crude oil, natural gas liquids (“NGL”) and natural gas primarily in the Williston Basin.Basin with limited non-operated interests in the Marcellus Shale. On May 31, 2024, we acquired Enerplus Corporation, a corporation existing under the laws of the Province of Alberta, Canada (“Enerplus”) in a stock-and-cash transaction (such transaction, the “Arrangement”). Our mission is to responsibly produce hydrocarbons while exercising capital discipline, operating efficiently, improving continuously and providing a fun and rewarding environment for our employees. We are ideally positioned to enhance return of capital and generate strong free cash flow,flow and enhance return of capital, while being responsible stewards of the communities and environment where we operate.

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, NGLsNGL and natural gas have experienced significant fluctuations in recent yearsyears, including sustained decreases during 2025, and may continue to fluctuate widely or continue to decrease in the future due to a combination of macro-economic factors that impact the supply and demand for crude oil, NGLsNGL and natural gas. CommodityThe pricespotential remainedfor lowcontinued throughoutvolatility 2024in dueour to a combination of factors, including slowing demand growth as a result of decreased globalmarkets, economic activity levelsuncertainty and higher levels of production from domesticunfavorable oil and gas producersmarket indynamics, theincluding UnitedOPEC+ Statesannouncements during 2025 regarding increased oil production targets and otherU.S. non-OPEC+tariffs countries.and potential retaliatory tariffs, may have an adverse impact on our future business operations, financial condition and liquidity.

In an effort to reduce inflationary pressures that emerged in the broader economy, central banks began to aggressively raise interest rates in 2022. After peaking in 2023, interest rates began to trend downward during 2024.2024 and 2025. Although U.S. inflation rates have shown signs of moderating, higher interest rates generally reduce economic activity levels, which have and could in the future again result in lower commodity prices due to reduced demand for crude oil, NGLsNGL and natural gas (see “Item 7A. —Quantitative and Qualitative Disclosures about Market Risk—Inflation risks” for additional information). The uncertainties resulting from the potential economic outcomes of monetary policy decisions of central banks as well as tariff and trade policy decisions of the U.S. or other governments, coupled with the geopolitical risks associated with the continued military conflicts in the Red Sea Region and the warswider Middle East and the recent developments in relations between Russiathe United States and Ukraine and Hamas and Israel,Venezuela, make it difficult to predict future impacts to commodity prices.

While we are unable to predict future commodity prices, we do not believe that an impairment of our oil and gas properties or goodwill is reasonably likely to occur in the near future at current price levels; however, we would evaluate the recoverability of the carrying value of our oil and gas properties and goodwill as a result of a future material or extended decline in the price of crude oil, NGLsNGL or natural gas or a material increase in the costs of labor, materials or services. See “Part I, Item 1A. Risk Factors—If crude oil, NGL and natural gas prices decline, or for an extended period of time remain at depressed levels, we may be required to take write-downs of the carrying values of our oil and gas properties and goodwill” for additional information.

In an effort to improve price realizations from the sale of our crude oil, NGLsNGL and natural gas, we manage our commodities marketing activities in-house, which enables us to market and sell our crude oil, NGLsNGL 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.”

We sell a significant amount of our crude oil production through gathering systems connected to multiple pipeline and rail facilities. These gathering systems, which originate at the wellhead, reduce the need to transport barrels by truck from the wellhead, helping remove trucks from local highways and reduce greenhouse gas emissions. As of December 31, 2024,2025, substantially all of our gross operated crude oil production was connected to gathering systems. Our market optionality on these crude oil gathering systems allows us to shift volumes between pipeline andand, to a lesser extent, rail markets in order to optimize price realizations. Expansions of both railpipeline and pipelinerail 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, 20242025 and 2023.2024. The results reported for the year ended December 31, 2025 reflect the consolidated results of Chord, while the results reported for the year ended December 31, 2024 reflect the consolidated results of Chord, including combined operations with Enerplus beginning on May 31, 2024 and the 2023 acquisition of acreage in the Williston Basin, while the results reported for the year ended December 31, 2023 reflect the consolidated results of Chord, including the 2023 acquisition of acreage in the Williston Basin beginning on June 30, 2023, and excluding the impact from the business combination with Enerplus,2024, unless otherwise noted.

•E&P and other capitalCapital expenditures (excluding capitalized interest) were $1.2$1,357.9 billionmillion for the year ended December 31, 2024.2025.

•Net cash provided by operating activities was $2.1$2,040.7 billionmillion and net income was $848.6$44.5 million for the year ended December 31, 2024.2025.

•Paid $10.15$5.20 per share base-plus-variablebase cash dividenddividends for the year ended December 31, 2024.2025.

•Repurchased $442.8$364.5 million of common stock (excluding accrued excise taxes) during the year ended December 31, 20242025 with $592.6$952.2 million remaining under the new $750$1.0 millionbillion share repurchase program authorized by the Board of Directors in OctoberAugust 2024.2025.

Our crude oil, NGL and natural gas revenues are derived from the sale of crude oil, NGL and natural gas production. These revenues do not include the effects of derivative instruments and may vary significantly from period to period as a result of changes in volumes of production sold and/or changes in commodity prices. OurAdditionally, our revenues for the year ended December 31, 20242025 increasedwere positively impacted due to the Arrangement, which expanded our operations primarily in the Williston Basin. Our purchased oil and gas sales are derived from the sale of crude oil, NGLsNGL and natural gas purchased through our marketing activities primarily to optimize transportation costs, for blending to meet pipeline specifications or to cover production shortfalls. Revenues and expenses from crude oil, NGL and natural gas sales and purchases are generally recorded on a gross basis, as we act as a principal in these transactions by assuming control of the purchased crude oil or natural gas before it is transferred to the counterparty. In certain cases, we enter into sales and purchases with the same counterparty in contemplation of one another, and these transactions are recorded on a net basis.

(1)For the yearyears ended December 31, 2025 and 2024, natural gas production volume from the Marcellus Shale was 45,151 MMcf and 24,727 MMcf.MMcf, respectively. The realized natural gas price related to this production, prior to the effect of derivative settlements, was $3.15 per Mcf and $1.78 per Mcf.Mcf for the years ended December 31, 2025 and 2024, respectively.

NGLCrude oil revenues. Our NGLcrude oil revenues decreased $15.7$24.4 million to $162.1$3,546.9 million for the year ended December 31, 20242025 as compared to the year ended December 31, 2023.2024. TheExcluding decreasethe wasincrease primarilyof $491.4 million due to our expanded operations as a result of the Arrangement, our crude oil revenues decreased $545.6 million due to lower NGLcrude oil realized prices year-over-year resulting in a $48.3 million decrease,year-over-year, partially offset by an increase of $32.6$29.8 million due to higher NGLtotal crude oil production volumes primarily as a result of the Arrangement.sold. Average NGLcrude oil sales prices, without derivative settlements, decreased by $3.70$10.89 per barrel period over periodyear-over-year to an average of $9.92$62.78 per barrel for the year ended December 31, 2024 primarily2025 due to widerdecreases differentialsin onNYMEX incrementalWTI productionand volumeswidening primarilyin-basin as a result of the Arrangement.differentials.

Natural gasNGL revenues. Our natural gasNGL revenues decreased $16.0$23.8 million to $102.8$138.3 million for the year ended December 31, 20242025 as compared to the year ended December 31, 2023.2024. TheExcluding decrease was primarily due to lower natural gas realized prices year-over-year resulting in a $49.0 million decrease, offset by anthe increase in total natural gas production volumes sold of $33.0$3.8 million, primarilymillion due to our expanded operations as a result of the Arrangement.Arrangement, our NGL revenues decreased $34.5 million due to lower NGL realized prices year-over-year, partially offset by an increase of $6.9 million due to higher total NGL production volumes sold. Average natural gasNGL sales prices, without derivative settlementssettlements, decreased by $0.59$2.70 per Mcfbarrel period over period to $0.84an average of $7.22 per Mcfbarrel for the year ended December 31, 20242025 primarily due to wider differentials on incremental production volumes primarily as a decreaseresult in natural gas index prices, coupled withof the impact of incurring fixed fees and related fee escalations for the majority of our natural gas marketing contracts beginning in the second quarter of 2023.Arrangement.

Purchased oil and gas sales. Purchased oil and gas sales increaseddecreased $650.7$435.0 million to $1.4$980.0 billionmillion for the year ended December 31, 20242025 as compared to the year ended December 31, 2023.2024. This increasedecrease was primarily due to ana increasedecrease in the volume of crude oil purchased and subsequently sold,sold partiallyas offsetwell byas lower crude oil and gas prices year-over-year.

Lease operating expenses. LOE increased $165.5$158.2 million to $824.4$982.6 million for the year ended December 31, 20242025 as compared to the year ended December 31, 2023.2024. The increase was primarily driven by our expanded operations after the ArrangementArrangement, contributing $181.3$115.3 million of additional LOE period over period. ExcludingAdditionally, theworkover increasecosts fromincreased theby Arrangement, LOE decreased $31.7$30.2 million and fixed and variable costs increased by $12.6 million primarily due to lower122 workovergross costs,(99 offsetnet) byoperated annew increasewells ofbrought $17.0online millionduring dueyear toended higherDecember variable31, costs period over period.2025. LOE per Boe decreasedincreased $0.73$0.05 per Boe period over period to $9.68$9.73 per Boe for the year ended December 31, 20242025 primarily due to higher production volumes and lowerincreased workover costs.

Gathering, processing and transportation expenses. Gathering, processing and transportation (“GPT”) expenses increased $87.3$23.4 million to $267.6$290.9 million for the year ended December 31, 20242025 as compared to the year ended December 31, 2023.2024. The increase was primarily due to our expanded operations after the Arrangement contributing $79.5$48.2 million of additional GPT periodexpenses. overThis periodincrease and lower fair value gains of $26.4 million attributable to the completion of certain derivative transportation contracts at the end of 2023 and during the first half of 2024. These increases werewas partially offset by a decrease of $19.5 million due to lower transportation rates,rates of $12.8 million, primarily due to several contracts expiring during the year ended December 31, 2024.2024, Theseand netlower increasesfair resultedvalue losses of $5.9 million attributable to the completion of certain derivative transportation contracts in anJune increase in2024. GPT expenses ofdecreased $0.29$0.26 per Boe period over period to $3.14$2.88 per Boe for the year ended December 31, 2024.2025 primarily due to an increase in production volumes, lower transportation rates and fair value losses period over period.

Purchased oil and gas expenses. Purchased oil and gas expenses increaseddecreased $651.0$437.2 million to $1.4$975.1 billionmillion for the year ended December 31, 20242025 as compared to the year ended December 31, 20232024 primarily due to ana increasedecrease in the volume of crude oil purchased and subsequently sold,sold partiallyas offsetwell byas lower crude oil and gas prices year-over-year.

Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) expense increased $509.2$362.4 million to $1.1$1,470.2 billionmillion for the year ended December 31, 20242025 as compared to the year ended December 31, 2023.2024. The increase was primarily due to $209.6 million of additional depletion expense due to a higher depletion rate year-over-year, coupled with $128.2 million of additional DD&A expense related to an overall increase in production volumes year-over-year, mainly due to our expanded operations after the ArrangementArrangement, contributingas $281.1well million of additional DD&A expense period over period,as an increase ofin $225.0accretion million due to a higher depletion rate period over period and an increaseexpense of $4.5$19.8 million due to higher production volumes year-over-year.million. The depletion rate increased $3.50$1.82 per Boe year-over-year to $12.70$14.12 per Boe for the year ended December 31, 20242025 primarily due to the purchase consideration allocated to the fair value of oil and gas properties acquired in the Arrangement.Arrangement and the 2025 Williston Basin Acquisition.

Gain (loss) on sale of assets, net. During the yearyears ended December 31, 2025 and 2024, we recorded a net gain on sale of assets of $8.7 million and $17.1 million, respectively, primarily related to certain non-operated wellbore divestitures in the Williston Basin. During the year ended December 31, 2023, we recorded a net loss on sale of assets of $2.8 million, primarily related to divestituresdivestiture of certain ofoil ourand non-coregas properties locatedwithin outsideeach of the Williston Basin.period.

Derivative instruments. During the year ended December 31, 2025, we recorded a $127.6 million net gain on derivative instruments, which was primarily comprised of a net gain of $125.4 million associated with our commodity derivative contracts and a net gain of $2.2 million associated with a contract that included contingent consideration. The net gain of $125.4 million on commodity derivative contracts included a realized gain of $63.8 million on settled commodity derivative contracts, coupled with an unrealized gain of $61.6 million related to the change in fair value of our commodity derivative contracts primarily driven by a downward shift in the futures curve for forecasted commodity prices. During the year ended December 31, 2024, we recorded a $12.6 million net gain on derivative instruments, which was primarily comprised of a net gain of $7.5 million associated with our commodity derivative contracts and a net gain of $5.1 million associated with a contract that includesincluded contingent consideration. The net gain of $7.5 million on commodity derivative contracts included an unrealized gain of $6.6 million related to the change in fair value of our commodity derivative contracts primarily driven by a downward shift in the futures curve for forecasted commodity prices, coupled with a realized gain of $0.9 million on settled commodity derivative contracts. During the year ended December 31, 2023, we recorded a $63.2 million net gain on derivative instruments, which was primarily comprised of a net gain of $56.4 million associated with our commodity derivative contracts and a net gain of $6.8 million associated with a contract that includes contingent consideration. The net gain of $56.4 million on commodity derivative contracts included an unrealized gain of $313.1 million related to the change in fair value of our commodity derivative contracts primarily driven by a downward shift in the futures curve for forecasted commodity prices, partially offset by a realized loss of $256.7 million on settled commodity derivative contracts.

Other income, net. For the year ended December 31, 2025, we recognized $15.0 million of other income, net, which related primarily to proceeds from the disposition of surplus equipment, partially offset by remeasurement of equipment inventory. For the year ended December 31, 2024, we recognized $5.0 million of other income, netnet, aswhich compared to $10.0 million for the year ended December 31, 2023. The $5.0 million decrease wasrelated primarily due to a decrease in interest income year-over-year associated with lowerthe balancesaverage cash balance in our money market accounts.account.

As of December 31, 2024,2025, we had $1.1$2,156.7 billionmillion of liquidity available, including $37.0$1,967.2 million in cash and cash equivalents and $1.0 billion of aggregate unused borrowing base capacity available under our Credit Facility (as defined below). Duringand the$189.5 firstmillion quarterin cash and cash equivalents. We had no net borrowings outstanding under our Credit Facility and $32.8 million of 2025,outstanding we expect to have approximately $1.6 billionletters of liquidity available after taking into account the increase in the aggregate amount of elected commitments to $2.0 billion.credit. Our primary sources of liquidity were from cash on hand, cash flows from operations andoperations, available borrowing base capacity under ourthe Credit Facility.Facility, proceeds from the issuance of the 2030 Senior Notes and the 2033 Senior Notes and cash on hand. Our primary liquidity requirements were debt repayments under our Credit Facility, capital expenditures for the development of oil and gas properties, dividend payments,acquisitions, debt repayments under ourthe Credit2026 Facility,Senior Notes, share repurchases, cashdividend consideration and transaction costs associated with the Arrangement,payments and working capital requirements.

Capital availability is affected by prevailing conditions in our industry, the global economy, the global banking and financial markets, stakeholder scrutiny of sustainability matters and other factors, many of which are beyond our control. The U.S. Federal Reserve recentlyhas decreasedcontinued to steadily decrease interest rates, however the potential for such rates to decrease further or to increase or remain elevated for an extended period of time creates additional economic uncertainty. Although we are unable to predict future interest rates, this disruption to the broader economy and financial markets may reduce our ability to access capital or result in such capital being available on less favorable terms, which could in the future negatively affect our liquidity. We believe, however, we have adequate liquidity to fund our capital expenditures and meet our contractual obligations during the next 12 months and the foreseeable future.

We also incurred certain costs for advisory, legal and other third-party fees in connection with the Arrangement, which were recorded to G&A expenses on the Consolidated Statements of Operations. During the yearyears ended December 31, 2025 and 2024, we incurred merger-relatedmerger and acquisition-related costs of $9.8 million and $89.3 million, respectively, and were primarily comprised of severance, legal, and advisory expenses related to legalthe and advisory services and severance costs.Arrangement.

Our cash flows depend on many factors, including the price of crude oil, NGLsNGL 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.

Our material cash requirements from known obligations include repayment of outstanding borrowings and interest payment obligations related to our long-term debt, payment of income taxes, obligations to plug, abandon and remediate our oil and gas properties at the end of their productive lives, paymentobligations ofassociated incomewith taxes,our leases, obligations associated with outstanding commodity derivative contracts that settle in a loss position,position and obligations to pay dividends on vested equity awards that include dividend equivalent rights and obligations associated with our leases.awards. 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.repurchases Onand variable dividend payouts. There were no borrowings outstanding under the Credit Facility (as defined below) as of December 31, 2025; however, on a quarterly basis, we pay a commitment fee on the average amount of borrowing base capacity not utilized during the quarter and fees calculated on the average amount of letter of credit balances outstanding during the quarter.

We also have contracts which include provisions for the delivery, transport or purchase of a minimum volume of crude oil, NGLs,NGL, natural gas and water within specified time frames, the majority of which are five years or less. Under the terms of these contracts, if we fail to deliver, transport or purchase the committed volumes we will be required to pay a deficiency payment for the volumes not tendered over the duration of the contract. The estimable future commitments under these agreements were $579.2$467.9 million as of December 31, 2024.2025. We believe that for the substantial majority of these agreements, our future production will be adequate to meet our delivery commitments or that we can purchase sufficient volumes of crude oil, NGLsNGL and natural gas from third parties to satisfy our minimum volume commitments.

•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 continue to control supply and to agree on and comply with production levels;

Our revenue, profitability and ability to return cash to shareholders depend substantially on factors beyond our control, such as economic, political and regulatory developments as well as competition from other sources of energy. Energy markets experienced significant volatility during the first quarterhalf of 2026, driven primarily by geopolitical tensions and the resulting disruptions to global oil supply. Following the escalation of conflict in the Middle East beginning in late February,February and the NYMEXresulting WTIdisruptions spotto priceglobal increasedoil moreand thannatural 50%gas bysupply following the endeffective closure of the firstStrait quarter.of Hormuz to most commercial shipping. Continued geopolitical tensions, including the uncertain pace and durability of any diplomatic resolution between the United States and Iran and periodic actual and potential escalations in hostilities, uncertainty around OPEC+ production policypolicy, including the withdrawal of the United Arab Emirates from OPEC+ effective in May 2026 and the withdrawal’s potential to reduce the group’s ability to coordinate global supply, and the potential economic outcomes of tariff and trade policy decisions of the U.S. or other governments create difficulty in predicting future impacts to commodity prices, which could affect our financial position, results of operations, cash flows, capital and operating costs, and the quantities of crude oil, NGL and natural gas reserves that may be economically produced.

Additionally, we sell a significant amount of our crude oil production through gathering systems connected to multiple pipeline and rail facilities. These gathering systems, which originate at the wellhead, reduce the need to transport barrels by truck from the wellhead, helping remove trucks from local highways and reduce greenhouse gas emissions. As of MarchJune 31,30, 2026, substantially all of our gross operated crude oil and natural gas production were connected to gathering systems. Our market optionality on these crude oil gathering systems allows us to shift volumes between pipeline and, to a lesser extent, rail markets in order to optimize price realizations. Expansions of both pipeline and rail facilities in the Williston Basin hashave reduced prior constraints on crude oil takeaway capacity and improved our price differentials received at the lease.

In an effort to reduce inflationary pressures that emerged in the broader economy, central banks have in the past raised interest rates. AlthoughDuring the first half of 2026, higher energy and commodity prices contributed to a renewed rise in U.S. inflationinflation, ratesand havethe shownU.S. signsFederal ofReserve moderating,held higherits benchmark interest rate steady. Higher interest rates generally reduce economic activity levels, which have and could in the future again result in lower commodity prices due to reduced demand for crude oil, NGL and natural gas. To the extent we and our relevant markets experience high inflation, we may see cost increases in our operations, including increases in equipment and labor costs, and as a result our revenues, estimates of future reserves, borrowing base calculations and impairment assessments could be negatively impacted.

•Production volumes averaged 275,615286,447 Boepd (57%58% oil), including average daily crude oil volumes of 158,027165,436 Bopd in the firstsecond quarter of 2026.

•Capital expenditures (excluding capitalized interest) were $344.9$416.7 million in the firstsecond quarter of 2026.

•Lease operating expenses (“LOE”) were $9.87$10.28 per Boe in the firstsecond quarter of 2026.

•Net cash provided by operating activities was $507.5$1,116.2 million and net income was $108.6$525.2 million for the firstsecond quarter of 2026.

•Paid $1.30 per share base cash dividend on MarchJune 27,5, 2026.

•Repurchased $70.7$147.4 million of common stock (excluding accrued excise taxes) in the firstsecond quarter of 2026.

•Declared a base cash dividend of $1.30 per share of common stock. The dividend will be payable on JuneSeptember 5,4, 2026 to shareholders of record as of MayAugust 20, 2026.

Net Income (Loss)

We had net income of $108.6$525.2 million and $633.8 million for the three and six months ended MarchJune 31,30, 2026, whichrespectively, decreasedprimarily 51%due asto increased realized oil prices and production volumes and net impacts from derivative instruments, compared to $219.8net losses of $389.9 million and $170.1 million for the three and six months ended MarchJune 31,30, 2025, respectively, primarily due to ana unrealizednon-cash lossimpairment charge on our commoditygoodwill derivativerecorded contracts driven by an upward shift induring the crudesecond oilquarter futuresof curve.2025. Additional impacts on net income from increases and decreases in certain revenues and expenses are further explained below.

Our crude oil, NGL and natural gas revenues are derived from the sale of crude oil, NGL and natural gas production. These revenues do not include the effects of derivative instruments and may vary significantly from period to period as a result of changes in volumes of production sold and/or changes in commodity prices. Our purchased oil and gas sales are derived from the sale of crude oil 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 salesrelated purchases and purchasessales with theone sameor counterpartymore counterparties in contemplation of one another, and these transactions are recorded on a net basis.

____________________ (1)For the three months ended June 30, 2026 and March 31, 2026, Decembernatural 31,gas 2025production volume from the Marcellus Shale was 10,637 MMcf and 11,745 MMcf, respectively. The realized natural gas price related to this production, prior to the effect of derivative settlements, was $2.10 per Mcf and $6.40 per Mcf for the three months ended June 30, 2026 and March 31, 2026, respectively. For the six months ended June 30, 2026 and June 30, 2025, natural gas production volume from the Marcellus Shale was 11,745 MMcf, 10,95022,382 MMcf and MMcf23,384 11,563,MMcf, respectively. The related realized natural gas price related to this production, prior to the effect of derivative settlementssettlements, was $6.40 per Mcf, $3.19$4.36 per Mcf and $4.71$3.59 per Mcf for the threesix months ended MarchJune 31,30, 2026, December 31, 20252026 and MarchJune 31,30, 2025, respectively.

Three months ended MarchJune 31,30, 2026 as compared to three months ended March 31, 20252026

Crude oil revenues. Our crude oil revenues increased $40.2$418.7 million to $996.3$1,415.0 million for the three months ended MarchJune 31,30, 2026 as compared to the three months ended March 31, 2025.2026. The increase was primarily due to higher crude oil productionaverage volumesrealized soldprices periodquarter over periodquarter resulting in a $27.1$340.4 million increase, coupled with an increase of $13.1$78.3 million due to higher crude oil realizedproduction pricesvolumes periodsold quarter over period.quarter. Average crude oil sales prices, without derivative settlements, increased by $0.94$23.94 per barrel periodquarter over periodquarter to an average of $70.05$93.99 per barrel for the three months ended MarchJune 31,30, 2026 primarily due to an increase in the average NYMEX WTI.WTI quarter over quarter.

NGL revenues. Our NGL revenues decreasedincreased $23.1$6.4 million to $38.2$44.6 million for the three months ended MarchJune 31,30, 2026 as compared to the three months ended March 31, 2025.2026. The decreaseincrease was primarily due to lower realized NGL prices period over period resulting in a $23.9 million decrease, partially offset by an increase of $0.8 million due to higher NGL production volumes sold periodquarter over period.quarter resulting in a $3.8 million increase, coupled with an increase of $2.6 million due to higher average realized NGL prices quarter over quarter. Average NGL sales prices, without derivative settlements, decreasedincreased by $5.52$0.59 per barrel periodquarter over periodquarter to an average of $8.66$9.25 per barrel for the three months ended MarchJune 31,30, 2026 primarily due to decreasesincreases in the corresponding NGL product index prices.prices for butane, pentane and propane.

Natural gas revenues. Our natural gas revenues increaseddecreased $30.1$81.3 million to $116.1$34.7 million for the three months ended MarchJune 31,30, 2026 as compared to the three months ended March 31, 2025.2026. The increasedecrease was primarily due to higher natural gas realized prices period over period resulting in a $31.0 million increase, partially offset by a decrease of $0.9 million due to lower natural gas productionaverage volumesrealized soldprices periodquarter over period.quarter resulting in an $81.4 million decrease quarter over quarter. Average natural gas sales prices, without derivative settlements, increaseddecreased by $0.84$2.20 per Mcf periodquarter over periodquarter to $3.14$0.94 per Mcf for the three months ended MarchJune 31,30, 2026 primarily due to increasesthe seasonality of warmer weather resulting in the corresponding natural gaslower index prices periodquarter over period.quarter.

Purchased oil and gas sales. Purchased oil and gas sales increased $403.4$163.4 million to $515.0$678.4 million for the three months ended MarchJune 31,30, 2026 as compared to the three months ended March 31, 2025.2026. This increase was primarily due to anhigher increasecrude oil prices quarter over quarter, partially offset by a decrease in the volume of crude oil purchased and subsequently sold periodquarter over period.quarter.

Three months ended MarchJune 31,30, 2026 as compared to three months ended March 31, 20252026

Lease operating expenses. LOE increased $11.8$22.9 million to $244.9$267.8 million for the three months ended MarchJune 31,30, 2026 as compared to the three months ended March 31, 2025.2026. The increase was primarily due to increasedhigher activityvariable costs of $10.0 million, higher fixed costs of $9.6 million and higher workover costs of $6.6 million, partially offset by a decrease in operating costs from our non-operated assets of $14.6 million, higher workover costs of $4.6$3.3 million and higher variable costs of $1.9 million, partially offset by decreased fixed costs of $9.4 million periodquarter over period.quarter. The same factors contributed to an increase in LOE per Boe, which increased $0.31$0.41 per Boe periodquarter over periodquarter to $9.87$10.28 per Boe for the three months ended MarchJune 31,30, 2026.

Gathering, processing and transportation expenses. GPT expenses decreased $6.3$4.3 million to $67.0$62.8 million for the three months ended MarchJune 31,30, 2026 as compared to the three months ended March 31, 2025.2026. The decrease was primarily due to loweran NGL and natural gas gathering and processing fees of $7.6$8.8 million andchange lowerin crudethe oilnon-cash transportationvaluation feesadjustment ofon $1.9our million,cumulative pipeline imbalance position, partially offset by an increase in crude oil production volumes transported of $3.1 million and a net increase in natural gas and NGL productiongathering, volumesprocessing and transportation fees of $3.5$1.4 million periodquarter over period.quarter. Excluding the non-cash valuation adjustment, GPT expenses decreasedincreased $0.31$0.04 per Boe periodquarter over periodquarter to $2.70$2.83 per Boe for the three months ended MarchJune 31,30, 2026 primarily due to lowerhigher natural gas and NGL gathering, processing and transportation fees.

Purchased oil and gas expenses. Purchased oil and gas expenses increased $398.5$161.8 million to $509.8$671.7 million for the three months ended MarchJune 31,30, 2026 as compared to the three months ended March 31, 20252026. This increase was primarily due to anhigher increasecrude oil prices quarter over quarter, partially offset by a decrease in the volume of crude oil purchased periodand subsequently sold quarter over period.quarter.

Production taxes. Production taxes increased $12.1$39.2 million to $86.7$125.9 million for the three months ended MarchJune 31,30, 2026 as compared to the three months ended March 31, 2025. The increase was2026 primarily due to higher crude oil revenues periodquarter over period, partially offset by a $10.9 million decrease in non-recurring refunds period over period related to certain North Dakota wells receiving an extraction tax exemption.quarter. The production tax rate as a percentage of crude oil, NGL and natural gas revenues increasedof from 6.8%8.4% for the three months ended MarchJune 31,30, 20252026 toincreased from 7.5% for the three months ended March 31, 2026 primarily due to increasedhigher crude oil revenues andquarter fewerover wellsquarter qualifyingcoupled forwith thenatural extractiongas taxcomprising exemptiona smaller percentage of total sales relative to the prior period.

Depreciation, depletion and amortization. DD&A expense increased $34.4$25.0 million to $384.2$409.2 million for the three months ended MarchJune 31,30, 2026 as compared to the three months ended March 31, 2025.2026. The increase was primarily duedriven toby $24.3higher millionproduction volumes of additional$21.2 depletion expense due to a higher depletion rate period over period,million, coupled with $9.3an millionincrease in accretion expense of additional$3.8 DD&A expensemillion related to anplugging overalland increaseabandonment in production volumes. The depletion rate increased $1.11 per Boe period over period to $15.20 per Boe for the three months ended March 31, 2026 primarily due to a decrease in proved developed reserves period over period.charges.

General and administrative expenses. G&A expenses decreased $0.9$7.6 million to $37.5$29.9 million for the three months ended MarchJune 31,30, 2026 as compared to the three months ended March 31, 2025.2026. The decrease was primarily attributable to a decrease in merger-related costs of $5.1 million, lower employeeequity-based compensation expenses of $2.5$3.7 million anddue to the impact of our stock price on the fair value of our liability-based awards, coupled with a decrease of $1.7$2.5 million primarily attributabledue to lower current expected credit losses and various cost savingsdecreases related to other G&A expenses, partially offset by an increaseexpenses of $4.5$1.4 million due to higher current expected credit losses and an increase in equity-based compensation costs of $4.0 million periodquarter over period.quarter.

InvestmentDerivative in equity securities.instruments. We recorded a $22.8$107.9 million net gain on derivative instruments for the three months ended June 30, 2026, which included an unrealized gain of $201.0 million related to ourthe investmentchange in Energyfair Transfervalue of our commodity derivative contracts primarily driven by a downward shift in the futures curve for forecasted commodity prices, partially offset by a realized loss on settled commodity derivative contracts of $93.1 million. During the three months ended March 31, 2026, which included an unrealized gain of $20.4 million as a result of an increase in the fair value of the investment during the period, coupled with a gain of $2.4 million for a cash distribution from Energy Transfer during the period. During the three months ended March 31, 2025, we recorded a $241.5 million net loss ofon $4.9derivative million related to our investment in Energy Transfer,instruments, which included an unrealized loss of $7.3$223.0 million asrelated ato resultthe of a decreasechange in the fair value of theour investmentcommodity duringderivative contracts primarily driven by an upward shift in the period,futures partiallycurve offsetfor byforecasted commodity prices, coupled with a gainrealized loss on settled commodity derivative contracts of $2.4$18.5 million for a cash distribution from Energy Transfer during the period.million.

Income tax benefit (expense). Our effective tax rate was recorded at 23.6% and (15.2)% and 25.0% of pre-tax income for the three months ended MarchJune 31,30, 2026 and 2025,March 31, 2026, respectively. OurThe effective tax rate for the three months ended June 30, 2026 was higher than the statutory federal rate of 21% primarily as a result of state income taxes. The effective tax rate for the three months ended March 31, 2026 was lower than the statutory federal rate of 21% primarily as a result of the identification of an error in the tax provision for the three and six months ended June 30, 2025 pertaining to the impact of goodwill impairment on our deferred taxes on unremitted earnings.earnings, Aswhich aresulted result, we recognizedin an additional income tax benefit of $41.8 million duringin the threefirst monthsquarter ended March 31,of 2026, with a corresponding decrease to deferred tax liabilities. The effective tax rate for the three months ended March 31, 2025 was higher than the statutory federal rate of 21% primarily as a result of the impact of state income taxes and deferred taxes on unremitted earnings.