SM Energy Co: Form 10-K for the period ended Dec 31, 2025

In addition to the other information included in this report, the risk factors discussed below should be carefully considered when evaluating an investment in SM Energy. For the purposes of this section, “we,” “our,” “us,” “Company” and “SM Energy” refer to the post-Merger company following the Civitas Merger. Our risk factors are summarized as follows:

Risks Related to the Civitas Merger

• We may be unable to successfully integrate Civitas’ business into our business or achieve the anticipated benefits of the Merger, which may have a material adverse effect on our business, financial condition or results of operations.
• We have incurred additional costs in connection with the Merger, which will continue during a portion of 2026.
• Securities class action and derivative lawsuits may be brought against us in connection with the Merger, which could result in substantial costs.
• The market price for our common stock may be affected by factors different from those that historically have affected SM Energy common stock or Civitas common stock.
• Our ability to utilize certain tax attributes may be limited as a result of the Civitas Merger.
• The historical business relationships of SM Energy and Civitas may be subject to disruption due to uncertainty associated with the Merger, which could have a material adverse effect on our results of operations, cash flows and financial position.
• The synergies and other benefits attributable to the Merger may vary from expectations.

Risks Related to Commodity Prices and Global Macroeconomics

• Oil, gas, and NGL prices are volatile, and declines in prices may adversely affect our profitability, financial condition, cash flows, access to capital, and ability to grow.
• Future oil, gas, and NGL price declines or unsuccessful exploration efforts may result in write-downs of our asset carrying values.
• Weakness in economic conditions, inflation, or uncertainty in financial markets may have material adverse impacts on our business that we cannot predict.
• Global geopolitical tensions may create heightened volatility in oil, gas, and NGL prices and could adversely affect our business, financial condition and results of operations.

Risks Related to Oil and Gas Operations and the Industry

• The proposed divestiture of certain of our South Texas assets may not be completed on the anticipated terms or at all, which could adversely affect our ability to execute our publicly stated deleveraging objectives.
• The loss of personnel could adversely affect our business.
• Our increasing dependence on digital technologies puts us at risk for a cyber incident that could result in information theft, data corruption, operational disruptions or financial loss.
• We are incorporating artificial intelligence technologies into our processes and these technologies may present business, compliance, and reputational risks.
• Competition in our industry is intense, and many of our competitors have greater financial, technical, and human resources than we do.
• Our ability to sell oil, gas, and NGLs, and/or receive market prices for our production, may be adversely affected by constraints on gathering systems, processing facilities, pipelines, rail systems, and other transportation systems owned or operated by third-

parties or by other interruptions beyond our control, which could obstruct, limit, or eliminate our access to oil, gas, and NGL markets.

• We have entered into firm transportation contracts that require us to pay fixed sums of money to our counterparties regardless of the quantities actually transported under these contracts. If we are unable to deliver the necessary quantities of oil, gas, NGL, or produced water to our counterparties, our results of operations, financial position, and liquidity could be adversely affected.
• We have limited control over the activities on properties we do not operate.
• We rely on third-party service providers to conduct drilling and completion and other related operations.
• The inability of customers or co-owners of assets to meet their obligations may adversely affect our financial results.
• Many of our properties are in areas that may have been partially depleted or drained by offset wells and certain of our wells or future locations may be adversely affected by actions other operators may take when drilling, completing, or operating wells that they own.
• Oil and gas drilling, completion, and production activities are subject to numerous risks, including the risk that no commercially producible oil, gas, or NGLs will be found.
• The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced.
• Our ability to produce oil, gas, and NGLs economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling and/or completions operations or are unable to dispose of or recycle the water we produce at a reasonable cost and in accordance with applicable environmental rules and regulations.
• If we are unable to replace reserves and increase our reserve life index, we will not be able to sustain production.
• The results of our operations are subject to drilling and completion technique risks, and results may not meet our expectations for reserves or production. As a result, we may incur material write-downs, and the value of our undeveloped acreage could decline if drilling and completion results are unsuccessful.
• The actual quantities and present value of our proved oil, gas, and NGL reserves may be less than we have estimated, and the cost to develop our reserves may be more than we have estimated.
• Our disposition activities may be subject to factors beyond our control, and in certain cases we may retain unforeseen liabilities for certain matters.
• Title to the properties in which we have an interest may be impaired by title defects.
• Our business could be negatively impacted by security threats, including cybersecurity threats, terrorism, armed conflict, and other disruptions.
• We are subject to operating and environmental risks and hazards that could result in substantial losses or liabilities that may not be fully insured.
• The impact of seasonal and extreme weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Risks Related to Litigation and Government Regulations

• In the future, we may be subject to claims, litigation, administrative proceedings and regulatory actions that may not be resolved in our favor.
• Our operations are subject to complex laws and regulations, including environmental regulations, which result in substantial costs and other risks.
• Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
• Federal and state regulatory initiatives relating to air quality and greenhouse gas emissions could result in increased costs and additional operating restrictions or delays.
• Legislative and regulatory initiatives and litigation related to global warming and climate change could have an adverse effect on our operations and the demand for oil, gas, and NGLs, and could result in significant litigation, capital, and related expenses.
• Requirements to reduce gas flaring could have an adverse effect on our operations.
• Senate Bill 181’s requirement, which applies to our Colorado operations, that we own or control more than 45 percent of the working or mineral interest in order to statutorily pool our applicable interest may make it much more difficult for us to develop such interests, which could have a material adverse effect on our business, financial condition, and results of operations.

Risks Related to Debt, Liquidity, and Access to Capital

• Commodity price declines could result in a decrease in the amount available to us under our Credit Agreement.
• Negative public perception and investor sentiment regarding our business and the oil and gas industry as a whole could adversely affect our business, operations, and our ability to attract capital.
• Substantial capital is required to develop and replace our reserves.
• Downgrades in our credit ratings by various credit rating agencies could impact our access to capital and have a material adverse effect on our business and financial condition.
• Our commodity derivative contract activities may result in financial losses or may limit the prices we receive for oil, gas, and NGL sales.
• The amount of our debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse economic conditions, and make it more difficult for us to make payments on our debt.
• The agreements governing our debt arrangements contain various covenants that limit our discretion in the operation of our business, could prohibit us from engaging in transactions we believe to be beneficial, and could lead to the accelerated repayment of our debt.

Risks Related to Corporate Governance and Ownership of Public Equity Securities

• Our certificate of incorporation and by-laws have provisions that discourage corporate takeovers and could prevent stockholders from receiving a takeover premium on their investment, which could adversely affect the price of our common stock.
• The price of our common stock may fluctuate significantly, which may result in losses for investors.
• We may not always pay dividends on our common stock or repurchase common stock under our Stock Repurchase Program.

Risks Related to the Civitas Merger

We may be unable to successfully integrate Civitas’ business into our business or achieve the anticipated benefits of the Merger, which may have a material adverse effect on our business, financial condition or results of operations.

The success of the Merger depends in part on whether we can complete the integration of the Civitas assets that we have not previously operated into our existing business in an efficient and effective manner, and there can be no assurance that we will be able to successfully integrate or otherwise realize the anticipated benefits of the Merger. The integration process may result in the disruption of ongoing business and there could be potential unknown liabilities and unforeseen expenses associated with the Merger that were not discovered in the course of performing due diligence. Integration may also require significant time and focus from management following the Merger that may disrupt our business and results of operations. Potential risks or difficulties include, among others:

• complexities associated with integrating our existing complex systems, technologies and other workflows with new assets;
• the inability to retain the services of key management and personnel;
• the accuracy of our assessments of the assets acquired in the Merger, including recoverable reserves, transportation costs and availability, drilling and completion equipment cost and availability, regulatory, permitting, and related matters;
• establishing business relationships with new third party contractors and other service providers with whom we have no prior experience; and
• potential unknown liabilities and unforeseen expenses, delays or regulatory conditions associated with the Merger.

Any of these issues could adversely affect our ability to maintain relationships with customers, suppliers, employees, and other constituencies. We may fail to realize the anticipated benefits expected from the Merger. The success of the Merger will depend, in significant part, on our ability to successfully complete the integration of the acquired assets and realize the anticipated strategic benefits from the Merger. The anticipated benefits of the Merger may not be realized fully or at all or may take longer to realize than expected. Actual operating, technological, strategic, and revenue opportunities, if achieved at all, may be less significant than expected or may take longer to achieve than anticipated. If we are not able to realize the anticipated benefits expected from the Merger within the anticipated timing or at all, our business, financial, and operating results may be adversely affected.

We have incurred additional costs in connection with the Merger, which will continue during a portion of 2026.

During the fiscal year ended December 31, 2025, we incurred non-recurring costs associated with the Merger, and we expect to continue to incur such costs during 2026. A substantial majority of non-recurring expenses consist of change in control payments and transaction costs which include, among others, fees paid to financial, legal, accounting, and other advisors.

Securities class action and derivative lawsuits may be brought against us in connection with the Merger, which could result in substantial costs.

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

The market price for our common stock may be affected by factors different from those that historically have affected SM Energy common stock or Civitas common stock.

Our financial position will differ from our financial position prior to the closing of the Merger, and our post-Merger results of operations may be affected by factors that are different from those that have historically affected the results of operations of SM Energy and of Civitas. Accordingly, the market price and performance of our common stock is likely to be different from the performance of the SM Energy and of Civitas common stock absent of the Merger. In addition, general fluctuations in trading activity and prices on the NYSE could have a material adverse effect on the market for, or liquidity of, our common stock, regardless of our actual operating performance.

Our ability to utilize certain tax attributes may be limited as a result of the Civitas Merger.

Our ability to utilize the former SM Energy’s carryover research and development credits and the former Civitas’ net operating losses (“NOL” or “NOLs”) and other tax attributes may be limited. The former Civitas had a material amount of federal tax NOLs that remained unutilized as of the Closing Date of the Merger.

Our ability to utilize these tax attributes to reduce future taxable income and reduce future tax liability depends on many factors, including our future income, which cannot be assured. Sections 382 and 383 of the Code (“Sections 382 and 383”) generally impose an annual limitation on the amount of attributes that can be used when a corporation has undergone an “ownership change” (as determined under Sections 382 and 383). An ownership change generally occurs if one or more stockholders (or groups of stockholders) who are each deemed to own at least five percent of such corporation’s stock has increased their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling three-year period. In the event that an ownership change occurs, utilization of the relevant corporation’s tax attributes would be subject to an annual limitation under Sections 382 and 383.

The historical business relationships of SM Energy and Civitas may be subject to disruption due to uncertainty associated with the Merger, which could have a material adverse effect on our results of operations, cash flows and financial position.

Parties with which the former SM Energy or the former Civitas do business may experience uncertainty associated with the Merger, including with respect to current or future business relationships with the Company. Our business relationships may be subject to disruption as customers, distributors, suppliers, vendors, landlords, joint venture partners and other business partners may attempt to delay or defer entering into new business relationships, negotiate changes in existing business relationships or consider entering into business relationships with parties other than us. These disruptions could have a material adverse effect on our results of operations, cash flows and our financial position, as well as a material adverse effect on the our ability to realize the expected cost savings and other benefits of the Merger.

The synergies and other benefits attributable to the Merger may vary from expectations.

We may fail to realize the anticipated synergies and other benefits expected from the Merger, which could adversely affect our business, financial condition and operating results. The success of the Merger will depend, in significant part, on our ability to successfully integrate the acquired business and realize the anticipated strategic benefits and synergies from the combination. The anticipated benefits of the transaction may not be realized fully or at all, or may take longer to realize than expected. Actual operating, technological, strategic and revenue opportunities, if achieved at all, may be less significant than expected or may take longer to achieve than anticipated. If we are not able to achieve these objectives and realize the anticipated synergies and other benefits expected from the Merger within the anticipated timing or at all, our business, financial condition and operating results may be adversely affected.

Risks Related to Commodity Prices and Global Macroeconomics

Oil, gas, and NGL prices are volatile, and declines in prices may adversely affect our profitability, financial condition, cash flows, access to capital, and ability to grow.

Our revenues, operating results, profitability, future rate of growth, and the carrying value of our oil and gas properties depend heavily on the prices we receive for oil, gas, and NGL sales. Oil, gas, and NGL prices also affect our cash flows available for capital expenditures, debt reductions, return of capital, and other expenditures, our borrowing capacity, and the volume and value of our oil, gas, and NGL reserves. In addition, we may have oil and gas property impairments or downward revisions of estimates of proved reserves if prices fall significantly. Refer to Significant Developments in 2025 and Reserves in Part I, Items 1 and 2, Comparison of Financial Results and Trends Between 2025 and 2024 and Overview of Liquidity and Capital Resources in Part II, Item 7, and Note 1 – Summary of Significant Accounting Policies, Note 8 – Fair Value Measurements, and Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 for specific discussion.

Historically, the markets for oil, gas, and NGLs have been volatile, and they are likely to continue to be volatile. Wide fluctuations in oil, gas, and NGL prices often result from relatively minor changes in the supply of and demand for oil, gas, and NGLs, market uncertainty, and other factors that are beyond our control, including:

• global and domestic supplies of oil, gas, and NGLs, and the productive capacity of the industry as a whole;
• the level of consumer demand for oil, gas, and NGLs;
• overall global and domestic economic conditions;
• inflation and other economic factors that contribute to market volatility including tariffs and trade restrictions;
• weather conditions;
• the availability and capacity of gathering, transportation, processing, storage, and/or refining facilities in asset-specific or localized areas;
• liquefied natural gas deliveries to and from the United States;
• the increased demand for, price, and availability of alternative fuels or sources of energy;
• technological advances in, and regulations affecting, energy consumption and conservation;
• the ability of the members of OPEC+ to maintain effective oil price and production controls;
• War and Geopolitical Instability;
• shipping channel constraints and disruptions to and from oil and gas producing countries or regions;
• actual or perceived epidemic or pandemic risks;
• strengthening and weakening of the United States dollar relative to other currencies;
• stockholder activism or activities by non-governmental organizations to limit sources of funding or restrict the exploration and production of oil, gas, and NGLs and related infrastructure; and
• governmental regulations and taxes.

Declines in oil, gas, and NGL prices would reduce our revenues and could also reduce the amount of oil, gas, and NGLs that we can produce economically, which could have a material adverse effect on our business, financial condition, liquidity, results of operations, and prospects.

Future oil, gas, and NGL price declines or unsuccessful exploration efforts may result in write-downs of our asset carrying values.

We follow the successful efforts method of accounting for our oil and gas properties. All property acquisition costs and development costs are capitalized when incurred. Exploratory well costs are initially capitalized, pending the determination of whether proved reserves have been discovered. If commercial quantities of proved reserves are not discovered with an exploratory well, the costs initially capitalized are expensed as dry hole costs.

The capitalized costs of our oil and gas properties, on a depletion pool basis, cannot exceed the estimated undiscounted future net cash flows of that depletion pool. If net capitalized costs exceed undiscounted future net cash flows, we generally must write down the costs to the estimated discounted future net cash flows of that depletion pool. Write downs for unproved properties are also evaluated for carrying costs in excess of fair value. This evaluation considers the potential for abandonment due to actual and anticipated lease expirations, as well as actual and anticipated losses on acreage due to title defects, changes in development plans, and other inherent acreage risks. Declines in the prices of oil, gas, or NGLs, or unsuccessful exploration efforts, could cause proved and/or unproved property impairments in the future, which could have a material adverse effect on our business, financial condition, liquidity, and results of operations.

We review the carrying values of our properties for indicators of impairment on a quarterly basis using the prices in effect as of the end of each quarter. Once incurred, a write-down of oil and gas properties held for use cannot be reversed at a later date, even if oil, gas, or NGL prices increase.

Weakness in economic conditions, inflation, or uncertainty in financial markets may have material adverse impacts on our business that we cannot predict.

The United States and global economies and financial systems regularly experience turmoil and upheaval characterized by extreme volatility in prices of equity and debt securities, periods of diminished liquidity and credit availability, inability to access capital markets, the bankruptcy, failure, collapse, or sale of financial institutions, inflation, tariffs or trade restrictions, and heightened levels of intervention by the United States federal government and other governments. Weakness or uncertainty in the United States economy or other large economies could have a material adverse effect on our business and financial condition. For example:

• market conditions, lack of buyer interest, regulatory delays or unforeseen economic issues could impede achieving our divestiture target of at least $1.0 billion and delay our ability to reach long term strategic goals;
• inflation has increased certain costs of our drilling and completion activities, and the costs of oilfield goods, services, personnel, equipment, and materials in recent years and could continue or worsen and further impact our financial condition, liquidity, and results of operations, and could limit our pool of economic development opportunities;
• economic recession could impact demand for oil, gas, and NGLs, and cause commodity price volatility;
• the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables;
• the liquidity available under our Credit Agreement could be reduced if any of our lenders is unable to fund its commitment;
• our ability, or the ability of our suppliers or contractors, to access the capital markets may be restricted or non-existent at a time when we or they would like, or need, to raise capital for our or their business, including for the exploration and/or development of reserves;
• our commodity derivative contracts could become economically ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection;
• the Federal Reserve may change interest rates, as they have in recent years, which could impact borrowing costs and suppress economic growth;
• variable interest rate spread levels, including for SOFR and the prime rate, could increase significantly, resulting in higher interest costs for unhedged variable interest rate-based borrowings under our Credit Agreement; and
• changes in tax laws and regulations could require us to adjust our business plan.

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

War and Geopolitical Instability could lead to significant market and other disruptions, including, but not limited to: significant volatility in commodity prices and supply of energy resources, instability in financial markets, supply chain interruptions, shipping channel constraints and disruptions, political and social instability, political and economic sanctions, geopolitical shifts, embargoes, changes in consumer or purchaser preferences, the potential destruction of critical oil-related infrastructure, as well as increases in cyberattacks and espionage. These factors could impact our operations and the financial condition of our business as well as the global economy.

Risks Related to Oil and Gas Operations and the Industry

The proposed divestiture of certain of our South Texas assets may not be completed on the anticipated terms or at all, which could adversely affect our ability to execute our publicly stated deleveraging objectives.

We have entered into the PSA with Caturus for the sale of certain of our South Texas assets as part of our previously announced plan to reduce debt and strengthen our capital structure. The completion of this Transaction, as defined in Note 17 – Mergers, Acquisitions, and Divestitures in Part II, Item 8 of this report, is subject to customary closing conditions including regulatory approvals and certain required consents, as well as the satisfaction of other contractual conditions. There can be no assurance that these conditions will be satisfied on the anticipated timeline or at all.

If the Transaction is delayed or not completed, we may not receive the anticipated proceeds within the expected timeframe, or at all, which could delay or prevent us from achieving our targeted leverage metrics or other strategic priorities. We may also incur Transaction-related costs, including advisory, legal and other expenses, regardless of whether the Transaction is completed, and management’s attention may be diverted during the pendency of the Transaction.

The loss of personnel could adversely affect our business.

We depend to a large extent on the efforts and continued employment of our executive management team, other key personnel, and our general labor force. The loss of their services could adversely affect our business. Our success in drilling and completing new wells and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers, landmen, and other professionals. Competition for many of these professionals can be intense. If we cannot retain our technical personnel or attract additional experienced technical personnel and professionals, our ability to compete could be harmed.

Our increasing dependence on digital technologies puts us at risk for a cyber incident that could result in information theft, data corruption, operational disruptions or financial loss.

We are subject to cybersecurity risks. The oil and gas industry, and our business, are increasingly dependent on digital technology. We use digital technology, including information technology (“IT”) and operational technology (“OT”), to conduct certain aspects of our drilling development, production and gathering activities, manage drilling rigs and completion equipment, gather and interpret seismic data, conduct reservoir modeling, record financial and operating data, and maintain employee and other databases. Our service providers, including those who gather, process, and market our oil, gas, and NGLs, are also increasingly reliant on digital technology. Our and their reliance on this technology increasingly puts us at risk for technology system failures, data or network disruptions, cyberattacks and other breaches in cybersecurity. Power failures, telecommunication or other system failures due to hardware or software malfunctions, computer viruses, vandalism, terrorism, natural disasters, fire, flood, human error or other means could significantly impair our ability to conduct our business.

Cybersecurity attacks are evolving and include, but are not limited to, malware (including viruses), phishing, vulnerability exploitation, insider threats, and physical or electronic security breaches, which may result in operational disruption; unauthorized access to or exfiltration of data; and other impacts to the confidentiality, availability, and integrity of systems and information. Geopolitical tensions or conflicts may further heighten the risk of cyberattacks. In particular, sophisticated nation state actors have, and may continue to, target companies operating in industries providing critical infrastructure. Deliberate attacks on, or security breaches in our systems, infrastructure, the systems and infrastructure of third-parties, or cloud-based applications could lead to disclosure of confidential information, a corruption or loss of our proprietary data, delays in production or exploration activities, difficulty in completing or settling transactions, challenges in maintaining our books and records, environmental damage, communication or other operational disruptions, and liability to third parties. Any insurance we might obtain in the future may not provide adequate protection from these risks. Any such events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability. As these cyber risks continue to evolve and our dependence on digital technologies grows, we may be required to expend significant additional resources to continue to modify or enhance our protective measures and remediate cyber vulnerabilities.

Refer to Cybersecurity in Part 1, Item 1C of this report for discussion of the Audit Committee’s role in cybersecurity governance. We did not experience any material cybersecurity incidents during 2025, however there can be no assurance that the measures we have taken to address IT and cybersecurity risks will prove effective in the future.

We are incorporating artificial intelligence technologies into our processes and these technologies may present business, compliance, and reputational risks.

Our business increasingly utilizes AI, machine learning, and automated decision making to improve our processes. Issues in the development and use of AI, combined with an uncertain regulatory environment, may result in new or enhanced governmental or regulatory scrutiny, litigation, confidentiality or security risks, reputational harm, liability, or other adverse consequences to our business operations, all of which could adversely affect our business, results of operations, and financial condition.

In addition, it is possible that AI and machine learning-technology could, unbeknownst to us, be improperly utilized by employees while carrying out their responsibilities. The use of AI can lead to unintended consequences, including the unauthorized use or disclosure of confidential and proprietary information, or generating content that appears correct but is factually inaccurate, misleading, biased, or otherwise flawed, which could harm our reputation and business and expose us to risks related to inaccuracies or errors in the output of such technologies. As the use of AI in our business becomes more prominent, we may be required to expend additional resources to further enhance our digital security, and we may face challenges in fully anticipating or implementing adequate preventive measures or mitigating potential harm. These costs may include deploying additional personnel and protection technologies, training employees, and engaging third party experts and consultants.

It is not possible to predict all of the risks related to the use of AI, machine learning and automated decision making, and developments in the regulatory frameworks governing the use of such technologies and in related stakeholder expectations may adversely affect our ability to develop and use such technologies or subject us to liability. If we fail to successfully integrate AI into our business processes, or if we fail to keep pace with rapidly evolving AI technological developments, including attracting and retaining talented data scientists, data engineers, and programmers, we may face a competitive disadvantage.

Competition in our industry is intense, and many of our competitors have greater financial, technical, and human resources than we do.

We face intense competition from oil and gas exploration and production companies of all sizes for the capital, equipment, expertise, labor, and materials required to operate oil and gas properties. Many of our competitors have financial, technical, and other resources exceeding those available to us, and many oil and gas properties are sold in a competitive bidding process in which our competitors may be able and willing to pay more for exploratory and development prospects and producing properties, or in which our competitors have technological information or expertise that is not available to us to evaluate and successfully bid for properties. As a result, we may not be successful in acquiring and developing profitable properties. In addition, other companies may have a greater ability to continue drilling activities during periods of low oil or gas prices and to absorb the burden of current and future governmental regulations and taxation. In addition, shortages of equipment, labor, or materials resulting from intense competition may result in increased costs or the inability to obtain those resources as needed. Our inability to compete effectively with companies in any area of our business could have a material adverse impact on our business activities, financial condition, and results of operations.

Our ability to sell oil, gas, and NGLs, and/or receive market prices for our production, may be adversely affected by constraints on gathering systems, processing facilities, pipelines, rail systems, and other transportation systems owned or operated by third-parties or by other interruptions beyond our control, which could obstruct, limit, or eliminate our access to oil, gas, and NGL markets.

The marketability of our oil, gas, and NGL production depends in part on the availability, proximity, and capacity of gathering systems, processing facilities, pipelines, rail systems, and other transportation systems, which are generally owned or operated by third parties. Any significant interruption in service from, damage to, or lack of available capacity in these systems and facilities can result in the shutting-in of producing wells, the delay, or discontinuance of development plans for our properties, increases in costs, or lower price realizations. Although we have some influence over the processing and transportation of our operated production, material changes in these business relationships could materially affect our operations. Federal, state, and tribal regulation of oil, gas, and NGL production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines or processing facilities, infrastructure or capacity constraints, train derailments, and general economic conditions could adversely affect our ability to produce, gather, process, transport, or market oil, gas, and NGLs.

Production may be interrupted, or shut in, from time to time for numerous reasons, including weather conditions, accidents, loss of pipeline, gathering, processing or transportation system access or capacity, field labor issues or strikes, or we might voluntarily curtail production in response to market or other conditions. If a substantial amount of our production is interrupted at the same time, it could adversely affect our cash flows and results of operations.

Our Uinta Basin operations include the use of rail systems operated by third-parties to transport our crude oil to market which involves inherent risk, including the potential for accidents and derailments. In the event of a rail system accident or derailment, there could be significant delays in the delivery of oil to processing facilities, or impacts to rail system access or capacity, which may disrupt our business operations and could adversely affect our financial condition. Additionally, we could experience financial losses related to spills or damages to the oil in transit that we may not be able to recoup from the third-party rail operators. We continue to monitor our transportation arrangements and maintain contingency plans to mitigate potential impacts of transportation-related disruptions; however, we cannot guarantee that such measures will adequately reduce the risks associated with transportation by rail.

We have entered into firm transportation contracts that require us to pay fixed sums of money to our counterparties regardless of the quantities actually transported under these contracts. If we are unable to deliver the necessary quantities of oil, gas, NGL, or produced water to our counterparties, our results of operations, financial position, and liquidity could be adversely affected.

As of December 31, 2025, we were contractually committed to deliver a minimum of 49 MMBbl of oil through December of 2032. We may enter into additional firm transportation agreements as we expand the development of our resource plays. In the event we encounter delays in drilling and completing our wells or otherwise due to construction, interruptions of operations, or delays in connecting new volumes to rail systems, gathering systems, or pipelines for an extended period of time, or if we further limit our capital expenditures due to future commodity price declines or for other reasons, the requirements to pay for quantities not delivered could have a material impact on our results of operations, financial position, and liquidity.

We have limited control over the activities on properties we do not operate.

Some of our properties are operated by other companies and involve third-party working interest owners. As a result, we have limited ability to influence or control the operation or future development of such properties, including the nature and timing of drilling and operational activities, the operator’s skill and expertise, compliance with environmental, safety and other regulations, the approval of other participants in such properties, the selection and application of suitable technology, or the amount of expenditures that we will be required to fund with respect to such properties. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the expenditures of such properties. These limitations and our dependence on the operator and other working interest owners in these projects could cause us to incur unexpected future costs.

We rely on third-party service providers to conduct drilling and completion and other related operations.

We rely on third-party service providers to perform necessary drilling and completion and other related operations. The ability of third-party service providers to perform such operations will depend on those service providers’ ability to compete for and retain qualified personnel, financial condition, economic performance, and access to capital, which in turn will depend upon the supply and demand for oil, gas, and NGLs, prevailing economic conditions, and financial, business, and other factors. Future periods of sustained low commodity prices could occur and could cause third-party service providers to consolidate or declare bankruptcy, which could limit our options for engaging such providers. The failure of a third-party service provider to adequately perform operations could delay drilling or completion or reduce production from the property and adversely affect our financial condition and results of operations.

The inability of customers or co-owners of assets to meet their obligations may adversely affect our financial results.

Substantially all of our accounts receivable result from oil, gas, and NGL sales or joint interest billings to co-owners of oil and gas properties we operate. This concentration of customers and joint interest owners may impact our overall credit risk because these entities may be similarly affected by various economic and other market conditions, including declines in oil, gas, and NGL prices. The loss of one or more of these customers could reduce competition for our products and negatively impact the prices of commodities we sell. We do not believe the loss of any single purchaser would materially impact our operating results, as we have numerous options for purchasers in each of our operating areas for our oil, gas, and NGL production; however, if adverse market conditions or other economic decline affected a substantial number of our customers or joint interest owners, our operations and financial results could be impacted. Refer to Concentration of Credit Risk and Major Customers in Note 1 – Summary of Significant Accounting Policies, in Part II, Item 8 of this report for further discussion of our concentration of credit risk and major customers. Additionally, the inability of our co-owners, some of which have significant non-operated interests in a substantial portion of our oil and gas properties, to pay joint interest billings could negatively impact our cash flows and financial ability to drill and complete current and future wells.

Many of our properties are in areas that may have been partially depleted or drained by offset wells and certain of our wells or future locations may be adversely affected by actions other operators may take when drilling, completing, or operating wells that they own.

Many of our properties are in areas that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests adjoining any of our properties could take actions, such as drilling and completing additional wells, which could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids toward the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. In addition, completion operations and other activities conducted on adjacent or nearby wells could cause production from our wells to be shut in for indefinite periods of time, result in increased lease operating expenses and adversely affect the production and reserves from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators.

Oil and gas drilling, completion, and production activities are subject to numerous risks, including the risk that no commercially producible oil, gas, or NGLs will be found.

The cost of drilling and completing wells is often uncertain, and oil, gas, or NGLs drilling and production activities may be shortened, delayed, or canceled as a result of a variety of factors, many of which are beyond our control. These factors may include, but are not limited to:

• supply chain issues, including cost increases and availability of equipment or materials;
• unexpected adverse drilling or completion conditions;
• title problems;
• disputes with owners or holders of surface interests on or near areas where we operate;
• pressure or geologic irregularities in formations;
• engineering and construction delays;
• equipment failures or accidents;
• hurricanes, tornadoes, flooding, wildfires, seasonal weather, or other adverse weather conditions;
• operational restrictions resulting from seismicity concerns;
• compliance with and changes in federal, state, and local environmental and other governmental regulatory requirements;
• governmental permitting delays; and
• shortages or delays in the availability of or increases in the cost of drilling rigs and crews, fracture stimulation crews and equipment, pipe, chemicals, water, sand, and other supplies.

The wells we drill may not be productive, and we may not recover all or any portion of our investment in such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well if oil, gas, or NGLs are present, or whether they can be produced economically. Drilling activities can result in dry holes or wells that are productive but do not produce sufficient net revenues after operating and other costs to cover drilling and completion costs. Even if sufficient amounts of oil, gas, or NGLs exist, we may damage a potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing a well, which could result in reduced or no production from the well, significant expenditure to repair the well, and/or the loss and abandonment of the well.

Another significant risk inherent in our drilling plans is the need to obtain drilling permits from federal, state, tribal, local, and other governmental authorities. Delays in obtaining regulatory approvals and drilling permits, including delays that jeopardize our ability to realize the potential benefits from leased properties within the applicable lease periods, the failure to obtain a drilling permit for a well, or the receipt of a permit with unreasonable conditions or costs could have a material adverse effect on our ability to explore or develop our properties.

Results in newer resource plays may be more uncertain than results in resource plays that are more developed and have longer established production histories. We, and the industry, generally have less information with respect to the ultimate recoverability of reserves and the production decline rates in newer resource plays than other areas with longer histories of development and production. Drilling and completion techniques that have proven to be successful in other resource plays are being used in the early development of new plays; however, we can provide no assurance of the ultimate success of these drilling and completion techniques.

We may not be able to obtain any options or lease rights in potential drilling locations that we identify. While some expiring leases may contain predetermined extension payments, other expiring leases will require us to negotiate new leases at the time of lease expiration. Further, existing leases which are currently held by production may unexpectedly encounter operational, political, regulatory, or litigation challenges which could result in their termination. It is possible that market conditions at the time of negotiation could require us to agree to new leases on less favorable terms to us than the terms of the expired leases or cause us to lose the leases entirely. Unless production is established within the spacing units covering undeveloped acres on which our drilling locations are identified, the leases for such acreage will expire, and we will lose our right to develop the related properties. Our total net acreage as of February 2, 2026, that is scheduled to expire over the next three years, represents approximately 30 percent of our total net undeveloped acreage as of that date. Although we have identified numerous potential drilling locations, we may not be able to economically drill for and produce oil, gas, or NGLs from all of them, and our actual drilling activities may materially differ from those presently identified, which could adversely affect our financial condition, results of operations and operating cash flow.

The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced.

The development of our proved undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate or that may be available to us. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could require us to reclassify our proved reserves as unproved reserves.

Our management has identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. Our ability to drill and develop these locations is subject to a number of uncertainties, including uncertainty in the level of reserves; the availability of capital to us and other participants; seasonal conditions; regulatory approvals; activist intervention; crude oil, natural gas, and NGL prices; availability of permits; costs; and well performance. 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 or natural gas from these or any other potential drilling locations. Pursuant to existing SEC rules and guidance, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking, and we may therefore be required to downgrade to probable or possible categories any proved undeveloped reserves that are not developed within this five-year time frame. These limitations may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program.

Our ability to produce oil, gas, and NGLs economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling and/or completions operations or are unable to dispose of or recycle the water we produce at a reasonable cost and in accordance with applicable environmental rules and regulations.

The hydraulic fracturing process on which we and others in our industry depend to complete wells that will produce commercial quantities of oil, gas, and NGLs require the use and disposal of significant quantities of water. Our inability to secure sufficient amounts of water, or to dispose of, or recycle, the water produced from our wells, could adversely impact our operations. Moreover, the imposition of new federal, state, or local environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of wastes, including, but not limited to, produced water, drilling fluids, and other wastes associated with the exploration, development, or production of oil, gas, and NGLs.

Compliance with environmental regulations, oil and gas leases, surface use agreements, and permit requirements governing the withdrawal, storage, and use of surface water and disposal or recycling of produced water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions, or termination of our operations. The extent of these impacts cannot be predicted, but they could have an adverse effect on our operations and financial condition.

If we are unable to replace reserves and increase our reserve life index, we will not be able to sustain production.

Our future operations depend on our ability to find or acquire and develop oil, gas, and NGL reserves that are economically producible. Our properties produce oil, gas, and NGLs at a declining rate over time. In order to maintain current production rates, we must locate or acquire and develop new oil, gas, and NGL reserves to replace those being depleted by production.

For future acquisitions we may complete, a successful outcome for our business will depend on a number of factors, many of which are beyond our control. These factors include the purchase price and transaction costs for the acquisition; future oil, gas, and NGL prices; the ability to reasonably estimate the recoverable volumes of reserves, rates of future production and future net revenues attainable from reserves; future operating and capital costs; results of future exploration, exploitation, and development activities on the acquired properties; future abandonment and possible future environmental or other liabilities; ability to attract and retain employees and contractors; success in transitioning ownership of the acquired properties; relationships with local regulatory authorities, landowners, and communities; and the ability to review and confirm the seller’s title to the subject properties. There are numerous uncertainties inherent in estimating these variables with respect to prospective acquisition targets. Actual results may vary substantially from those assumed in the estimates. Our customary review in connection with acquisitions will not necessarily reveal, or allow us to fully assess, all existing or potential problems and deficiencies with such properties. We do not inspect every well, and even when we inspect a well, we may not discover structural, subsurface, or environmental problems that may exist or arise. We may not be entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities, and we may not be able to obtain representation and warranty or similar insurance products on terms or at a price that efficiently manages the perceived or actual risk profile. We often acquire interests in properties on an “as-is” basis with limited remedies for breaches of representations and warranties.

Significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties. For example, newly acquired properties may have substantially different operating and geological characteristics or be in different geographic locations than our existing properties.

To the extent that acquired properties are substantially different than our existing properties, our ability to efficiently realize the expected economic benefits of such transactions may be limited. If we are unable to replace any significant volume declines with additional volumes from other sources, our results of operations and cash flows could be materially and adversely impacted.

The results of our operations are subject to drilling and completion technique risks, and results may not meet our expectations for reserves or production. As a result, we may incur material write-downs, and the value of our undeveloped acreage could decline if drilling and completion results are unsuccessful.

Many of our operations involve utilizing the latest drilling and completion techniques as developed by us, other operators and our service providers in order to maximize production and ultimate recoveries and therefore generate the highest possible returns. Risks we face while drilling include, but are not limited to, landing our well bore outside the desired drilling zone, deviating from the desired drilling zone while drilling horizontally through the formation, the inability to run our casing the entire length of the well bore, and the inability to run tools and recover equipment consistently through the horizontal well bore. Risks we face while completing our wells include, but are not limited to, the inability to fracture stimulate the planned number of stages, the inability to run tools and other equipment the entire length of the well bore during completion operations, the inability to recover such tools and other equipment, and the inability to successfully clean out the well bore after completion of the final fracture stimulation.

In addition, exploration and drilling technologies we currently use or implement in the future may become obsolete. If we are unable to maintain technological advancements consistent with industry standards, our operations and financial condition may be adversely affected. We cannot be certain we will be able to implement exploration and drilling technologies on a timely basis or at a cost that is acceptable to us.

Ultimately, the success of exploration, drilling, and completion technologies and techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, limited access to gathering systems and takeaway capacity, and/or prices for oil, gas, and NGLs decline, then the return on our investment for a particular project may not be as attractive as we anticipated and we could incur material write-downs of oil and gas properties and the value of our undeveloped acreage could decline in the future.

The actual quantities and present value of our proved oil, gas, and NGL reserves may be less than we have estimated, and the cost to develop our reserves may be more than we have estimated.

This report and certain of our other SEC filings contain estimates of our proved oil, gas, and NGL reserves and the present value of estimated future net revenues from those reserves. The process of estimating reserves is complex and estimates are based on various assumptions, including geological and geophysical characteristics; future oil, gas, and NGL prices; drilling, completion and other capital expenditures; gathering and transportation costs; operating expenses; effects of governmental regulation; taxes; timing of operations; and availability of funds. Therefore, these estimates are inherently imprecise. In addition, our reserve estimates for properties with limited production history may be less reliable than estimates for properties with lengthy production histories.

Actual future production; prices for oil, gas, and NGLs; revenues; production taxes; development expenditures; operating expenses; and quantities of producible oil, gas, and NGL reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities of, and present value related to proved reserves disclosed by us, and the actual quantities and present value may be significantly less than we have previously estimated. Our properties may also be susceptible to hydrocarbon drainage from production on adjacent properties, which we may not control.

As of December 31, 2025, 39 percent, or 260.7 MMBOE, of our estimated proved reserves were proved undeveloped. In order to develop our net proved undeveloped reserves, as of December 31, 2025, we estimate approximately $2.6 billion of capital expenditures would be required. Although we have estimated our proved reserves and the costs associated with these proved reserves in accordance with industry standards, estimated costs may not be accurate, development may not occur as scheduled, and actual results may not occur as estimated.

One should not assume that the standardized measure of discounted future net cash flows or PV-10 included in this report represent the current market value of our estimated proved oil, gas, and NGL reserves. Management has based the estimated discounted future net cash flows from proved reserves on price and cost assumptions required by the SEC, whereas actual future prices and costs may be materially higher or lower. Refer to Reserves in Part I, Items 1 and 2 of this report for discussion regarding the prices used in estimating the present value of our proved reserves as of December 31, 2025, and to the caption Oil and Gas Reserve Quantities under Critical Accounting Estimates in Part II, Item 7 of this report for additional information.

The timing of production from oil and gas properties and of related expenses affects the timing of actual future net cash flows from proved reserves, and thus their actual present value. Our actual future net cash flows could be less than the estimated future net cash flows for purposes of computing PV-10. In addition, the 10 percent discount factor required by the SEC to calculate PV-10 for reporting purposes is not necessarily the most appropriate discount factor given actual interest rates, costs of capital, and other risks to which our business and the oil and gas industry in general are subject.

Our disposition activities may be subject to factors beyond our control, and in certain cases we may retain unforeseen liabilities for certain matters.

We periodically sell non-core assets in order to increase capital resources available for core assets and other purposes and to create organizational and operational efficiencies. We also occasionally sell interests in core assets for the purpose of accelerating the development and increasing efficiencies in other core assets. Various factors could materially affect our ability to dispose of such assets, including the approvals of governmental agencies or third parties, the availability of purchaser financing and purchasers willing to acquire the assets on terms we deem acceptable, or other matters or uncertainties that could impact such dispositions, including whether transactions could be consummated or completed in the form or timing and for the value that we anticipate. At times, we may be required to retain certain liabilities or agree to indemnify buyers in connection with such asset sales, or we may have to rely on third parties to perpetuate leases we intend to develop in the future. The magnitude of such retained liabilities or of the indemnification obligations may be difficult to quantify at the time of the transaction and ultimately could be material.

Title to the properties in which we have an interest may be impaired by title defects.

We generally rely on title due diligence reports when acquiring oil and gas leasehold interests, and we obtain title opinions prior to commencing initial drilling operations on the properties we operate. Title to the properties in which we have an interest may be impaired by title defects that may not be identified in the due diligence title reports or title opinions we obtain, or such defects may not be cured following identification. A material title defect can reduce the value of a property or render it worthless, thus adversely affecting our oil and gas reserves, financial condition, results of operations, and operating cash flow, and may also impair the value of or render adjacent properties uneconomic to develop. Undeveloped acreage has greater risk of title defects than developed acreage and title insurance is not generally available for oil and gas properties.

Our business could be negatively impacted by security threats, including cybersecurity threats, terrorism, armed conflict, and other disruptions.

As an oil, gas, and NGL producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the safety of our employees; threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts, including armed attacks on shipping channels. Although we utilize various procedures and controls to monitor these threats and mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel, or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations, or cash flows. Further, our insurance may not protect against such occurrences.

The threat of terrorism and the impact of military and other actions have caused instability in world financial markets and could lead to increased volatility in prices for oil, gas, and NGLs, all of which could adversely affect the markets for our production. Energy assets might be specific targets of terrorist attacks. Depending on their occurrence and ultimate magnitude, terrorist threats or attacks could have a material adverse effect on our business, financial condition, or results of operations.

We are subject to operating and environmental risks and hazards that could result in substantial losses or liabilities that may not be fully insured.

Oil and gas operations are subject to many risks, including human error and accidents, that could cause personal injury, death, and property damage. These include well blowouts, craterings, explosions, and uncontrollable flows of oil, gas, NGLs, and well fluids. Risks also include releases or spills of completion fluids, spills or releases from facilities and equipment used to deliver or store these materials, and spills or releases of brine or other produced or flowback water. In addition, subsurface conditions may prevent us from stimulating the planned number of completion stages, accessing the entirety of the wellbore with our tools during completion, or removing materials from the wellbore to allow production to begin. Fires, adverse weather such as hurricanes or tornadoes, freezing conditions, wildfires, floods, droughts, formations with abnormal pressures, pipeline ruptures or spills, train derailments, pollution, seismic events, releases of toxic gas such as hydrogen sulfide, and other environmental risks and hazards may impact operations. If any of these types of events occur, we could sustain substantial losses.

In response to increased seismic activity in the Permian Basin in Texas, the Railroad Commission of Texas (“RRC”) has developed a seismic review process for injection wells near qualifying seismic activity. As a result of the seismic review process, the RRC may declare an area to be a Seismic Response Area (“SRA”) and may adjust limits for injection rates and pressure, require bottom-hole pressure tests, or modify, suspend, or terminate injection well permits within the SRA. If an SRA is declared within an area of our operations, our ability to dispose of produced water may be adversely affected, and as a result, we may be forced to shut-in injection wells or find alternate produced water disposal options which could affect production and therefore oil, gas, and NGL production revenue, and could cause us to incur additional capital or operating expense. The declaration of SRAs has required us to adjust the areas where we seek permits for injection wells to areas or formations that are less desirable, and could further restrict the areas where we are able to obtain and operate under such permits without restrictions. Additionally, we could be subject to third-party claims and liability based on allegations that our operations caused or contributed to seismic events that resulted in damage to property or personal injury, or that are otherwise related to seismic events.

If we experience any of the problems with well stimulation, completion activities, and disposal referenced above, our ability to explore for and produce oil, gas, and NGLs may be adversely affected. We could incur substantial losses or otherwise fail to realize reserves in particular formations resulting from the need to shut down, abandon, or relocate drilling operations, the need to modify drill sites to lessen the risk of spills or releases, the need to investigate and/or remediate any spills, releases or ground water contamination that might have occurred, and the need to suspend our operations.

There is an inherent risk of incurring significant environmental costs and liabilities in our operations due to our current and past generation, handling, and disposal of materials, including produced water, solid and hazardous wastes, and petroleum hydrocarbons. We may incur joint and several, and/or strict liability under applicable United States federal and state environmental laws in connection with releases of hazardous substances at, on, under, or from our leased or owned properties, some of which have been used for oil and gas exploration and production activities for a number of years, often by third-parties not under our control. For our outside-operated properties, we are dependent on the operator for operational and regulatory compliance and could be subject to liabilities in the event of non-compliance. These properties and the wastes disposed thereon or therefrom could be subject to stringent and costly investigatory or remedial requirements under applicable laws, some of which are strict liability laws without regard to fault or the legality of the original conduct, including CERCLA , RCRA, the Clean Water Act, the CAA, the OPA, and analogous state laws. Under various federal, state, and local regulations, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), to perform natural resource mitigation or restoration practices, or to perform remedial plugging or closure operations to prevent future contamination. In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury or property damage, including induced seismicity damage, allegedly caused by the release of petroleum hydrocarbons or other hazardous substances into the environment. As a result, we may incur substantial liabilities to third-parties or governmental entities, which could reduce or eliminate funds available for exploration, development, or acquisitions, or cause us to incur losses.

We maintain insurance against some, but not all, of these potential risks and losses. We have significant but limited coverage for sudden environmental damage. We do not believe that insurance coverage for the full potential liability that could be caused by environmental damage that occurs gradually over time is appropriate for us at this time given the nature of our operations and the nature and cost of such coverage. Further, we may elect not to obtain insurance coverage under circumstances where we believe that the cost of available insurance is excessive relative to the risks to which we are subject. Accordingly, we may be subject to liability or may lose substantial assets in the event of environmental or other damages. If a significant accident or other event occurs and is not fully covered by insurance, we could suffer an uninsured material loss.

The impact of seasonal and extreme weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Our operations have been in the past, and may continue to be, adversely affected by the impact of seasonal and extreme weather conditions. Additionally, lease stipulations designed to protect various wildlife or plant species may adversely impact our operations. In certain areas, drilling and other oil and gas activities can only be conducted during limited times of the year. This limits our ability to operate in those areas and can intensify competition during those times for drilling rigs and completion equipment, oil field equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.

Risks Related to Litigation and Government Regulations

In the future, we may be subject to claims, litigation, administrative proceedings and regulatory actions that may not be resolved in our favor.

In the future, we may be subject to claims, litigation, administrative proceedings and regulatory actions. The outcome of these matters may be difficult to assess or quantify, and there cannot be any assurance that such matters will be resolved in our favor. If we are unable to resolve such matters favorably, we or our directors, officers or employees may become involved in legal proceedings that could result in an onerous or unfavorable decision, including fines, sanctions, monetary damages or the inability to engage in certain operations or transactions. The defense of such matters may also be costly, time consuming and could divert the attention of management and key personnel away from our operations. We may also be subject to adverse publicity associated with such matters, regardless of whether such allegations are valid or whether we are ultimately found liable. As a result, such matters could have a material adverse effect on our business, reputation, financial condition, results of operations or liquidity.

Our operations are subject to complex laws and regulations, including environmental regulations, which result in substantial costs and other risks.

Federal, state, tribal, and local authorities extensively regulate the oil and gas industry. Legislation and regulations affecting the industry are under constant review for amendment or expansion, and subject to constantly changing or differing interpretations, raising the possibility of changes that may become more stringent and, as a result, may affect, among other things, the pricing, or marketing of oil, gas, and NGL production. Non-compliance with statutes and regulations and more vigorous enforcement of such statutes and regulations by regulatory agencies may lead to increased operational and compliance costs, substantial administrative penalties, civil penalties, and criminal prosecution. These may include the assessment of natural resource damages and the imposition of significant investigatory and remedial obligations, potentially resulting in the suspension or termination of our operations. The overall regulatory burden on the industry increases the cost to place, design, drill, complete, install, operate, and abandon wells and related facilities and, in turn, decreases profitability.

Governmental authorities regulate various aspects of drilling for and the production of oil, gas, and NGLs, including the permit and bonding requirements of drilling wells, the spacing of wells, the unitization or pooling of interests in oil and gas properties, rights-of-way and easements, disposal of produced water, environmental matters, occupational health and safety, the sharing of markets, production limitations, plugging, abandonment, restoration standards, and oil and gas operations. Public interest in environmental protection has increased over time, and environmental and other public interest organizations have opposed, with some success, certain projects. Under certain circumstances, regulatory authorities may deny a proposed permit or right-of-way grant or impose conditions of approval to mitigate potential environmental impacts, which could, in either case, negatively affect our ability to explore or develop certain properties. Any such delay, suspension, or termination could have a material adverse effect on our operations.

Our operations are also subject to complex and constantly changing environmental laws and regulations adopted by federal, state, tribal, and local governmental authorities in jurisdictions where we are engaged in exploration or production operations. New laws or regulations, or changes to current requirements, including, among other things, air quality and GHG emissions standards and the designation of previously unprotected wildlife or plant species as threatened or endangered in areas we operate in, could result in material costs or claims with respect to properties we own or have owned or limitations on exploration and production activities in certain locations. We will continue to be subject to uncertainty associated with new regulatory interpretations and inconsistent interpretations between state and federal agencies. Under existing or future environmental laws and regulations, we could incur significant liability, including joint and several, strict liability under federal, state, tribal, and local environmental laws for emissions and for discharges of oil, gas, and NGLs or other pollutants into the air, soil, surface water, or groundwater as described in Government Regulations in Part I, Items 1 and 2 of this report. Existing environmental laws or regulations, as currently interpreted or enforced, or as they may be interpreted, enforced, or altered in the future, may have a material adverse effect on us.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is a common practice in the oil and gas industry used to stimulate the production of oil, gas, and NGLs from dense subsurface rock formations. We routinely apply hydraulic fracturing techniques to many of our oil and gas properties, including our unconventional resource plays. Hydraulic fracturing involves injecting water, sand, and certain chemicals under pressure to fracture the hydrocarbon-bearing rock formation to allow the flow of hydrocarbons into the wellbore. The process is typically regulated by state oil and gas commissions. However, the EPA and other federal agencies have asserted federal regulatory authority over certain aspects of hydraulic fracturing activities, as outlined below.

The EPA has authority to regulate underground injections that contain diesel in the fluid system under the Safe Drinking Water Act. The EPA also has authority under the Clean Water Act to regulate wastewater generated by unconventional oil and gas operations during the hydraulic fracturing process and discharged to publicly-owned wastewater treatment facilities. Although the Trump administration has signaled a desire for fewer environmental regulations, if the EPA were to implement further regulations of hydraulic fracturing, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and could even be prohibited from drilling and/or completing certain wells.

A slowdown in federal regulation of hydraulic fracturing could encourage states, tribes, or localities to implement more or stricter regulations. Certain states have adopted or may adopt, regulations that could impose more stringent permitting, public disclosure, waste disposal, and well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether. The regulatory burden of each state’s respective laws varies. For example, some counties in Colorado have amended their land use regulations to impose new siting and other requirements on oil and gas development, while other local governments have entered memoranda of agreement with oil and gas producers to accomplish the same or similar objectives. Under current Colorado law, local governments can regulate both facility siting and the surface impacts associated with oil and gas development, and local government regulations may be more protective or stricter than state requirements. Texas, Utah, and Colorado require disclosure of chemical ingredients used in hydraulic fracturing fluids. State initiatives relevant to fracturing are often changing and priorities across states differ. On May 14, 2025, the New Mexico Water Quality Control Commission adopted a rule that prohibits the discharge of produced water to New Mexico’s ground and surface waters. Also in 2025, New Mexico lawmakers proposed a bill that would ban PFAS in fracking operations. In 2015, Texas Governor Greg Abbott signed a law which preempts municipal and county bans or limits on oil and gas operations, including drilling and hydraulic fracturing, and confirms that regulation of those activities is under the state of Texas’ exclusive jurisdiction, while still allowing limited, commercially reasonable, surface-level regulation by local governments.

In addition to state laws, local land use restrictions, such as city ordinances or memoranda of understanding, may restrict, or prohibit the performance of drilling in general and/or hydraulic fracturing in particular. Recently, municipalities have passed or proposed zoning ordinances that ban or strictly regulate hydraulic fracturing within city boundaries, setting the stage for challenges by state regulators and third-parties. Similar events and processes are playing out in several cities, counties, and townships across the United States. In the event that tribal, state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct, operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and could even be prohibited from drilling and/or completing certain wells.

In the recent past, several federal governmental agencies were actively involved in studies or reviews that focus on environmental aspects and impacts of hydraulic fracturing practices. Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Disclosure of chemicals used in the hydraulic fracturing process could make it easier for third parties opposing such activities to pursue legal proceedings against producers and service providers based on allegations that specific chemicals used in the fracturing process could adversely affect human health or the environment, including groundwater. Litigation resulting in financial compensation for damages linked to hydraulic fracturing, including damages from induced seismicity, could spur future litigation and bring increased attention to the practice of hydraulic fracturing. Judicial decisions could also lead to increased regulation, permitting requirements, enforcement actions, and penalties. Additional legislation or regulation could also lead to operational delays or restrictions or increased costs in the exploration for, and production of, oil, gas, and NGLs, including from the development of shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of additional state or local laws, or the implementation of new regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells, or an increase in compliance costs and delays, which could adversely affect our financial position, results of operations, and cash flows.

We will continue to be subject to uncertainty associated with new regulatory suspensions, revisions or rescissions and inconsistent state and federal regulatory mandates that could adversely affect our production.

Federal and state regulatory initiatives relating to air quality and greenhouse gas emissions could result in increased costs and additional operating restrictions or delays.

There has been a trend toward increased air quality and GHG regulation and reduced emissions from oil and gas sources. These regulations include the New Source Performance Standards (“NSPS”), the National Emission Standards for Hazardous Air Pollutants programs, and ozone standards set under the National Ambient Air Quality Standards (“NAAQS”), among others. Notwithstanding any reversal of this trend federally by the Trump administration, the adoption of additional state or local laws could adversely affect our financial position, results of operations, and cash flows. Refer to the Environmental section in Part II, Item 7 of this report for additional information about the regulation of air emissions, particularly methane emissions from the oil and gas sector.

Additionally, certain areas where we currently operate (such as the Uinta Basin in Utah) or may operate in the future are or may be designated as ozone non-attainment areas, and are subject to stricter emissions regulations and control measures. These increased regulations and controls, which may increase over time, result in certain restrictions or limitations to our operations, increase our costs and may cause delays, which could affect our financial position, results of operations, and cash flows.

Legislative and regulatory initiatives and litigation related to global warming and climate change could have an adverse effect on our operations and the demand for oil, gas, and NGLs, and could result in significant litigation, capital, and related expenses.

While courts have generally declined to assign direct liability for climate change to large sources of GHG emissions, some have required increased scrutiny of such emissions by federal agencies and permitting authorities. There is a continuing risk of claims being filed against companies that have significant GHG emissions, and new claims for damages and increased government scrutiny, especially from state and local governments, will likely continue.

The United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs, and the majority of states have already taken measures to reduce emissions of GHGs through various measures, including, primarily through the planned development of GHG emission inventories, participation in and/or regional GHG “cap and trade” programs, and/or transition to clean energy. The focus on legislating and/or regulating methane could result in increased scrutiny for sources emitting high levels of methane, including during permitting processes, analysis, regulation and reduction of methane emissions as a requirement for project approval, and actions taken by one agency for a specific industry establishing precedents for other agencies and industry sectors. In 2021, the EPA proposed requirements for methane emission reductions from existing oil and gas equipment. In 2022, the EPA released a supplemental proposal expanding its initial requirements as well as updating requirements, and in 2023, proposed updates to GHG reporting requirements. In 2024, the EPA announced a final rule that facilitates the implementation of Congress’s directive in the Inflation Reduction Act of 2022 (“IRA”) to collect a waste emissions charge, but on March 14, 2025, President Trump signed a joint resolution of disapproval under the Congressional Review Act, voiding the EPA’s final rule on methane waste emission.

Scientists have predicted that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods, and other climatic events. If such effects were to occur, our operations could be adversely affected. Potential adverse effects could include disruption of our drilling, completion, and production activities, including, for example, damages to our facilities from flooding or increases in our costs of operation or reductions in the efficiency of our operations. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies, or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses, or costs that may result from potential physical effects of climate change. Federal regulations or policy changes regarding climate change preparation requirements could also impact our costs and planning requirements because emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes.

Requirements to reduce gas flaring could have an adverse effect on our operations.

In the areas where we have significant operations, there have been, and could be, in the future, constraints in gas takeaway capacity which has historically led to increased gas flaring. We are subject to laws established by state and other regulatory agencies that restrict the duration and amount of natural gas that can be legally flared. These laws and regulations, including potential future regulations that may impose further restrictions on flaring, could limit the amount of oil and gas we can produce from our wells or may limit the number of wells or the locations that we can drill. Any future laws or commitments may increase our operational costs, or restrict our production, which could have a material adverse effect on our financial condition, results of operations and cash flows.

Senate Bill 181’s requirement, which applies to our Colorado operations, that we own or control more than 45 percent of the working or mineral interest in order to statutorily pool our applicable interest may make it much more difficult for us to develop such interests, which could have a material adverse effect on our business, financial condition, and results of operations.

With respect to our operations in the DJ Basin in Colorado, in some cases, we do not own more than 45 percent working interest or mineral interest in a prospective area of development, which is now required to statutorily pool our applicable working or mineral interests. In such cases, unless we can obtain the consent of more than 45 percent of all applicable working or mineral interest owners (who can be located through reasonable diligence) to pursue statutory pooling, or achieve a voluntary pooling agreement with 100 percent of the applicable interest owners, we may be prohibited from developing the resources in that area or having them be developed by other operators.

Risks Related to Debt, Liquidity, and Access to Capital

Commodity price declines could result in a decrease in the amount available to us under our Credit Agreement.

As of December 31, 2025, the borrowing base and aggregate revolving lender commitments under our Credit Agreement were $3.0 billion and $2.0 billion, respectively. The borrowing base is subject to semi-annual redetermination based on the bank group’s assessment of the value of our proved reserves, which in turn is impacted by oil, gas, and NGL prices. On January 30, 2026, in connection with the closing of our acquisition of Civitas, we entered into a Fourth Amendment to our Credit Agreement, which increased the borrowing base to $5.0 billion, increased aggregate revolving lender commitments to $2.5 billion, and extended the scheduled maturity date to January 30, 2031. The next borrowing base redetermination date is scheduled to occur on April 1, 2026. Divestitures of properties, incurrence of additional debt, or declines in commodity prices could limit our borrowing base and reduce the amount we can borrow under our Credit Agreement, which could in turn impact, among other things, our ability to service our debt, fund our capital program, or compete for the acquisition of new properties.

Negative public perception and investor sentiment regarding our business and the oil and gas industry as a whole could adversely affect our business, operations, and our ability to attract capital.

Certain segments of the public as a whole, and the investment community in particular, have developed negative sentiment toward our industry. In recent years, equity returns in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. In addition, some investors, including investment management firms, sovereign wealth and pension funds, university endowments and other investment advisors, have adopted policies to discontinue or reduce their investments in the oil and gas sector based on social and environmental considerations. Furthermore, other influential stakeholders have pressured commercial and investment banks and other service providers to reduce or cease financing of oil and gas companies and related infrastructure projects.

Such developments could result in downward pressure on the stock prices of oil and gas companies, including ours. This may also potentially result in a reduction of available capital funding for potential development projects, impacting our future financial results.

Substantial capital is required to develop and replace our reserves.

We must make substantial capital expenditures to find, acquire, develop, and produce oil, gas, and NGL reserves. Future cash flows and the availability of financing are subject to a number of factors, such as the level of production from existing wells, prices received for oil, gas, and NGL sales, our success in locating, acquiring, and developing new reserves, and the orderly functioning of credit and capital markets. If our cash flows from operations are less than expected, we may reduce our planned capital expenditures. If we cannot access sufficient liquidity under our Credit Agreement, or raise additional funds through debt or equity financing or the sale of assets, our ability to execute development plans, replace our reserves, maintain our acreage, or maintain production levels could be greatly limited.

Downgrades in our credit ratings by various credit rating agencies could impact our access to capital and have a material adverse effect on our business and financial condition.

Downgrades of our credit ratings could have material adverse consequences on our business and future prospects and could:

• limit our ability to access capital markets, including for the purpose of refinancing our existing debt;
• cause us to refinance or issue debt with less favorable terms and conditions, which may restrict, among other things, our ability to make any dividend payments or repurchase shares;
• negatively impact lenders’ willingness to transact business with us, which could impact our ability to obtain favorable terms and conditions under our Credit Agreement;
• negatively impact current and prospective customers’ willingness to transact business with us;
• impose additional insurance, guarantee, bonding, and collateral requirements;
• limit our access to bank and third-party guarantees, surety bonds, and letters of credit; and
• cause our suppliers and financial institutions to lower or eliminate the level of credit provided through payment terms or intraday funding when dealing with us, thereby increasing the need for higher levels of cash on hand, which would decrease our ability to repay outstanding indebtedness.

We cannot provide assurance that any of our current credit ratings will remain in effect for any given period of time or that a credit rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances warrant.

Our commodity derivative contract activities may result in financial losses or may limit the prices we receive for oil, gas, and NGL sales.

To mitigate a portion of the exposure to potentially adverse market changes in oil, gas, and NGL prices and the associated impact on cash flows, we regularly enter into commodity derivative contracts. Our commodity derivative contracts typically include price swaps and collar arrangements for oil, gas, and NGLs. These activities may expose us to the risk of financial loss in certain circumstances, including instances in which:

• our production is less than expected;
• one or more counterparties to our commodity derivative contracts default on their contractual obligations; or
• there is a widening of price differentials between delivery points for our production and the delivery point assumed in the commodity derivative contract arrangement.

In addition, commodity derivative contracts may limit the prices we receive for our oil, gas, and NGL sales if oil, gas, or NGL prices rise substantially over the price established by the commodity derivative contract. Refer to Note 7 – Derivative Financial Instruments in Part II, Item 8 of this report for additional detail regarding our commodity derivative contracts.

The amount of our debt may limit our ability to obtain financing for acquisitions, make us more vulnerable to adverse economic conditions, and make it more difficult for us to make payments on our debt.

As of December 31, 2025, we had $2.7 billion of aggregate principal amount outstanding of Senior Notes with maturities through 2032, as further discussed and defined in Note 5 – Long-Term Debt in Part II, Item 8 of this report. We had no outstanding balance on our revolving credit facility and we had $2.0 billion of available borrowing capacity under our Credit Agreement as of December 31, 2025. Our long-term debt represented 36 percent of our total book capitalization as of December 31, 2025.

In connection with the Civitas Merger on January 30, 2026, we assumed approximately $4.9 billion in aggregate principal amount of additional senior notes with maturities through 2033. Additionally, in connection with the closing of the Civitas Merger, the Company and its lenders entered into the Fourth Amendment to the Credit Agreement, which increased the aggregate revolving lender commitments available under our Credit Agreement to $2.5 billion and increased the borrowing base to $5.0 billion. As of February 2, 2026, we had no outstanding balance on our revolving credit facility and we had $2.5 billion of available borrowing capacity under our Credit Agreement. Refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional detail.

The amounts of our indebtedness could have important consequences for our operations, including:

• making it more difficult for us to obtain additional financing in the future for our operations and potential acquisitions, working capital requirements, capital expenditures, debt service, or other general corporate requirements;
• requiring us to dedicate a substantial portion of our cash flows from operations to the repayment of our debt and the service of interest costs associated with our debt, rather than to capital investments;
• limiting our operating flexibility due to financial and other restrictive covenants, including restrictions on incurring additional debt, making acquisitions, and paying dividends or repurchasing shares of common stock;
• placing us at a competitive disadvantage compared to our competitors with less debt; and
• making us more vulnerable in the event of adverse economic or industry conditions or a downturn in our business.

If our business does not generate sufficient cash flow from operations or future sufficient borrowings are not available to us under our Credit Agreement or from other sources, we might not be able to service our debt, issue additional debt, or fund our planned capital expenditures and other liquidity needs. If we are unable to service our debt due to inadequate liquidity or otherwise, we may have to delay or cancel acquisitions, defer capital expenditures, sell equity securities, divest assets, and/or restructure or refinance our debt. We might not be able to sell our equity, sell our assets, or restructure or refinance our debt on a timely basis or on satisfactory terms or at all. In addition, the terms of our existing or future debt agreements, including our Credit Agreement and any future credit agreements, may prohibit us from pursuing any of these alternatives.

As discussed above, our Credit Agreement is subject to periodic borrowing base redeterminations. At times when we have an outstanding balance, we could be forced to repay a portion of our bank borrowings in the event of a downward redetermination of our borrowing base, and we may not have sufficient funds to make such repayment at that time. If we do not have sufficient funds and are otherwise unable to negotiate adjustments to our borrowing base or arrange new financing, we may be forced to sell significant assets.

The agreements governing our debt arrangements contain various covenants that limit our discretion in the operation of our business, could prohibit us from engaging in transactions we believe to be beneficial, and could lead to the accelerated repayment of our debt.

Our debt agreements, including our Credit Agreement and the indentures governing our Senior Notes, contain restrictive covenants that limit our ability to engage in activities that may be in our long-term best interests, including restrictions on incurring debt, issuing dividends, repurchasing common stock, selling assets, creating liens, entering into transactions with affiliates, and merging, consolidating, or selling our assets. Our ability to borrow under our Credit Agreement is subject to compliance with certain financial and non-financial covenants, as outlined in the Credit Agreement. Refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion. These restrictions on our ability to operate our business could significantly harm us by, among other things, limiting our ability to take advantage of financings, mergers and acquisitions, and other corporate opportunities.

Our failure to comply with these covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all or a portion of our indebtedness. We do not have sufficient working capital to satisfy our debt obligations in the event of an acceleration of all or a significant portion of our outstanding indebtedness.

Risks Related to Corporate Governance and Ownership of Public Equity Securities

Our certificate of incorporation and by-laws have provisions that discourage corporate takeovers and could prevent stockholders from receiving a takeover premium on their investment, which could adversely affect the price of our common stock.

Delaware corporate law and our certificate of incorporation and by-laws contain provisions that may have the effect of delaying or preventing a change of control of us or our management. These provisions, among other things, provide for non-cumulative voting in the election of members of the Board of Directors and impose procedural requirements on stockholders who wish to make nominations for the election of directors or propose other actions at stockholder meetings. These provisions, alone or in combination with each other, may discourage transactions involving actual or potential changes of control, including transactions that otherwise could involve payment of a premium over prevailing market prices to stockholders for their common stock. As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, which may limit the price investors are willing to pay in the future for shares of our common stock.

In addition, stockholder activism in our industry has been present in recent years, and if investors seek to exert influence or affect changes to our business that we do not believe are in the long-term best interests of our stockholders, such actions could adversely impact our business by, among other things, distracting our Board of Directors and management team, causing us to incur unexpected advisory fees and other related costs, impacting execution of our strategic objectives, and creating unnecessary market uncertainty.

The price of our common stock may fluctuate significantly, which may result in losses for investors.

From January 1, 2025, to February 2, 2026, the intraday trading prices per share of our common stock as reported by the New York Stock Exchange ranged from a low of $17.45 per share in January 2026 to a high of $44.95 per share in January 2025. We expect our stock to continue to be subject to fluctuations resulting from a variety of factors, including factors beyond our control. These factors include, in addition to the other risk factors set forth herein, the following:

• changes in oil, gas, or NGL price;
• changes in the outlook for regional, national, or global commodity supply and demand;
• variations in drilling, recompletion, and operating activity;
• inflation;
• changes in financial estimates by securities analysts;
• changes in market valuations of comparable companies;
• additions or departures of key personnel;
• increased volatility due to the impacts of algorithmic trading practices;
• future sales of our common stock;
• negative public perception and investor sentiment regarding our business and the oil and gas industry as a whole;
• changes in the national and global economic outlook, including potential impacts from trade agreements or tariffs; and
• international trade relationships, potentially including the effects of trade restrictions or tariffs affecting the raw materials we utilize and the commodities we produce in our business.

We may not meet the expectations of our stockholders and/or of securities analysts at some time in the future, and our stock price could decline as a result.

We may not always pay dividends on our common stock or repurchase common stock under our Stock Repurchase Program.

Payment of future dividends remains at the discretion of our Board of Directors, and common stock repurchases under our Stock Repurchase Program remain at the discretion of our Board of Directors and certain authorized officers of the Company. Decisions regarding the payment of dividends and the repurchase of common stock will continue to depend on our earnings, capital requirements, financial condition, general market and economic conditions, applicable legal requirements, the market price of our common stock, and other factors. The payment of dividends and the repurchase of our common stock are each subject to covenants in our Credit Agreement and in the indentures governing our Senior Notes that could limit our ability to make certain restricted payments including dividends and common stock repurchases. Our Board of Directors may determine in the future to reduce the current annual dividend rate or discontinue the payment of dividends altogether. The value of shares authorized for repurchase by the Board of Directors does not require us to repurchase such shares or guarantee that such shares will be repurchased, and the Stock Repurchase Program may be suspended, modified, or discontinued at any time without prior notice. No assurance can be given that any particular number or dollar value of our shares will be repurchased. Refer to Purchases of Equity Securities by Issuer and Affiliated Purchasers in Part II, Item 5 of this report for discussion and definition of the Stock Repurchase Program.

Governance

Our Board of Directors, with assistance from the Audit Committee, oversees the Company’s enterprise risk management process, including with respect to relevant IT matters affecting the Company and management of risks arising from cybersecurity threats. Our Board of Directors has delegated the primary responsibility to oversee relevant IT matters affecting the Company, including cybersecurity risks and mitigations strategies, to the Audit Committee. The Audit Committee receives cybersecurity reports and regular updates from our Vice President and Chief Information Officer and our Director of Cybersecurity Risk and Business Continuity (“IT Management”), which includes, among other information, the steps management has taken and the specific guidelines and policies that have been established to monitor, control, mitigate and report exposure to cybersecurity risk. The Audit Committee regularly reports to the Board of Directors on relevant IT matters affecting the Company, including cybersecurity risks and mitigation strategies.

IT Management is responsible for assessing and managing cybersecurity risks and leads a team of specialized technologists entrusted with ensuring the functionality, continuity, and security of our technology infrastructure and data. This team regularly reports to IT Management, and IT Management regularly reviews risk management measures implemented by the Company to identify and mitigate data protection and cybersecurity risks. IT Management works closely with our legal department to oversee compliance with legal, regulatory and contractual security requirements.

During 2025, our Vice President and Chief Information Officer was a seasoned IT professional with over 30 years of experience encompassing all facets of IT within the energy industry. His extensive background comprises managing IT service delivery, designing and administering secure solutions, establishing robust IT and Internet of Things infrastructures, and effectively managing technology-related risks. His skill set includes proficiency in threat mitigation, comprehensive risk assessment, and integration of cybersecurity strategies into business operations designed to safeguard critical assets and sensitive data. He reported to our Executive Vice President and Chief Financial Officer until his retirement in January 2026. Our Director of Cybersecurity Risk and Business Continuity has over 25 years of experience in the IT field with a majority of that time focused on designing, building and maintaining technology systems. His experience includes implementing security solutions and processes with a focus on adapting to the evolving cybersecurity threat landscape. He is a skilled leader and reports to our Executive Vice President and Chief Financial Officer.

In January 2026, upon his retirement, our Vice President and Chief Information Officer,’s role was been assumed by our new Vice President of Information Technology who has over 20 years of IT experience,12 of which have been at the Company in progressive leadership roles.

We have adopted a Cybersecurity Incident Response Plan that applies in the event of a cybersecurity threat or incident (the “IRP”) to provide a standardized framework for responding to security incidents. The IRP outlines protocols by which certain cybersecurity incidents are escalated within the Company and, where appropriate, reported to executive management Audit Committee in a timely manner. We have also established a Cyber Incident Response Team (“CIRT”) led by IT Management, to provide an efficient, effective, and orderly response to technology related incidents. The IRP applies to all Company personnel (including third-party contractors, vendors and partners) that perform functions or services require access to secure Company information, and to all devices and network services that are owned or managed by the Company.

Risk Management and Strategy

We believe that mitigating cybersecurity risks is the responsibility of every employee. We are focused on building a resilient cybersecurity culture and strong IT and OT infrastructure. Our processes for assessing, identifying, and managing material risks from cybersecurity threats include:

• monitoring the threat landscape and taking measures to enhance our cybersecurity program to adapt to new and developing risks;
• ongoing mandatory training and testing, and utilizing other forms of social engineering awareness and education for our employees;
• using cybersecurity tools to monitor endpoints and environment logs in a centralized security information and event management system with capabilities for detecting and alerting on known threats and anomalous behaviors;
• assessing the cybersecurity practices and external ratings and assessments of certain of our third-party technology and data vendors and service providers, and maintaining preventative controls and monitoring systems related to these partners;
• creating and testing various incident response plans to hypothetical cybersecurity attacks in order to quickly assess and respond to potential and actual threats;
• engaging third-party cybersecurity experts and consultants to perform penetration testing and scanning of our systems for vulnerabilities;
• obtaining third-party security maturity assessments, benchmarking, and security effectiveness ratings of our cybersecurity program; and
• maintaining a retainer for incident response services with a trusted cybersecurity partner in order to quickly respond, investigate, contain, and recover in the event of a cybersecurity incident.

Our cybersecurity risk management program leverages the National Institute of Standards and Technology’s Cybersecurity Framework. We strive to employ cybersecurity best practices, including implementing new technologies to proactively monitor new threats and vulnerabilities and reduce risk; maintaining a Cybersecurity Incident Response Plan, Disaster Recovery Plan, and Business Continuity Plan; and regularly updating our response planning and protocols. We have integrated our cybersecurity processes into our overall enterprise risk management program, thereby establishing a comprehensive approach by which we determine and implement strategies designed to manage external, strategic, operational and financial risks to our business, including cybersecurity threats.

We utilize a wide range of protective cybersecurity technologies and tools, including, but not limited to, encryption, firewalls, endpoint detection and response, security information and event management, multi-factor authentication, and threat intelligence feeds. In addition, we use an information security risk management approach that includes monitoring security threats and trends in the industry, analyzing potential security risks that could impact the business, partnering with industry recognized security organizations, and coordinating an appropriate response should the need arise.

Cybersecurity threats and incidents could have a material impact on our financial condition and results of operations. A successful cyber-attack could lead to operational disruptions, financial losses, regulatory penalties, reputational damage, and legal liabilities. In some cases, the costs associated with investigating and remediating a cybersecurity incident, as well as potential litigation and regulatory fines, could result in a material impact to our financial condition and results of operations. During 2025, 2024, and 2023, we did not experience any cybersecurity incidents that materially affected or are reasonably likely to materially affect us, including our business strategy, results of operations, or financial condition, however, there can be no assurance that the measures we have taken to address IT and cybersecurity risks will prove effective in the future. For additional discussion of the IT and cybersecurity risks facing our business, refer to Risk Factors in Part I, Item 1A of this report.

We prioritize investment in cybersecurity risk management and governance. We continually assess the adequacy of our resources and capabilities to address emerging threats, regulatory requirements, and changes in technology. As cybersecurity threats evolve, we may need to further enhance our processes and technologies, which could require additional financial resources.

At times, we may be involved in litigation relating to claims arising out of our business and operations in the normal course of business. As of the filing of this report, no legal proceedings are pending against us that we believe individually or collectively are likely to have a material adverse effect upon our financial condition, results of operations, or cash flows.

With respect to administrative or judicial proceedings involving the environment, we have determined that we will disclose any such proceeding if we reasonably believe such proceeding will result in monetary sanctions, exclusive of interest and costs, of $1 million or more.

The following discussion includes forward-looking statements. Refer to the Cautionary Information about Forward-Looking Statements section of this report for important information about these types of statements. For discussion related to changes in financial condition and results of operations for the year ended December 31, 2024, compared with the year ended December 31, 2023, refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 20, 2025.

Overview of the Company

Merger with Civitas

On November 2, 2025, we entered into the Merger Agreement with Civitas. On January 27, 2026, our stockholders voted in favor of both proposals necessary to complete the Civitas Merger, which included approval of (i) the issuance of shares of SM Energy common stock to Civitas stockholders as contemplated by the Merger Agreement, and (ii) an amendment of our Restated Certificate of Incorporation to increase the number of authorized shares of our common stock from 200 million shares to 400 million shares.

On January 30, 2026, we completed the Civitas Merger in accordance with the terms of the Merger Agreement. Civitas was an independent exploration and production company focused on the acquisition, development, and production of crude oil and associated liquids-rich natural gas in the DJ Basin in Colorado and the Permian Basin in Texas and New Mexico. We believe that the Merger will create a premier portfolio across the highest-return U.S. shale basins, driving significant free cash flow, enhancing stockholder value, and enabling the realization of significant operational and cost efficiencies.

Under the terms of the Merger Agreement, subject to certain exceptions, each share of Civitas common stock was converted into the right to receive 1.45 shares of SM Energy common stock, with cash paid in lieu of fractional shares. On January 30, 2026, we issued approximately 124 million shares to holders of Civitas common stock, representing 52 percent of the outstanding shares of SM Energy’s common stock upon the closing of the Merger. Based on the closing price of SM Energy common stock on January 30, 2026, the total stock consideration was valued at $2.4 billion.

Refer to Note 17 – Mergers, Acquisitions, and Divestitures in Part II, Item 8 of this report for additional discussion.

South Texas Asset Divestiture

On February 17, 2026, we entered into the PSA with Caturus to sell certain of our South Texas assets for a Purchase Price of $950 million, subject to certain customary purchase price adjustments set forth in the PSA. This Transaction is expected to advance our deleveraging goals and position us to substantially achieve our commitment to complete at least $1.0 billion of divestitures within one year following the closing of the Civitas Merger. Refer to Note 17 – Mergers, Acquisitions, and Divestitures in Part II, Item 8 for additional discussion and the definitions of Purchase Price and Transaction.

General Overview

Our purpose is to make people’s lives better by responsibly producing energy supplies, contributing to domestic energy security and prosperity, and having a positive impact in the communities where we live and work. We are a premier operator of top-tier assets in the Midland Basin, South Texas, and the Uinta Basin, utilizing state-of-the-art digital technology, data analytics, and AI in our operations, and continually seeking innovative ideas to help us optimize capital efficiency and well performance, while reducing our impact on shared natural resources and operating in an efficient, safe, and responsible manner.

Following the closing of the Civitas Merger, our asset portfolio consists of high-quality assets in the Midland Basin and Delaware Basin, both of which are part of the larger Permian Basin of Texas and New Mexico, the Maverick Basin of South Texas, the Uinta Basin of northeast Utah, and the DJ Basin of northeast Colorado. We believe our assets are capable of generating strong returns in the current macroeconomic environment and provide resilience to commodity price risk and volatility. Through disciplined capital spending, strategic acquisitions and divestitures, and continued development and optimization, we seek to maximize returns and increase the value of our top-tier asset base while maintaining financial flexibility and a sustainable approach to long-term value creation.

Our long-term vision and strategy are focused on sustainably growing value for all of our stakeholders by deploying our technical excellence and exceptional execution to improve and optimize our high-quality asset portfolio, generate cash flows, and maintain a disciplined, strong balance sheet. Our team executes our strategy by prioritizing safety, technological innovation, and stewardship of natural resources, which are foundational to our corporate culture. Our near-term strategic focus is the successful integration of Civitas following the closing of the Merger on January 30, 2026. Integration is centered on maintaining safe operations, delivering consistent operational execution, and continuing to generate cash flows that enable us to return value to stockholders through fixed dividend payments, debt reduction, and share repurchases. Refer to Outlook for discussion of our 2026 capital program.

We are committed to exceptional safety, health, and environmental stewardship; supporting the professional development of a diverse and thriving team of employees; building and maintaining partnerships with our stakeholders by investing in and connecting with the communities where we live and work; and transparency in reporting our progress in these areas. The Governance and Sustainability Committee of our Board of Directors oversees, among other things, the effectiveness of our sustainability policies, programs and initiatives, monitors and responds to emerging trends, issues, and associated risks, and, together with management, reports to our Board of Directors regarding such matters. Further demonstrating our commitment to sustainable operations and environmental stewardship, compensation for our executives and employees under certain aspects of our compensation plans is calculated based on Company-wide performance metrics that include key financial, operational, environmental, health, and safety measures. Refer to our Definitive Proxy Statement on Schedule 14A for the 2026 annual meeting of stockholders to be filed within 120 days from December 31, 2025, for additional discussion of our compensation program.

Market Trends and Uncertainties

As global commodities, the prices of oil, gas, and NGLs, as well as broader financial markets, remain subject to heightened uncertainty and volatility. Market conditions are influenced by factors including real or perceived geopolitical risks, War and Geopolitical Instability, OPEC+ production decisions, fluctuations in global supply and demand (including demand from China), U.S. Federal Reserve monetary policy, movements in the strength of the U.S. dollar, shipping channel constraints and disruptions, tariffs or trade restrictions, and changes in global oil inventory in storage. These factors have resulted in commodity price volatility, contributed to instances of supply chain disruptions, inflation, and interest rate fluctuations, and could have further industry-specific impacts that may require us to adjust our business plan. The timing and magnitude of future effects are inherently unpredictable.

Historically, tariffs have led to increased costs for products exchanged in international trade, and have heightened global political tensions. Recent U.S. government policies, including new and higher tariffs on imported goods, have increased economic uncertainty. These tariffs, along with retaliatory tariffs from other countries, could lead to reduced trade resulting from increased costs for imported goods and decreased demand for U.S. exports, as well as reduced investment and technological exchange between major economies. These outcomes could negatively impact global economic conditions, financial market stability, and commodity prices. Volatility in political, trade, regulatory, and economic conditions could have a material adverse effect on our financial condition or results of operations. We are unable to reasonably estimate the period of time that these market conditions will exist or the extent to which they will impact our business, results of operations, and financial condition.

Continuing volatility in political, trade, regulatory and economic conditions could impact supply and demand fundamentals, and any related declines in oil, gas, and NGL prices could lead to proved and unproved property impairments in the future. Future impairments of proved and unproved properties are difficult to predict, especially in a volatile price environment.

Outlook

We expect our total 2026 capital program to be approximately $2.65 billion to $2.85 billion, excluding acquisitions, which we expect to fund with cash flows from operations, with any remaining cash needs being funded by borrowings under our revolving credit facility. We plan to focus our 2026 capital program on highly economic oil development projects in our Midland Basin, South Texas, Uinta Basin, and DJ Basin assets. Refer to Outlook in Part I, Items 1 and 2 of this report for additional discussion.

2025 Financial and Operational Highlights

During 2025:

• We completed the integration of the Uinta Basin assets into our portfolio. Refer to Note 17 – Mergers, Acquisitions, and Divestitures in Part II, Item 8 of this report for additional discussion of the Uinta Basin Acquisition.
• Net equivalent production of 75.5 MMBOE drove net income of $648 million, net cash provided by operating activities of $2.0 billion, and Adjusted EBITDAX, a non-GAAP financial measure, of $2.3 billion. Refer to Non-GAAP Financial Measures below for additional discussion, including our definition of adjusted EBITDAX and reconciliations to net income and net cash provided by operating activities.
• Strong operating cash flow enabled us to reduce debt through $69 million in net repayments on our revolving credit facility, increase cash on hand to $368 million, and return capital to stockholders. We repurchased and subsequently retired 444,705 shares of our common stock at a cost of $12 million, excluding excise taxes, commissions, and fees, and paid $92 million in dividends.

Financial and Operational Results. Oil, gas, and NGL production revenue increased 17 percent to $3.1 billion for the year ended December 31, 2025, compared with $2.7 billion for 2024. This increase was primarily driven by a 21 percent increase in average net daily equivalent production to 206.8 MBOE, reflecting a full year of production from our Uinta Basin assets and continued strong well performance, partially offset by a three percent decrease in total realized price per BOE due to lower oil and NGL benchmark commodity prices. Oil, gas, and NGL production expense on a per BOE basis increased 15 percent to $11.72 per BOE for the year ended December 31, 2025, compared with 2024.

We recorded net derivative gains of $178 million and $50 million for the years ended December 31, 2025, and 2024, respectively. These amounts include net derivative settlement gains of $132 million and $69 million for the years ended December 31, 2025, and 2024, respectively.

Operational activities during the year ended December 31, 2025, resulted in the following:

• Net cash provided by operating activities of $2.0 billion, compared with $1.8 billion for 2024.
• Net income of $648 million, or $5.64 per diluted share, compared with net income of $770 million, or $6.67 per diluted share for 2024.
• Adjusted EBITDAX, a non-GAAP financial measure, of $2.3 billion, compared with $2.0 billion for 2024. Refer to Non-GAAP Financial Measures below for additional discussion, including our definition of adjusted EBITDAX and reconciliations to net income and net cash provided by operating activities.
• Estimated net proved reserves decreased slightly to 673.0 MMBOE as of December 31, 2025 from 678.3 MMBOE as of December 31, 2024. As of December 31, 2025, 60 percent of our net proved reserves were liquids (oil and NGLs), and 61 percent were proved developed reserves. The decrease primarily related to 75.5 MMBOE produced in 2025, the removal of 40.7 MMBOE of certain net proved undeveloped reserves that are no longer expected to be developed within the five-year period from initial booking resulting from testing and delineation efforts, and 15.5 MMBOE of net performance and price revisions. The decreases were mostly offset by revisions of previous estimates of 87.0 MMBOE related to infill reserves, primarily related to our South Texas assets, and additions from extensions and discoveries of 39.7 MMBOE, primarily related to our Uinta Basin assets. Our proved reserve life index decreased to 8.9 years as of December 31, 2025, compared with 10.9 years as of December 31, 2024. Refer to Reserves in Part I, Items 1 and 2 of this report for additional discussion. The standardized measure of discounted future net cash flows was $6.0 billion as of December 31, 2025, compared with $7.3 billion as of December 31, 2024. The year-over-year decrease of 18 percent was primarily due to decreases in oil and NGL benchmark commodity prices during 2025. Refer to Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report for additional discussion.

Operational Activities. During 2025, successful operational execution drove strong well performance and capital efficiency across our asset portfolio. Our continued success in our Midland Basin, South Texas, and Uinta Basin programs is attributable to our top-tier assets and technical teams, and our commitment to geoscience, technology, and innovation.

In our Midland Basin program, we averaged three drilling rigs and one completion crew during 2025. Average net daily equivalent production volumes increased year-over-year by three percent to 82.8 MBOE. Costs incurred during 2025 totaled $548 million, or 38 percent, of our total 2025 costs incurred. Drilling and completion activities focused on developing formations within our RockStar and Sweetie Peck assets.

In our South Texas program, we averaged one drilling rig and one completion crew during 2025. Average net daily equivalent production volumes decreased year-over-year by one percent to 80.3 MBOE. Costs incurred during 2025 totaled $361 million, or 25 percent, of our total 2025 costs incurred. Drilling and completion activities were primarily focused on delineating and developing the Austin Chalk formation.

In our Uinta Basin program, we averaged three drilling rigs and one completion crew during 2025. Average net daily equivalent production volumes increased to 43.7 MBOE for the full year 2025, compared to 36.1 MBOE for the fourth quarter of 2024. Costs incurred during 2025 totaled $481 million, or 33 percent, of our total 2025 costs incurred. Drilling and completion activities primarily focused on delineating and developing the Lower Green River and Wasatch formations.

The table below provides a summary of changes in our drilled but not completed well count and current year drilling, completion, and acquisition activity in our operated programs for the year ended December 31, 2025:

(1) As of December 31, 2024, the drilled but not completed well count included nine gross (nine net) wells that were not included in our five-year development plan, eight of which were in the Eagle Ford shale. As of December 31, 2025, the drilled but not completed well count included two gross (two net) wells that were not included in our five year development plan, each of which are in the Eagle Ford shale.

(2) The South Texas adjustments relate to previously drilled wells that we no longer intend to complete.

(3) The Uinta Basin adjustment relates to the acquisition of additional working interest in existing drilled but not completed wells.

Costs Incurred. Costs incurred in oil and gas property acquisition, exploration, and development activities, whether capitalized or expensed, are summarized as follows:

(in millions)

(1) Refer to the caption Costs Incurred in Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report.

Production Results. The table below presents the disaggregation of our net production volumes by product type for each of our assets for the year ended December 31, 2025:

Net equivalent production increased 21 percent for the year ended December 31, 2025, compared with 2024. The increase was a result of a three percent increase from our Midland Basin assets, a full year of production from our Uinta Basin assets, and continued strong well performance. Refer to Overview of Selected Production and Financial Information, Including Trends and Comparison of Financial Results and Trends Between 2025 and 2024 below for additional discussion of production.

Oil, Gas, and NGL Prices

Our financial condition and the results of our operations are significantly affected by the prices we receive for our oil, gas, and NGL production, which can fluctuate dramatically. When we refer to realized oil, gas, and NGL prices below, the disclosed price represents the average price for the respective period, before the effect of net derivative settlements. While quoted NYMEX oil and gas and OPIS NGL prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, location and transportation differentials, and contracted pricing benchmarks for these products.

The following table summarizes commodity price data, as well as the effect of net derivative settlements, for the years ended December 31, 2025, and 2024:

(1) Our realized prices at local sales points may be affected by infrastructure capacity in the areas of our operations and beyond.

(2) Average OPIS price per barrel of NGL, historical or strip, assumes a composite barrel product mix of 42% Ethane, 28% Propane, 6% Isobutane, 11% Normal Butane, and 13% Natural Gasoline. This product mix represents the industry standard composite barrel and does not necessarily represent our product mix for NGL production. Realized prices reflect our actual product mix.

The following table summarizes 12-month strip prices for NYMEX WTI oil, NYMEX Henry Hub gas, and OPIS NGLs as of February 2, 2026, and December 31, 2025:

We use financial derivative instruments as part of our financial risk management program. We have a financial risk management policy governing our use of derivatives, and decisions regarding entering into commodity derivative contracts are overseen by a financial risk management committee consisting of certain senior executive officers and finance personnel. We make decisions about the amount of our expected production that we cover by derivatives based on the amount of debt on our balance sheet, the level of capital commitments and long-term obligations we have in place, and the terms and futures prices that are made available by our approved counterparties. With our current commodity derivative contracts, we believe we have partially reduced our exposure to volatility in commodity prices and basis differentials in the near term. Our use of costless collars for a portion of our derivatives allows us to participate in some of the upward movements in oil and gas prices while also setting a price floor below which we are insulated from further price decreases. Refer to Note 7 – Derivative Financial Instruments in Part II, Item 8 of this report and to Commodity Price Risk in Overview of Liquidity and Capital Resources below for additional information regarding our oil, gas, and NGL derivatives.

Financial Results of Operations and Additional Comparative Data

The tables below provide information regarding selected production and financial information for the three months ended December 31, 2025, and the preceding three quarters:

(in millions)

Selected Performance Metrics

Overview of Selected Production and Financial Information, Including Trends

(1) Amounts and percentage changes may not calculate due to rounding.

(2) Net derivative settlements for the years ended December 31, 2025, and 2024, are included within the net derivative gain line item in the accompanying consolidated statements of operations (“accompanying statements of operations”).

(3) Refer to Note 9 – Earnings Per Share in Part II, Item 8 of this report for additional discussion.

The Civitas Merger, which closed on January 30, 2026, is expected to materially affect our future operating and financial results. The addition of Civitas’ assets and operations is expected to increase production volumes and revenues and to impact oil, gas, and NGL production expense, general and administrative expense, and other expense categories. The magnitude and timing of these impacts will depend, in part, on integration activities, operating performance, commodity prices, and other factors and may not be directly comparable to the Company’s historical results. Unless otherwise noted, the discussion below reflects the results of our legacy operations and historical trends prior to the Merger.

Average net daily equivalent production for the year ended December 31, 2025, increased 21 percent compared with 2024, resulting from a full year of production from our Uinta Basin assets, and continued strong well performance. Oil production as a percentage of total production increased to 53 percent in 2025 from 47 percent in 2024, resulting from a full year of oil production from our Uinta Basin assets, which averaged 87 percent oil production in 2025. In 2026, we expect an increase in total production volumes due to the integration of assets from the Civitas Merger. Refer to Comparison of Financial Results and Trends Between 2025 and 2024 below for additional discussion.

We present certain information on a per BOE basis in order to evaluate our performance relative to our peers and to identify and measure trends we believe may require additional analysis and discussion.

Our realized price on a per BOE basis decreased three percent for the year ended December 31, 2025, compared with 2024, primarily because of decreases in oil benchmark commodity prices partially offset by the increase in gas benchmark commodity prices. For the years ended December 31, 2025, and 2024, we recognized net gains on the settlement of our commodity derivative contracts of $1.75 per BOE and $1.10 per BOE, respectively.

LOE on a per BOE basis increased 12 percent for the year ended December 31, 2025, compared with 2024, driven by the increased percentage of oil in our total production mix, which has higher lifting costs per BOE, and increases in certain operating costs. We anticipate volatility in LOE on a per BOE basis resulting from changes in production, timing of workover projects, changes in service provider costs, and industry activity, all of which affect total LOE.

Transportation costs on a per BOE basis increased 44 percent for the year ended December 31, 2025, compared with 2024. This increase was primarily due to 15.9 MMBOE of full year production from our Uinta Basin assets, which incur higher transportation costs on a per BOE basis compared to our Midland Basin and South Texas assets. In general, we expect total transportation costs to fluctuate relative to changes in oil production from our Uinta Basin assets and gas and NGL production from our South Texas assets, where we incur a majority of our transportation costs. For 2026, we expect transportation costs on a per BOE basis to remain relatively flat compared with 2025.

Production tax expense on a per BOE basis for the year ended December 31, 2025, decreased nine percent compared with 2024, primarily resulting from a decrease in the realized price of oil, and full year operations for our Uinta Basin assets which incur a lower production tax rate compared to our Midland Basin and South Texas assets. Our overall production tax rate was 4.1 percent and 4.3 percent for the years ended December 31, 2025, and 2024, respectively. We generally expect production tax expense to correlate with oil, gas, and NGL production revenue on a per BOE and absolute basis. Product mix, the location of production, and incentives to encourage oil and gas development can also impact the amount of production tax expense that we recognize.

Ad valorem tax expense on a per BOE basis decreased 18 percent for the year ended December 31, 2025, compared with 2024, primarily due to increased net equivalent production and changes to the assessed values of our producing properties. We anticipate volatility in ad valorem tax expense on a per BOE and absolute basis as the valuation of our producing properties changes.

Depletion, depreciation, and amortization (“DD&A”) expense on a per BOE basis increased 23 percent for the year ended December 31, 2025, compared with 2024, due to increased production from our Uinta Basin assets, which caused a shift in the production mix towards our higher rate Midland Basin and Uinta Basin assets. For 2026, we expect DD&A expense on an absolute basis to increase compared with 2025, primarily reflecting anticipated higher production volumes and our expanded asset base. Our DD&A expense on a per BOE and absolute basis may fluctuate as a result of changes in our production mix, changes in our total estimated proved reserve volumes, changes in capital allocation, impairments, acquisition and divestiture activity, and carrying cost funding and sharing arrangements with third parties.

General and administrative (“G&A”) expense on a per BOE basis decreased four percent for the year ended December 31, 2025, compared with 2024, primarily driven by a higher rate of production growth relative to increases in G&A expense on an absolute basis. For 2026, we expect G&A expense on an absolute basis and on a per BOE basis to increase compared with 2025, primarily due to an increase in employee headcount as a result of the Civitas Merger, and expected increases in compensation expense and integration costs. Certain components of G&A expense, and G&A expense on a per BOE basis, are impacted by the Company’s full year performance against performance targets established at the beginning of the year and, therefore, are subject to variability.

Refer to Comparison of Financial Results and Trends Between 2025 and 2024 for additional discussion of operating expenses.

Comparison of Financial Results and Trends Between 2025 and 2024

Average net daily equivalent production, production revenue, and production expense

The following table presents the changes in our average net daily equivalent production, oil, gas, and NGL production revenue, and oil, gas, and NGL production expense, by area, between the years ended December 31, 2025, and 2024:

(in millions)

(in millions)

Note: Amounts may not calculate due to rounding.

Average net daily equivalent production volumes for the year ended December 31, 2025, increased 21 percent compared with 2024, comprised of a three percent increase from our Midland Basin assets, and 43.7 MBOE of production from our Uinta Basin assets. As a result of decreases in benchmark oil and NGL prices, realized prices for oil and NGLs decreased 15 percent and three percent, respectively, while the realized price for gas increased 29 percent. Oil, gas, and NGL production revenue increased 17 percent, primarily resulting from a 21 percent increase in average net daily equivalent production volumes. Oil, gas, and NGL production expense for the year ended December 31, 2025, increased 39 percent compared with 2024, as activity related to our Uinta Basin assets contributed to increases in transportation costs, LOE, and production tax expense.

Refer to Overview of Selected Production and Financial Information, Including Trends above for additional discussion, including discussion of trends on a per BOE basis.

Depletion, depreciation, and amortization

(in millions)

DD&A expense for the year ended December 31, 2025, increased 49 percent compared with 2024, primarily resulting from increased production from our Uinta Basin assets during 2025. Our Midland Basin and Uinta Basin assets have higher DD&A rates than our South Texas assets. Refer to Overview of Selected Production and Financial Information, Including Trends above for discussion of DD&A expense on a per BOE basis.

Exploration

(in millions)

Exploration expense decreased 11 percent for the year ended December 31, 2025, compared with 2024, primarily resulting from a decrease in geological and geophysical and other expenses. Exploration expense fluctuates based on actual geological and geophysical studies we perform within an exploratory area, exploratory dry hole expense incurred, and changes in the amount of allocated overhead.

General and administrative

(in millions)

G&A expense increased 17 percent for the year ended December 31, 2025, compared with 2024, primarily due to increased compensation costs associated with additional headcount from the Uinta Basin Acquisition. Refer to Overview of Selected Production and Financial Information, Including Trends above for discussion of G&A expense, including G&A expense on a per BOE basis.

Net derivative gain

(in millions)

Net derivative gain is a result of changes in fair values associated with fluctuations in the forward price curves for the commodities underlying our outstanding derivative contracts and the monthly cash settlements of our derivative positions during the period. We expect increases in benchmark commodity prices to result in net derivative losses, and decreases in benchmark commodity prices to result in net derivative gains, as measured against our derivative contract prices. Refer to Note 7 – Derivative Financial Instruments in Part II, Item 8 of this report for additional discussion.

Interest expense

(in millions)

Interest expense increased 23 percent for the year ended December 31, 2025, compared with 2024, as a result of the issuance of our 2029 Senior Notes and 2032 Senior Notes during the third quarter of 2024 and an increase in interest expense associated with borrowings under our revolving credit facility. Total interest expense can vary based on the amount of our outstanding fixed-rate debt securities, fluctuations in the amount of capitalized interest resulting from the timing of the development of our wells in progress, and due to the timing and amount of borrowings under our revolving credit facility. Refer to Overview of Liquidity and Capital Resources below and to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion and definitions.

Income tax expense

(in millions, except tax rate)

Our effective tax rate is impacted by changes in revenue affecting the apportionment of taxable income to states with higher statutory tax rates and proportional effects of net income on permanent items between periods and states. Our effective tax rate increased during 2025, primarily resulting from the impact of state income taxes and the decoupling of state income tax calculations from certain OBBBA provisions, partially offset by the Company’s increasing research and development (“R&D”) activities in new basins and additional credit claims. The increase also reflects the impact of excess tax deficiencies from stock-based compensation awards.

During 2025, we made estimated tax payments of $8 million and received a federal refund of $4 million during the fourth quarter of 2025.

The effects of changes in tax laws are recognized in the period of enactment. On July 4, 2025, the OBBBA was enacted into law and includes, among other things, tax reform provisions that amend, eliminate, and extend tax rules under the Inflation Reduction Act and Tax Cuts and Jobs Act. During 2025, we recorded the impact of the OBBBA, which resulted in a decrease to our current portion of income tax expense. This change reflects the impacts of the reinstatement of 100 percent bonus depreciation on tangible assets; the immediate expensing of qualified R&D expenditures and the expensing of unamortized, previously capitalized, prior year qualified R&D expenditures; and a less restrictive limitation on the business interest expense deduction. Additionally, the OBBBA allows for the deduction of intangible drilling costs from Adjusted Financial Statement Income (“AFSI”) when determining whether a company is subject to and liable for the Corporate Alternative Minimum Tax (“CAMT”). As a result, we do not expect to become subject to or liable for the CAMT for the foreseeable future, notwithstanding other factors that may impact our AFSI.

Refer to Note 4 – Income Taxes in Part II, Item 8 of this report for further discussion.

Overview of Liquidity and Capital Resources

Based on the current commodity price environment, we believe we have sufficient liquidity and capital resources to execute our business plan while continuing to meet our financial obligations, including near-term maturities of our outstanding Senior Notes. We continue to manage the duration and level of our drilling and completion service commitments in order to maintain flexibility with regard to our activity level and capital expenditures.

Sources of Cash

We expect to fund our 2026 capital expenditures and return of capital program with cash flows from operations, with any remaining cash needs being funded by borrowings under our revolving credit facility. Although we expect cash flows from these sources to be sufficient for 2026, we may also elect to raise funds through new debt or equity offerings or from other sources of financing. If we raise additional funds through the issuance of equity or convertible debt securities, the percentage ownership of our current stockholders could be diluted, and these newly issued securities may have rights, preferences, or privileges senior to those of existing stockholders and bondholders. Additionally, we may enter into carrying cost and sharing arrangements with third parties for certain exploration or development programs.

During 2024, we issued our 2029 Senior Notes and 2032 Senior Notes. See below for discussion on how the net proceeds received were used, and refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion.

Our credit ratings affect the availability of, and cost for us to borrow, additional funds. Two major credit rating agencies upgraded our credit ratings following the close of the Civitas Merger on January 30, 2026, citing our increased size, scale and diversification, and enhanced and consistently positive free cash flow generation.

All of our sources of liquidity can be affected by the general conditions of the broader economy, force majeure events, fluctuations in commodity prices, operating costs, interest rate changes, tax law changes, and volumes produced, all of which affect us and our industry.

We have no control over the market prices for oil, gas, and NGLs, although we may be able to influence the amount of our realized revenues from our oil, gas, and NGL sales through the use of commodity derivative contracts as part of our financial risk management program. Commodity derivative contracts may limit the prices we receive for our oil, gas, and NGL sales if oil, gas, or NGL prices rise over the price established by the commodity derivative contract. Refer to Note 7 – Derivative Financial Instruments in Part II, Item 8 of this report for additional information about our commodity derivative contracts currently in place and the timing of settlement of those contracts.

Credit Agreement

Our Credit Agreement provides for a senior secured revolving credit facility with a maximum loan amount of $3.0 billion. As of December 31, 2025, the borrowing base and aggregate revolving lender commitments under our Credit Agreement were $3.0 billion and $2.0 billion, respectively. The borrowing base is subject to regular, semi-annual redetermination, and considers the value of both our proved oil and gas properties reflected in our most recent reserve report and commodity derivative contracts, each as determined by our lender group. The next borrowing base redetermination date is scheduled to occur on April 1, 2026. During, 2025 we entered into the Third Amendment with our lenders to amend the springing maturity provision of the Credit Agreement to provide a more flexible structure based on the amount of our short-term debt outstanding and our borrowing availability. No individual bank participating in our Credit Agreement represents more than 10 percent of the lender commitments under the Credit Agreement. We must comply with certain financial and non-financial covenants under the terms of the Credit Agreement, including covenants limiting dividend payments and requiring that we maintain certain financial ratios, as set forth in the Credit Agreement. We were in compliance with all financial and non-financial covenants as of December 31, 2025, and through the filing of this report. In connection with the closing of the Civitas Merger on January 30, 2026, the Company and its lenders entered into the Fourth Amendment to the Credit Agreement, which, among other things, increased the aggregate revolving lender commitments available under our Credit Agreement to $2.5 billion and increased the borrowing base to $5.0 billion. Refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report for definitions of the Third

Amendment and Fourth Amendment and additional discussion, as well as the presentation of the outstanding balance, total amount of letters of credit, and available borrowing capacity under the Credit Agreement as of February 2, 2026, December 31, 2025, and December 31, 2024.

The following table summarizes our daily weighted-average revolving credit facility balance during the periods presented:

(in millions)

The amount we borrow under our revolving credit facility is impacted by cash flows provided by our operating activities, proceeds received from divestitures of properties, capital markets activities including open market debt repurchases, debt redemptions, and repayment of scheduled debt maturities, other financing activities, and our capital expenditures, including acquisitions.

Weighted-Average Interest and Weighted-Average Borrowing Rates

Our weighted-average interest rate includes paid and accrued interest, fees on the unused portion of the aggregate revolving lender commitment amount under the Credit Agreement, letter of credit fees, and the non-cash amortization of deferred financing costs. Our weighted-average borrowing rate includes paid and accrued interest only.

The following table presents our weighted-average interest rates and our weighted-average borrowing rates for the years ended December 31, 2025 and 2024:

Our weighted-average interest rate decreased for the year ended December 31, 2025, compared with 2024, primarily due to decreased borrowings under our revolving credit facility. Our weighted-average borrowing rate increased for the year ended December 31, 2025, compared with 2024, primarily as a result of the issuance of our 2029 Senior Notes and 2032 Senior Notes during 2024, which have greater outstanding aggregate principal balances and higher interest rates compared with our other outstanding Senior Notes and our 5.625% Senior Notes due June 1, 2025 (“2025 Senior Notes”) that we redeemed during the third quarter of 2024. The rates disclosed in the table above for the year ended December 31, 2024, do not reflect the $9 million fee paid to secure firm commitments for senior unsecured bridge term loans in connection with the Uinta Basin Acquisition.

Our weighted-average interest rate and weighted-average borrowing rate are affected by the occurrence and timing of long-term debt issuances and redemptions and the average outstanding balance on our revolving credit facility. Additionally, our weighted-average interest rate is affected by the fees paid on the unused portion of our aggregate revolving lender commitments. The rates disclosed in the above table do not reflect certain amounts associated with the repurchase or redemption of Senior Notes, such as the accelerated expense recognition of the unamortized deferred financing costs and unamortized discounts, as these amounts are netted against the associated gain or loss on extinguishment of debt. The 2025 Senior Notes were redeemed at their par value on August 26, 2024 and after this date, the weighted-average interest rate was no longer affected by the non-cash amortization of deferred financing costs of the 2025 Senior Notes.

Refer to Significant Developments in 2025 in Part I, Items 1 and 2 for the definitions of 2029 Senior Notes and 2032 Senior Notes, and to Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion and definitions.

Uses of Cash

We use cash for the development, exploration, and acquisition of oil and gas properties; for the payment of operating and general and administrative costs, income taxes, debt obligations, including interest and early repayments or redemptions, and dividends; and for repurchases of shares of our outstanding common stock under the Stock Repurchase Program. Expenditures for the development, exploration, and acquisition of oil and gas properties are the primary use of our capital resources. During 2025, we spent $1.5 billion on capital expenditures and on acquisitions of proved and unproved oil and gas properties. This amount differs from the costs incurred amount of $1.4 billion for the year ended December 31, 2025, as costs incurred is an accrual-based amount that also includes asset retirement obligations, geological and geophysical expenses, and exploration overhead amounts. Refer to Costs Incurred in Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report for additional discussion.

The amount and allocation of our future capital expenditures will depend upon a number of factors, including our cash flows from operating, investing, and financing activities, our ability to execute our development program, inflation, and the number and size of acquisitions that we complete. In addition, the impact of oil, gas, and NGL prices on investment opportunities, the availability of capital, tax law and other regulatory changes, and the timing and results of our exploration and development activities may lead to changes in funding requirements for future development. We periodically review our capital expenditure budget and guidance to assess if changes are necessary based on current and projected cash flows, acquisition and divestiture activities, debt requirements, and other factors.

Changes to the Internal Revenue Code (“IRC“) and federal income tax laws could increase our corporate income tax rate and eliminate or reduce current tax deductions, such as those for intangible drilling costs, depreciation of equipment costs, and other deductions which currently reduce our taxable income. The CAMT and other possible future legislation could reduce our net cash provided by operating activities resulting in a reduction of available funding. Refer to Comparison of Financial Results and Trends Between 2025 and 2024 above for additional discussion.

We may from time to time repurchase shares of our common stock, or repurchase or redeem all or portions of our outstanding debt securities, for cash, through exchanges for other securities, or a combination of both. Such repurchases or redemptions may be made in open market transactions, privately negotiated transactions, tender offers, pursuant to contractual provisions, or otherwise. Any such repurchases or redemptions will depend on our business strategy, prevailing market conditions, our liquidity requirements, contractual restrictions or covenants, compliance with securities laws, and other factors. The amounts involved in any such transaction may be material.

During the years ended December 31, 2025, and 2024, we repurchased and subsequently retired 444,705 shares and 1,771,191 shares, respectively, of our common stock at a cost, excluding excise taxes, commissions, and fees, of $12 million and $84 million, respectively. As of December 31, 2025, $488 million remained available under the Stock Repurchase Program for repurchases of our common stock through December 31, 2027. Effective January 1, 2023, shares of common stock repurchased, net of shares of common stock issued, are subject to a one percent excise tax imposed by the IRA. We paid a minimal amount of excise tax related to common stock repurchases during 2025. Refer to Note 3 – Equity in Part II, Item 8 of this report for discussion of the Stock Repurchase Program.

During the years ended December 31, 2025, and 2024, we paid $92 million and $85 million, respectively, in dividends to our stockholders. Dividends paid were $0.80 and $0.74, per share during the years ended December 31, 2025, and 2024, respectively. Beginning in the first quarter of 2026, dividends are expected to be declared and paid within the same quarter, rather than being paid in the quarter subsequent to declaration. As a result of this timing change, cash dividend payments during 2026 are expected to include five payments, consisting of the fourth quarter 2025 dividend paid in the first quarter of 2026, plus the four quarterly dividends declared and paid during 2026. In February of 2026, our Board of Directors approved a 10 percent increase to our annual base dividend to $0.88 per share, payable quarterly, effective beginning with the March 2026 dividend. We currently intend to continue paying dividends to our stockholders for the foreseeable future, subject to our future earnings, our financial condition, covenants under our Credit Agreement and indentures governing each series of our outstanding Senior Notes, and other factors that could arise. The payment and amount of future dividends remain at the discretion of our Board of Directors.

During 2024, we redeemed all of the $349 million of aggregate principal amount outstanding of our 2025 Senior Notes. Additionally, we used a portion of the net proceeds from the 2029 Senior Notes and 2032 Senior Notes, cash on hand, and borrowings under our revolving credit facility to fund our proportionate share of the Uinta Basin Acquisition. Refer to Significant Developments in 2025 in Part I, Items 1 and 2 for the definitions of 2029 Senior Notes and 2032 Senior Notes, and to Note 5 – Long-Term Debt and Note 17 – Mergers, Acquisitions, and Divestitures in Part II, Item 8 of this report for additional discussion and definitions.

Analysis of Cash Flow Changes Between 2025 and 2024

The following tables present changes in cash flows between the years ended December 31, 2025 and 2024, for our operating, investing, and financing activities. The analysis following each table should be read in conjunction with our accompanying consolidated statements of cash flows (“accompanying statements of cash flows”) in Part II, Item 8 of this report.

Operating Activities

(in millions)

Net cash provided by operating activities increased for the year ended December 31, 2025, compared with 2024, primarily resulting from a $474 million increase in cash received from oil, gas, and NGL production revenues, net of transportation costs and production taxes, and an increase of $60 million in cash received on settled derivative trades. These amounts were partially offset by an increase of $169 million in cash paid for LOE, ad valorem taxes, and certain G&A expenses, and an increase of $78 million in cash paid for interest. Net cash provided by operating activities was also affected by the timing of payments made between us and XCL Resources related to activity occurring after the closing date of the Uinta Basin Acquisition. Refer to Note 17 – Mergers, Acquisitions, and Divestitures in Part II, Item 8 of this report for additional discussion and definitions.

Net cash provided by operating activities is affected by working capital changes and the timing of cash receipts and disbursements.

Investing Activities

(in millions)

Net cash used in investing activities decreased for the year ended December 31, 2025, compared with 2024, resulting from $2.1 billion of cash paid for the Uinta Basin Acquisition in 2024, partially offset by a $127 million increase in capital expenditures. Refer to Note 17 – Mergers, Acquisitions, and Divestitures in Part II, Item 8 of this report for additional discussion of the Uinta Basin Acquisition.

Financing Activities

(in millions)

Net cash used in financing activities during the year ended December 31, 2025, primarily related to $92 million of dividends paid to our stockholders, net repayments under our revolving credit facility of $69 million, and $13 million, including commission and fees, paid to repurchase and subsequently retire 444,705 shares of our common stock under the Stock Repurchase Program.

Net cash provided by financing activities during the year ended December 31, 2024, primarily related to net cash proceeds of $1.5 billion from the issuance of our 2029 Senior Notes and 2032 Senior Notes, and net borrowings under our revolving credit facility of $69 million, partially offset by $349 million of cash paid to redeem our 2025 Senior Notes. Additionally, we paid $86 million, including commission and fees, to repurchase and subsequently retire 1,771,191 shares of our common stock under the Stock Repurchase Program, and paid $85 million of dividends to our stockholders.

Refer to Note 3 – Equity in Part II, Item 8 of this report for additional discussion of our Stock Repurchase Program and Note 5 – Long-Term Debt in Part II, Item 8 of this report for additional discussion and definitions related to our debt transactions.

Interest Rate Risk

We are exposed to market and credit risk due to the floating interest rate associated with any outstanding balance on our revolving credit facility. Our Credit Agreement allows us to fix the interest rate for all or a portion of the principal balance of our revolving credit facility for a period up to six months. To the extent that the interest rate is fixed, interest rate changes will affect the revolving credit facility’s fair value but will not affect results of operations or cash flows. Conversely, for the portion of the revolving credit facility that has a floating interest rate, interest rate changes will not affect the fair value but will affect future results of operations and cash flows. Changes in interest rates do not affect the amount of interest we pay on our fixed-rate Senior Notes, but can affect their fair values. As of December 31, 2025, our outstanding principal amount of fixed-rate debt totaled $2.7 billion and we had no floating-rate debt outstanding. As of December 31, 2024, our outstanding principal amount of fixed-rate debt totaled $2.7 billion and our floating-rate debt outstanding totaled $69 million. Refer to Note 8 – Fair Value Measurements in Part II, Item 8 of this report for additional discussion on the fair values of our Senior Notes.

Commodity Price Risk

The prices we receive for our oil, gas, and NGL production directly affect our revenue, profitability, access to capital, ability to return capital to our stockholders, and future rate of growth. Oil, gas, and NGL prices are subject to unpredictable fluctuations resulting from a variety of factors that are typically beyond our control, including changes in supply and demand associated with the broader macroeconomic environment, constraints on gathering systems, processing facilities, pipelines, rail systems, and other transportation systems, and weather-related events. The markets for oil, gas, and NGLs have been volatile, especially over the last decade, and remain subject to high levels of uncertainty and volatility related to production output from OPEC+, fluctuations in oil and gas demand from China, global shipping channel constraints and disruptions, War and Geopolitical Instability, tariffs or trade restrictions, and the potential impacts of these issues on global commodity and financial markets. These circumstances have contributed to inflation, instances of supply chain disruptions, and fluctuations in interest rates, and could have further industry-specific impacts that may require us to adjust our business plan. The realized prices we receive for our production also depend on numerous factors that are typically beyond our control. Refer to Risk Factors - Risks Related to Commodity Prices and Global Macroeconomics in Part I, Item 1A of this report. Based on our production for 2025, and 2024, a 10 percent decrease in our average realized prices for oil, gas, and NGLs would have reduced our oil, gas, and NGL production revenues by approximately $256 million, $35 million, and $22 million, respectively, for 2025, and $219 million, $25 million and $24 million, respectively, for 2024. If commodity prices had been 10 percent lower, our net derivative settlements for the year ended December 31, 2025, would have offset the declines in oil, gas, and NGL production revenue by approximately $106 million.

We enter into commodity derivative contracts in order to reduce the risk of fluctuations in commodity prices. The fair value of our commodity derivative contracts is largely determined by estimates of the forward curves of the relevant price indices. As of December 31, 2025, and 2024, a 10 percent increase or decrease in the forward curves associated with our oil, gas, and NGL commodity derivative instruments would have changed our net derivative positions for these products by approximately $57 million, $36 million, and $1 million, respectively, for 2025, and $52 million, $23 million, and $2 million, respectively, for 2024.

Off-Balance Sheet Arrangements

We have not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities (“SPE” or “SPEs”). Refer to Off-Balance Sheet Arrangements within Note 1 – Summary of Significant Accounting Policies in Part II, Item 8 of this report for additional discussion.

Critical Accounting Estimates

Our discussion of financial condition and results of operations is based upon the information reported in our consolidated financial statements. The preparation of these consolidated financial statements in conformity with GAAP requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses, as well as the disclosure of contingent assets and liabilities as of the date of our consolidated financial statements. We base our assumptions and estimates on historical experience and various other sources that we believe to be reasonable under the circumstances. Actual results may differ from the estimates we calculate as a result of changes in circumstances, global economics and politics, and general business conditions. A summary of our significant accounting policies is detailed in Note 1 – Summary of Significant Accounting Policies in Part II, Item 8 of this report. We have outlined below, those policies identified as being critical to the understanding of our business and results of operations and that require the application of significant management judgment.

Successful Efforts Method of Accounting. GAAP provides two alternative methods for the oil and gas industry to use in accounting for oil and gas producing activities. These two methods are generally known in our industry as the full cost method and the successful efforts method, and both methods are widely used. The methods are different enough that in many circumstances the same set of facts will provide materially different financial statement results within a given year. We have chosen the successful efforts method of accounting for our oil and gas producing activities. A more detailed description is included in Note 1 – Summary of Significant Accounting Policies of Part II, Item 8 of this report.

Oil and Gas Reserve Quantities. Our estimated proved reserve quantities and future net cash flows are critical to understanding the value of our business. They are used in comparative financial ratios and are the basis for significant accounting estimates in our consolidated financial statements, including the calculations of DD&A expense, impairment of proved and unproved oil and gas properties, asset retirement obligations, and purchase price allocations. Refer to Oil and Gas Producing Activities in Note 1 – Summary of Significant Accounting Policies of Part II, Item 8 of this report for additional discussion on our accounting policies impacted by estimated reserve quantities.

Future cash inflows and future production and development costs are determined by applying prices and costs, including transportation, quality differentials, and basis differentials, applicable to each period to our net share of estimated quantities of proved reserves remaining to be produced as of the end of that period. Expected cash flows are discounted to present value using an appropriate discount rate. For example, the standardized measure of discounted future net cash flows calculation requires that a 10 percent discount rate be applied. Although reserve estimates are inherently imprecise and estimates of new discoveries and undeveloped locations are more imprecise than those of established producing oil and gas properties, we make a considerable effort in estimating our reserves. We engage Ryder Scott, an independent reservoir evaluation consulting firm, to audit a minimum of 80 percent of our total calculated proved reserve PV-10. We expect proved reserve estimates will change as additional information becomes available and as commodity prices and operating and capital costs change. We evaluate and estimate our proved reserves each year end. It should not be assumed that the standardized measure of discounted future net cash flows (GAAP) or PV-10 (non-GAAP) as of December 31, 2025, is the current market value of our estimated proved reserves. In accordance with SEC requirements, we based these measures on the unweighted arithmetic average of the first-day-of-the-month price of each month within the trailing 12-month period ended December 31, 2025. Actual future prices and costs may be materially higher or lower than the prices and costs utilized in the estimates. Refer to Risk Factors in Part I, Item 1A of this report for additional discussion.

If the estimates of proved reserves decline, the rate at which we record DD&A expense will increase, which would reduce future net income. Changes in DD&A rate calculations caused by changes in reserve quantities are made prospectively. In addition, a decline in reserve estimates may impact the outcome of our assessment of proved and unproved properties for impairment. Impairments are recorded in the period in which they are identified.

The following table presents information about proved reserve changes from period to period due to items we do not control, such as price, and from changes due to production history and well performance. These changes do not require a capital expenditure on our part, but may have resulted from capital expenditures we incurred to develop other estimated proved reserves.

As previously noted, commodity prices are volatile and estimates of reserves are inherently imprecise. Consequently, we expect to continue experiencing these types of changes.

We cannot reasonably predict future commodity prices, although we believe that together, the analyses below provide reasonable information regarding the impact of changes in pricing and trends on total estimated net proved reserves. The following table reflects the estimated MMBOE change and percentage change to our total reported estimated net proved reserve volumes from the described hypothetical changes:

(1) The change solely reflects the impact of a 10 percent decrease in SEC pricing to the total reported estimated net proved reserve volumes as of December 31, 2025, and does not include additional impacts to our estimated net proved reserves that may result from our internal intent to drill hurdles or changes in future service or equipment costs.

(2) The change solely reflects the impact of replacing SEC pricing with the five-year average NYMEX strip pricing as of December 31, 2025, and does not include additional impacts to our estimated net proved reserves that may result from our internal intent to drill hurdles or changes in future service or equipment costs. As of December 31, 2025, SEC pricing was $65.34 per Bbl for oil, $3.39 per MMBtu for gas, and $27.45 per Bbl for NGLs, and five-year average NYMEX strip pricing was $58.72 per Bbl for oil, $3.71 per MMBtu for gas, and $22.85 per Bbl for NGLs.

(3) The change solely reflects a 10 percent decrease in net proved undeveloped reserves as of December 31, 2025, and does not include any additional impacts to our estimated net proved reserves.

Additional reserve information can be found in Reserves in Part I, Items 1 and 2 of this report, and in Supplemental Oil and Gas Information (unaudited) in Part II, Item 8 of this report.

Impairment of Proved Properties. Proved oil and gas properties are evaluated for impairment on a depletion pool-by-pool basis and reduced to fair value when there is an indication that their carrying amount may not be recoverable. We estimate the expected future cash flows of our proved oil and gas properties and compare these undiscounted cash flows to the carrying amount to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will write down the carrying amount of the proved oil and gas properties to fair value (or discounted future cash flows). Management estimates future cash flows from all proved reserves and risk adjusted probable and possible reserves using various factors, which are subject to our judgment and expertise, and include, but are not limited to, commodity price forecasts, estimated future operating and capital costs, development plans, and discount rates to incorporate the risk and current market conditions associated with realizing the expected cash flows. We cannot predict when or if future impairment charges will be recorded because of the uncertainty in the factors discussed above. Despite any amount of future impairment being difficult to predict, based on our commodity price assumptions as of

February 2, 2026, we do not expect any material proved oil and gas property impairments in the first quarter of 2026 resulting from commodity price impacts.

Accounting Matters

Refer to Recently Issued Accounting Guidance in Note 1 – Summary of Significant Accounting Policies in Part II, Item 8 of this report for information on new authoritative accounting guidance.

Environmental

We believe we are in substantial compliance with environmental laws and regulations and do not currently anticipate that material future expenditures will be required under the existing regulatory framework. However, environmental laws and regulations are subject to frequent changes, and we are unable to predict the impact that compliance with future laws or regulations, such as those currently being considered as discussed below, may have on future capital expenditures, liquidity, and results of operations.

Hydraulic Fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. For additional information about hydraulic fracturing and related environmental matters, refer to Risk Factors – Risks Related to Litigation and Government Regulations – Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Climate Change and Air Quality. In June 2013, President Obama announced a Climate Action Plan designed to further reduce GHG emissions and prepare the nation for the physical effects that may occur as a result of climate change. The Climate Action Plan targeted methane reductions from the oil and gas sector as part of a comprehensive interagency methane strategy. As part of the Climate Action Plan, on May 12, 2016, the EPA issued final regulations applicable to new, modified, or reconstructed sources that amended and expanded 2012 regulations for the oil and gas sector by, among other things, setting emission limits for volatile organic compounds (“VOCs” or “VOC”) and methane, a GHG, and added requirements for previously unregulated sources. The 2016 NSPS requires reduction of methane and VOCs from certain activities in oil and gas production, processing, transmission and storage and applies to facilities constructed, modified, or reconstructed after September 18, 2015. The regulation requires, among other things, GHG and VOC emission limits for certain equipment, such as centrifugal compressors and reciprocating compressors; semi-annual leak detection and repair for well sites and quarterly for boosting and garnering compressor stations and gas transmission compressor stations; control requirements and emission limits for pneumatic pumps; and additional requirements for control of GHGs and VOCs from well completions. In September 2020, the EPA finalized amendments to the 2012 and 2016 NSPS that removed transmission and storage infrastructure from regulation of methane emissions and other VOCs, as well as removed methane control requirements. The portion of the 2020 amendments that removed the transmission and storage infrastructure from the regulations was disapproved by the Congressional Review Act in 2021. In November 2021, the EPA proposed to expand the requirements of the 2012 and 2016 NSPS and also include requirements for states to develop performance standards to control methane emissions from existing sources. In December 2022, the EPA issued a supplemental proposal to update, strengthen, and expand the 2021 proposed rules. The EPA finalized the rule in December 2023. In March 2024, the EPA announced a final rule that implemented a waste emissions charge and new reporting requirements for facilities and wells completed after May 7, 2024. On March 14, 2025, President Trump signed a joint resolution of disapproval under the Congressional Review Act, voiding the EPA’s final rule on methane waste emission, and in July 2025, the EPA announced an interim final rule that extends deadlines for certain provisions related to facilities and wells.

States are also required to comply with the NAAQS. The oil and gas sector is often subjected to additional controls when areas within states are not attaining the ozone NAAQS as the VOCs emitted by the oil and gas sector are a precursor to ozone formation. The ozone NAAQS was set at 70 parts per billion (“ppb”) in 2015. In 2023, the EPA announced its plan to perform a full and complete review of the ozone NAAQS. The results of this review could result in changes to the ozone NAAQS which, if lowered, may result in additional actions by states requiring further emission controls and associated costs. Oil and gas facilities operating in areas that are determined to be out of compliance with the 70 ppb requirement or a lowered ozone NAAQS may be subject to increased emission controls and associated costs of compliance. In March of 2025, the EPA announced it was revisiting the Biden PM2.5 NAAQS and that it was planning on releasing guidance to increase flexibility of NAAQS implementation, reforms to the New Source Review, and direction on permitting obligations.

The United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs and many of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal. In addition, certain international agreements seek to limit and reduce GHGs globally, including the Global Methane Pledge announced at the United Nations Climate Change Conference in Glasgow that aims to reduce methane emissions by 30 percent compared with 2020 levels.

The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances, or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition, and results of operations. Judicial challenges to new regulatory measures are likely and we cannot predict the outcome of such challenges. New regulatory suspensions, revisions, or rescissions and conflicting state and federal regulatory mandates may inhibit our ability to accurately forecast the costs associated with future regulatory compliance. Finally, scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere produce climate changes that likely have significant physical effects, such as increased frequency and severity of storms, droughts, floods, and other climatic events. Such effects could have an adverse effect on our financial condition and results of operations.

In terms of opportunities, the regulation of GHG emissions and the introduction of alternative incentives, such as enhanced oil recovery, carbon sequestration, and low carbon fuel standards, could benefit us in a variety of ways. For example, although federal regulation and climate change legislation could reduce the overall demand for the oil and gas that we produce, the relative demand for gas may increase because the burning of gas produces lower levels of emissions than other readily available fossil fuels such as oil and coal. In addition, if renewable resources such as wind or solar power become more prevalent, gas-fired electric plants may provide an alternative backup to maintain consistent electricity supply. Also, if states adopt low-carbon fuel standards, gas may become a more attractive transportation fuel. For the years ended December 31, 2025, and 2024, approximately 33 percent and 37 percent, respectively, of our production on a per BOE basis was gas. Market-based incentives for the capture and storage of carbon dioxide in underground reservoirs, particularly in oil and gas reservoirs, could also benefit us through the potential to obtain GHG emission allowances or offsets from or government incentives for the sequestration of carbon dioxide. For additional information about climate change, air quality, and related environmental matters, refer to Risk Factors – Risks Related to Litigation and Government Regulations – Legislative and regulatory initiatives and litigation related to global warming and climate change could have an adverse effect on our operations and the demand for oil, gas, and NGLs, and could result in significant litigation, capital, and related expenses and Federal and state regulatory initiatives relating to air quality and greenhouse gas emissions could result in increased costs and additional operating restrictions or delays.

Non-GAAP Financial Measures

Adjusted EBITDAX represents net income (loss) before interest expense, interest income, income taxes, depletion, depreciation, and amortization expense, exploration expense, property abandonment and impairment expense, non-cash stock-based compensation expense, derivative gains and losses net of settlements, gains and losses on divestitures, gains and losses on extinguishment of debt, and certain other items. Adjusted EBITDAX excludes certain items that we believe affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that we believe provides useful additional information to investors and analysts, as a performance measure, for analysis of our ability to internally generate funds for exploration, development, acquisitions, and to service debt. We are also subject to financial covenants under our Credit Agreement. In addition, adjusted EBITDAX is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. Adjusted EBITDAX should not be considered in isolation or as a substitute for net income (loss), income (loss) from operations, net cash provided by operating activities, or other profitability or liquidity measures prepared under GAAP. Because adjusted EBITDAX excludes some, but not all items that affect net income (loss) and may vary among companies, the adjusted EBITDAX amounts presented may not be comparable to similar metrics of other companies. Our revolving credit facility provides a material source of liquidity for us. Under the terms of our Credit Agreement, if we failed to comply with the covenants that establish a maximum permitted ratio of total funded debt, as defined in the Credit Agreement, to adjusted EBITDAX, we would be in default, an event that would prevent us from borrowing under our revolving credit facility and would therefore materially limit a significant source of our liquidity. In addition, if we are in default under our revolving credit facility and are unable to obtain a waiver of that default from our lenders, lenders under that facility and under the indentures governing each series of our outstanding Senior Notes would be entitled to exercise all of their remedies for default. Refer to Note 5 – Long-Term Debt in Part II, Item 8 of this report, for definition of and further detail about our Credit Agreement.

The following table provides reconciliations of our net income (GAAP) and net cash provided by operating activities (GAAP) to adjusted EBITDAX (non-GAAP) for the periods presented:

(in millions)

(1) Stock-based compensation expense is a component of the exploration expense and general and administrative expense line items on the accompanying statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the accompanying statements of operations for the component of stock-based compensation expense recorded to exploration expense.

(2) For the year ended December 31, 2024, amount excludes certain capital expenditures related to one well deemed non-commercial.

The information required by this Item is provided under the captions Interest Rate Risk and Commodity Price Risk in Item 7 above, as well as under the section entitled Summary of Oil, Gas, and NGL Derivative Contracts in Place in Note 7 – Derivative Financial Instruments in Part II, Item 8 of this report and is incorporated herein by reference.

Evaluation of Disclosure Controls and Procedures

We maintain a system of disclosure controls and procedures that are designed to reasonably ensure that information required to be disclosed in our SEC reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and to reasonably ensure that such information is accumulated and communicated to our management, including our Chief Executive Officer (Principal Executive Officer) and our Chief Financial Officer (Principal Financial Officer), as appropriate, to allow for timely decisions regarding required disclosure.

Our management, including our Chief Executive Officer and our Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) (“Disclosure Controls”) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant.

An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our Disclosure Controls are effective at a reasonable assurance level.

Changes in Internal Control Over Financial Reporting

There have been no changes to our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the fourth quarter of 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management’s Report on Internal Control over Financial Reporting

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. The Company’s internal control over financial reporting includes those policies and procedures that:

(i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;

(ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and

(iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that have a material effect on the financial statements.

Because of the inherent limitations, internal controls over financial reporting may not prevent or detect misstatements. Even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of the changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2025. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (2013 framework).

Based on management’s assessment and those criteria, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2025.

The Company’s independent registered public accounting firm has issued an attestation report on the Company’s internal control over financial reporting. That report immediately follows this report.

Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of SM Energy Company

Opinion on Internal Control Over Financial Reporting

We have audited SM Energy Company and subsidiaries’ internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, SM Energy Company and subsidiaries (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the 2025 consolidated financial statements of the Company and our report dated February 26, 2026 expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP

Denver, Colorado

February 26, 2026