10-K – 2026-02-25 – fang-20251231.htm

In addition to PHMSA regulation, we are subject to the requirements of OSHA and comparable state statutes, whose purpose is to protect the health and safety of workers. Moreover, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. Rattler LLC and the entities in which it owns an interest are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above specified thresholds, or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal boiling point without the benefit of chilling or refrigeration are exempt from these standards. Also, the Department of Homeland Security and other agencies such as the EPA continue to develop regulations concerning the security of industrial facilities, including crude oil and natural gas facilities. We are subject to a number of requirements and must prepare Federal Response Plans to comply. We must also prepare Risk Management Plans under the regulations promulgated by the EPA to implement the requirements under the CAA to prevent the accidental release of extremely hazardous substances. We have an internal program of inspection designed to monitor and enforce compliance with safeguard and security requirements. We believe that we are in compliance in all material respects with all applicable laws and regulations relating to safety and security.

State Regulation. Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

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Operational Hazards and Insurance

The oil and natural gas industry involves a variety of operating risks, including the risk of fire, explosions, blow outs, pipe failures and, in some cases, abnormally high pressure formations which could lead to environmental hazards such as oil spills, natural gas leaks and the discharge of toxic gases. If any of these should occur, we could incur legal defense costs and could be required to pay amounts due to injury, loss of life, damage or destruction to property, natural resources and equipment, pollution or environmental damage, regulatory investigation and penalties and suspension of operations.

In accordance with what we believe to be industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We currently have insurance policies for onshore property (oil lease property/production equipment) for selected locations, control of well protection for all wells, comprehensive general liability, commercial automobile, workers compensation, pollution liability (claims made coverage with a policy retroactive date and occurrence-based coverage for sudden, accidental releases), excess umbrella liability and other coverage.

Our insurance is subject to certain exclusions and limitations, and there is no assurance that such coverage will fully or adequately protect us against liability from all potential consequences, damages and losses. Any of these operational hazards could cause a significant disruption to our business. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. See Item 1A. Risk Factors of this report for additional information regarding operating hazard and uninsured risks.

We reevaluate the purchase of insurance, policy terms and limits annually. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations.

Generally, we also require our third-party vendors to sign master service agreements in which they agree to indemnify us for property damage and injuries and deaths of the service provider’s employees as well as contractors and subcontractors hired by the service provider.

Human Capital

We have built a culture grounded upon the solid foundation of our core values—leadership, integrity, excellence, people and teamwork—which guide how we operate across the organization. We set high expectations for all of our employees in terms of how they operate and interact, in the office, in the field and in the community. We challenge them to identify new ways to foster a better future for themselves and for our organization. Our board of directors, through its Safety, Sustainability and Corporate Responsibility Committee (the “SS&CR Committee”), provides an important oversight of our human capital management strategy, including on issues of diversity, equity and inclusion. The SS&CR Committee receives regular updates from our executive leadership, senior management and third-party consultants on human capital trends and other key human capital matters impacting our business.

We ended the year 2025 with 1,762 full-time employees. None of our full-time employees are represented by labor unions or covered by any collective bargaining agreements. In addition, we engage independent contractors and consultants in land, technical, regulatory and other disciplines to support our full-time employees.

Equal Opportunity, Recruiting and Retention

Equal employment opportunity is a core principle of our organization. We are committed to attracting and retaining top talent and fostering a respectful work environment. Our employment decisions are guided by merit, qualifications, competencies and demonstrated contributions in compliance with all applicable laws. We value the diverse perspectives, experiences and ideas contributed by employees from a wide range of ethnic, cultural and ideological backgrounds. As of December 31, 2025, approximately 25% of our employees are women and 40% self-identify as ethnic minorities. To further support transparency around our workforce demographics, we disclosed our 2024 Equal Employment Opportunity data in our 2025 Corporate Sustainability Report.

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In 2025, we expanded our recruitment efforts, with a particular focus on college recruitment and internship programs. We collaborated with several student organizations to reinforce this inclusive initiative, which will continue in the future. Our focus on military recruiting and partnerships with two-year technical schools for technical talent remain a priority for field operations. In addition, we have focused on recruiting experienced hires to target and retain top industry talent. In 2025, our total attrition rate was approximately 19%, which includes our remaining Endeavor Energy Resources integration efforts and asset divestitures. Excluding these factors, our adjusted attrition rate was approximately 8%. We believe our ability to retain talent is supported by our corporate culture, which emphasizes diversity and inclusion, teamwork and a strong commitment to employee development and career advancement.

Health and Safety

Protecting employees, the public and the environment is a top priority in our operations and in the way we manage our assets. We are focused on minimizing the risk of workplace incidents and preparing for emergencies. We also strive to comply with all applicable health, safety and environmental standards, laws and regulations.

We have committed to reduce injuries and fatalities in our business and are focused on safety culture improvements, safety leadership actions and human performance principles. We require our operational employees and independent contractors and their employees to go through orientation and training aligned with the International Association of Oil and Gas Producers Life Saving Rules, a program that also meets the operational safety requirements adopted by the American Petroleum Institute. We also involve employees from all operational levels in our safety program to provide input and suggested improvements to the overall safety program, recommend preventative measures based on reviewing vehicle and personnel incidents, perform safety and environmental audits at operational locations and participate in the audit and oversight of the Diamondback Hazard Communication Program.

Since inception, we have had no employee work-related fatalities. Our employee OSHA recordable cases, comprising work-related injuries and illnesses that require medical treatment beyond first aid, totaled 11 in 2025, consistent with 11 in 2024. Our employee total recordable incident rate (TRIR) was 0.62 in 2025, down from 0.82 in 2024, and lost-time incident rate was 0.45 in 2025 consistent with 0.45 in 2024. At December 31, 2025, we had a short-term goal of maintaining an employee TRIR of 0.25 or less.

Training and Development

We support employees in pursuing training opportunities to expand their professional skills. Our internal course offerings in 2025 included a wide array of topics in addition to extensive safety and other compliance training sessions. Additionally, our people undergo training and education each year on regulatory compliance, industry standards and innovative opportunities to effectively manage the challenges of developing our resources. We have also implemented development programs that are designed to build leadership capabilities at all levels.

Our Facilities

Our corporate headquarters is located at the Fasken Center in Midland, Texas, and we own office space in Oklahoma City, Oklahoma. We also lease additional office space in Dallas, Texas.

Availability of Company Reports

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports are available free of charge on the Investor Relations page of our website at www.diamondbackenergy.com as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. Information contained on, or connected to, our website is not incorporated by reference into this Annual Report and should not be considered part of this or any other report that we file with or furnish to the SEC. Reports filed or furnished with the SEC are also made available on its website at www.sec.gov.

ITEM 1A. RISK FACTORS

The nature of our business activities subjects us to certain hazards and risks. The following is a summary of the material risks relating to our business activities. We could also face additional risks and uncertainties not currently known to us or that we currently deem to be immaterial. If any of these risks actually occurs, it could materially harm our business, financial condition or results of operations and the trading price of our shares could decline.

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The following is a summary of the principal risks that could adversely affect our business, operations and financial results:

Risks Related to the Oil and Natural Gas Industry and Our Business

• Geopolitics and market conditions, and particularly volatility in prices for oil and natural gas, may adversely affect our revenue, cash flows, profitability, growth, production and the present value of our estimated reserves.
• Our commodity price derivatives could result in financial losses, may fail to protect us from declines in commodity prices, prevent us from fully benefiting from commodity price increases and may expose us to other risks, including counterparty credit risk.
• Changes in U.S. trade policy and the impact of tariffs may have a material adverse impact on our business and results of operations.
• Risks relating to the transition to a low carbon economy could impose new costs on our operations that may have a material and adverse effect on us.
• Changing political and social perspectives on climate change and other environmental, social and governance factors
may create risks and uncertainties impacting our business.
• Our targets related to sustainability and emissions reduction initiatives, including our public statements and disclosures regarding them, may expose us to numerous risks.
• Our success depends on developing our existing leasehold acreage and finding, developing or acquiring additional reserves.
• We may be unable to obtain needed capital or financing on satisfactory terms or at all to fund our acquisitions, exploration or development activities.
• Our failure to successfully identify, complete and integrate pending and future acquisitions of properties or businesses could reduce our earnings.
• Our identified potential drilling locations are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
• We may fail to meet our obligations to deliver specified quantities of oil under our oil purchase contracts.
• The loss of one or more of our customers or their inability to meet their obligations may adversely affect our financial results.
• Our method of accounting for investments in oil and natural gas properties may result in impairment of asset value.
• Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
• The standardized measure of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved reserves.
• We are vulnerable to risks associated with our primary operations concentrated in a single geographic area.
• If transportation or other facilities, certain of which we do not control, or rigs, equipment, raw materials, supplies, oilfield services or personnel become unavailable or too costly, our operations could be interrupted and our revenues reduced.
• Restrictions on our ability to obtain water and dispose of produced water, and additional monitoring and reporting requirements related to existing and new produced water disposal wells in the Permian Basin could adversely impact our business, results of operations and financial condition.
• Our planned exploratory drilling in existing or emerging shale plays is subject to risks associated with drilling and completion techniques.
• Our operations are subject to various governmental laws and regulations which require compliance that can be burdensome and expensive.
• U.S. tax legislation may negatively affect our business, results of operations, financial condition and cash flow.
• We operate in areas of high industry activity, which may affect our ability to hire, train or retain qualified personnel needed to manage and operate our assets.
• Operating hazards and uninsured risks may result in substantial losses and could prevent us from realizing profits.
• We may not be able to keep pace with technological developments in our industry.
• Our operations depend heavily on electrical power, internet and telecommunication infrastructure and information and computer systems. If any of these systems are compromised or unavailable, our business could be adversely affected.
• Legal proceedings brought against us could result in substantial liabilities and materially and adversely impact our financial condition.
• Failure to comply with cybersecurity and data privacy laws and regulations could have a material effect on our reputation, results of operations or financial loss.
• Following the closing of the Endeavor Acquisition, the Endeavor equityholders have the ability to significantly influence our business, and their interest in our business may be different from that of other stockholders.

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Risks Related to Our Indebtedness

• Our substantial level of indebtedness could adversely affect our results of operations, business flexibility and our ability to service our debt.
• A downgrade in our debt ratings could restrict our access to, and negatively impact the terms of, current or future financings or trade credit.

Risks Related to Our Common Stock

• The declaration of dividends and any repurchases of our common stock are each within the discretion of our board of directors, and there is no guarantee that we will pay any dividends on or repurchases of our common stock in the future or at levels anticipated by our stockholders.
• A change of control could limit our use of net operating losses and certain other tax attributes.
• We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.
• Provisions in our certificate of incorporation and bylaws and Delaware law make it more difficult to effect a change in control of the company, which could adversely affect the price of our common stock.
• The provision of our certificate of incorporation and bylaws requiring exclusive venue in the Court of Chancery in the State of Delaware for certain types of lawsuits may have the effect of discouraging lawsuits against us and our directors, officers and employees.

Risks Related to the Oil and Natural Gas Industry and Our Business

Geopolitics and market conditions for oil and natural gas, and particularly volatility in prices for oil and natural gas, have in the past adversely affected, and may in the future adversely affect, our revenue, cash flows, profitability, growth, production and the present value of our estimated reserves.

Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend significantly upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including the domestic and foreign supply of oil and natural gas; the level of prices and expectations about future prices of oil and natural gas; the level of global oil and natural gas exploration and production; the cost of exploring for, developing, producing and delivering oil and natural gas; the price and quantity of foreign imports; political and economic conditions in oil producing countries; regional conflicts and political instability; the continued threat of terrorism, including attacks targeting oil and gas facilities and the impact of military and other action; the ability of members of OPEC+ to agree to and maintain oil price and production controls; speculative trading in crude oil and natural gas derivative contracts; the level of consumer product demand; extreme weather conditions and other natural disasters; risks associated with operating drilling rigs; technological advances affecting energy consumption; the price and availability of alternative fuels; domestic and foreign governmental regulations and taxes; global or national health concerns, including the outbreak of pandemic or contagious disease; the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities; and overall domestic and global economic conditions. Our results of operations may also be adversely impacted by any future government rule, regulation or order that may impose production limits, as well as pipeline capacity and storage constraints, in the Permian Basin where we operate.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. From the beginning of 2023 through the end of 2025, WTI prices ranged from $55.27 to $93.68 per Bbl and the Henry Hub price of natural gas ranged from $1.58 to $5.29 per MMBtu. If the prices of oil and natural gas decline, our production, proved reserves and cash flows are likely to be adversely impacted.

Our commodity price derivatives could result in financial losses, may fail to protect us from declines in commodity prices, prevent us from fully benefiting from commodity price increases and may expose us to other risks, including counterparty credit risk.

We use commodity price derivatives, which have historically included swaps, basis swaps, swaptions, roll hedges, costless collars, puts and basis puts, to reduce price volatility associated with certain of our oil, natural gas and natural gas liquids sales. Currently, we have hedged a portion of our estimated 2026 and 2027 production. To the extent that the prices of oil, natural gas and natural gas liquids remain at current levels or decline further, we may not be able to economically hedge additional future production at the same level as our current commodity price derivatives, and our results of operations and financial condition may be negatively impacted. While these commodity price derivatives are intended to mitigate risk from
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commodity price volatility, we may be prevented from fully realizing the benefits of increases in the prices of oil, natural gas and natural gas liquids above the price levels of the commodity price derivatives used to manage price risk.

At settlement, market prices for commodities may exceed the contract prices in our commodity price derivatives agreements, resulting in our need to make significant cash payments to our counterparties. Further, by using commodity derivative instruments, we expose ourselves to credit risk if we are in a positive position at contract settlement and the counterparty fails to perform under the terms of the derivative contract. We do not require collateral from our counterparties.

Additionally, U.S. and non‑U.S. derivatives reforms (including the Dodd‑Frank Act) impose clearing, margin and other requirements. While we do not expect material direct effects, our counterparties’ compliance could increase our hedging costs, limit instrument availability, and heighten counterparty credit exposure, leading to greater earnings and cash flow volatility. These regulations could also depress commodity prices, further reducing our revenues.

For additional information regarding our outstanding derivative contracts as of December 31, 2025, see Note 12— Derivatives in Item 8. Financial Statements and Supplementary Data, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 7A. Quantitative and Qualitative Disclosures About Market Risk —Commodity Price Risk of this report.

Changes in U.S. trade policy and the impact of tariffs may have a material adverse effect on our business and results of operations.

Our business and results of operations may be adversely affected by uncertainty and changes in U.S. trade policies, including tariffs, trade agreements or other trade restrictions imposed by the U.S. or other governments. The recent uncertainty over such policies has caused substantial volatility in commodity, capital and financial markets, increased concerns over domestic and global inflation and adversely impacted consumer confidence in the U.S. and worldwide.

Tariffs or other trade restrictions may lead to continuing uncertainty and volatility in U.S. and global financial and economic conditions and commodity markets, declining consumer confidence, significant inflation and diminished expectations for the economy, and ultimately reduced demand for oil and natural gas. Such conditions could have a material adverse impact on our business, results of operations and cash flows. Also, disruptions and volatility in the financial markets may lead to adverse changes in the availability, terms and cost of capital. Such adverse changes could increase our costs of capital and limit our access to external financing sources to fund acquisitions, repurchases of securities or other capital requirements.

Changes in tariffs and trade restrictions can be announced with little or no advance notice. The adoption and expansion of tariffs or other trade restrictions, increasing trade tensions, or other changes in governmental policies related to taxes and tariffs, are difficult to predict, which makes attendant risks difficult to anticipate and mitigate. If we are unable to navigate further changes in U.S. or international trade policy, it could have a material adverse impact on our business and results of operations.

Risks relating to the transition to a low carbon economy could impose new costs on our operations that may have a material and adverse effect on us.

Governmental and regulatory bodies, investors, consumers, industry and other stakeholders have evolving and varied views on climate change matters in recent years. Such views, together with changes in consumer and industrial/commercial behavior, preferences and attitudes with respect to the generation and consumption of energy, the use of hydrocarbons, and the use of products manufactured with, or powered by, hydrocarbons, may result in: (i) the enactment of new or evolving climate change-related regulations, policies and initiatives by governments, investors, and other companies, including alternative energy or “zero carbon” requirements and fuel or energy conservation measures; (ii) technological advances with respect to the generation, transmission, storage and consumption of energy (including advances in battery technology); (iii) variability in demand from consumers and industry for energy sources other than oil and natural gas (including wind, solar, nuclear, and geothermal sources as well as electric vehicles); and (iv) development of, and variable demand from consumers and industry for, lower-emission products and services (including electric vehicles and renewable residential and commercial power supplies) as well as more efficient products and services.

Any of these developments may reduce the demand for products manufactured with (or powered by) hydrocarbons and the demand for, and in turn the prices of, the oil and natural gas that we produce and sell, which would likely have a material adverse impact on us. If any of these developments reduce the desirability of participating in the oilfield services, midstream or downstream portions of the oil and gas industry, then these developments may also reduce the availability to us of necessary third-party services and facilities that we rely on, which could increase our operational costs and adversely affect
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our ability to explore for, produce, transport and process oil and natural gas and successfully carry out our business and financial strategy.

The enactment of climate change-related regulations, policies and initiatives may also result in increases in our compliance costs and other operating costs and have other adverse effects, such as a greater potential for governmental investigations or litigation. For further discussion regarding the risks to us of climate change-related regulations, policies and initiatives, please see the section entitled Items 1 and 2. Business and Properties—Regulation —Climate Change of this report.

In addition to potentially reducing demand for our oil and natural gas and potentially reducing the availability of oilfield services and midstream and downstream customers, further regulatory or other climate change incentives, to the extent they continue, may create investment and reputational risks associated with the exploration for, and production of, hydrocarbons, which may adversely affect the availability and cost to us of capital. Certain stakeholders and capital providers may seek to restrict or seek to impose stringent conditions with respect to their investment in or financing of certain carbon intensive sectors, which could result in capital being unavailable to us, or only at significantly increased costs.

Changing political and social perspectives on climate change and other environmental, social and governance factors may create risks and uncertainties impacting our business.

We may not be able to meet evolving expectations of stakeholders, including governmental officials, standard setters, investors, employees, and customers, relating to climate change, human capital, and other ESG issues. For example, while some policymakers, including the European Union and the State of California, have adopted disclosure and other requirements relating to ESG matters, other policymakers have sought to constrain companies’ consideration of such matters. Further, shareholders have sought to effect changes to public companies’ businesses or governance to deal with climate change-related issues through shareholder proposals, public campaigns, proxy solicitations or other actions. Any such future actions may result in significant management distraction and potentially significant expense.

Additionally, cities, counties, and other governmental entities in several states in the U.S. have filed lawsuits against energy companies seeking damages allegedly associated with climate change. Similar lawsuits may be filed in other jurisdictions. If any such lawsuits were to be filed against us, whether due to our activities or the activities of the acquired entities or operations prior to their acquisition by us, we could incur substantial legal defense costs and, if any such litigation were adversely determined, we could incur substantial damages.

Any of these climate change-related litigation risks could result in unexpected costs, negative sentiments about our company, disruptions in our operations, and increases to our operating expenses, which in turn could have an adverse effect on our business, financial condition and results of operations.

Our targets related to sustainability and emissions reduction initiatives, including our public statements and disclosures regarding them, may expose us to numerous risks.

We have developed, and will continue to develop, targets related to our ESG initiatives, including our emissions reduction targets and strategy. Statements in this and other reports we file with the SEC and other public statements related to these initiatives reflect our current plans and expectations and are not a guarantee the targets will be achieved or achieved on the currently anticipated timeline. Our ability to achieve our ESG targets, including emissions reductions, is subject to numerous factors and conditions, some of which are outside of our control, and failure to achieve our announced targets or comply with ethical, environmental or other standards, including reporting standards, may expose us to government enforcement actions or private litigation and adversely impact our business. Further, our continuing efforts to research, establish, accomplish and accurately report on these targets may create additional operational risks and expenses and expose us to reputational, legal and other risks.

Further, in response to the evolving regulatory environment and investor expectations, or due to our acquisitions of other companies or assets, we may, periodically, make adjustments to our environmental targets or goals. If we do not, or are perceived to not, adapt or comply with certain investor or stakeholder expectations and standards on ESG matters, we may suffer from reputational damage and our business, financial condition and results of operations could be materially and adversely affected. Any reputational damage associated with ESG factors may also adversely impact our ability to recruit and retain employees and customers.

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Our success depends on developing our existing leasehold acreage and finding, developing or acquiring additional reserves.

A significant portion of our net leasehold acreage is undeveloped, or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. In addition, many of our oil and natural gas leases require us to drill wells that are commercially productive and to maintain the production in paying quantities, and if we are unsuccessful in drilling such wells and maintaining such production, we could lose our rights under such leases. Our future oil and natural gas reserves and production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage.

Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production in paying quantities is established within the spacing units covering the undeveloped acres. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. Any reduction in our current drilling program, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the loss of acreage through lease expirations. Any non-renewal or other loss of leases could materially and adversely affect the growth of our asset basis, cash flows and results of operations.

We use 2-D and 3-D seismic data to identify the presence of oil and natural gas. Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures.

Additionally, our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. To increase reserves and production, we undertake development, exploration and other replacement activities or use third parties to accomplish these activities. If we are unable to replace our current production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected.

Our development and exploration operations and our ability to complete acquisitions require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a loss of properties and a decline in our oil and natural gas reserves.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration for and development, production and acquisition of oil and natural gas reserves. In 2025, our total cash capital expenditures were approximately $3.5 billion. Our 2026 cash capital budget is currently estimated to be approximately $3.60 billion to $3.90 billion, representing an increase at the midpoint of 6% from our 2025 capital expenditures.

We intend to finance our future capital expenditures with cash flow from operations, while future acquisitions may also be funded from operations as well as proceeds from offerings of our debt and equity securities and borrowings under our revolving credit facility. Our cash flow from operations and access to capital are subject to a number of variables, including our proved reserves; the volume of oil and natural gas we are able to produce from existing wells; the prices at which our oil and natural gas are sold; our ability to acquire, locate and produce economically new reserves; and our ability to borrow under our credit facility.

We cannot assure you that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Further, our actual capital expenditures in 2026 could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount of capital we have available, we could be required to seek additional sources of capital, which may include traditional reserve base borrowings, debt financing, joint venture partnerships, sales of assets, offerings of debt or equity securities or other means. We cannot assure you that we will be able to obtain debt or equity financing on terms favorable to us, or at all.

If we are unable to fund our capital requirements or our costs of capital increase, we may be required to curtail our operations relating to the exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves, or we may be otherwise unable to implement our development plan, complete acquisitions or take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations. In addition, a delay in or the
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failure to complete proposed or future infrastructure projects could delay or eliminate potential efficiencies and related cost savings.

In addition, approximately 30% of our total estimated proved reserves as of December 31, 2025, were proved undeveloped reserves and may not be ultimately developed or produced. The reserve data included in the reserve reports of our independent petroleum engineers assume that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or further decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.

Our failure to successfully identify, complete and integrate pending and future acquisitions of properties or businesses could reduce our earnings and slow our growth.

There is intense competition for acquisition opportunities in our industry. The successful acquisition of producing properties requires an assessment of several factors, including recoverable reserves, future oil and natural gas prices and their applicable differentials, operating costs, and potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain, and we may not be able to identify attractive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems, including title defects or environmental issues, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Environmental or other regulatory issues may arise with respect to acquired entities or operations years after the acquisitions. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.

Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. If these acquisitions include geographic regions in which we do not currently operate, we could be subject to unforeseen operating difficulties and difficulties in coordinating geographically dispersed operations, personnel and facilities. In addition, if we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Further, the success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions.

Any of these factors could have a material adverse effect on our financial condition and results of operations. Our financial position and results of operations may also fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.

Our identified potential drilling locations, which are part of our anticipated future drilling plans, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

Drilling for oil and natural gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then realized prices after deducting drilling, operating and other costs.

As of December 31, 2025, we have approximately 8,854 gross (6,541 net) identified economic potential horizontal drilling locations in multiple horizons on our acreage at an assumed price of approximately $50.00 per Bbl WTI. As of December 31, 2025, only 1,351 of our gross identified economic potential horizontal drilling locations in which we have a working interest were attributed to proved reserves. These drilling locations, including those without proved undeveloped reserves, represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, unusual or unexpected geological
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formations, title problems, facility or equipment malfunctions, unexpected operational events, inclement weather, environmental and other regulatory requirements and approvals, oil and natural gas prices, costs, drilling results and the availability of water. Further, our identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. In addition, as of December 31, 2025, we have identified approximately 1,901 horizontal drilling locations in intervals in which we have drilled very few or no wells, which are necessarily more speculative and based on results from other operators whose acreage may not be consistent with ours. We cannot predict in advance of drilling and testing whether any particular drilling location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. Through December 31, 2025, we are the operator of, have participated in, or have acquired working interest in a total of 6,677 horizontal producing wells completed on our acreage. We cannot assure you that the analogies we draw from available data from these or other wells, more fully explored locations or producing fields will be applicable to our drilling locations. Further, initial production rates reported by us or other operators in the Permian Basin may not be indicative of future or long-term production rates. Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

We may fail to meet our obligations to deliver specified quantities of oil under our oil purchase contracts, which will result in deficiency payments to the counterparty and may have an adverse effect on our operations.

We are a party to long-term crude oil agreements under which, subject to certain terms and conditions, we are obligated to deliver specified quantities of oil to our counterparties. Our maximum delivery obligation under these agreements varies for different periods and depends in some cases upon certain conditions beyond our control. If production from our Permian Basin acreage decreases due to reduced developmental activities, as a result of the low commodity price environment, production related difficulties or otherwise, we may be unable to meet our obligations under our oil purchase agreements, which may result in deficiency payments to certain counterparties or a default under such agreements and may have an adverse effect on our company.

The loss of one or more of our customers or their inability to meet their obligations may adversely affect our financial results.

In addition to credit risk related to receivables from commodity derivative contracts, our principal exposure to credit risk is through receivables from joint interest owners on properties we operate and receivables from purchasers of our oil and natural gas production. Joint interest receivables arise from billing entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We are generally unable to control which co-owners participate in our wells.

We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. See Items 1 and 2. Business and Properties—Marketing and Customers of this report for additional information regarding these customers. This concentration of customers may impact our overall credit risk in that these entities may be similarly affected by any adverse changes in economic and other conditions. We do not require our customers to post collateral. Under certain circumstances, the amounts due to them can be offset by any unpaid receivables. The loss of one or more of these customers, our inability to sell our production to other customers on terms we consider acceptable, the inability or failure of our significant customers or joint working interest owners to meet their obligations to us or their insolvency or liquidation may materially adversely affect our financial results.

Our method of accounting for investments in oil and natural gas properties may result in impairment of asset value.

We account for our oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals, are capitalized. We also capitalize direct operating costs for services performed with internally owned drilling and well servicing equipment.

The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment,
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exceed the discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense. We use the unweighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date in estimating discounted future net revenues.

An impairment on proved oil and natural gas properties of approximately $3.7 billion was recorded for the year ended December 31, 2025. No impairments were recorded on our proved oil and natural gas properties for the years ended December 31, 2024 and 2023. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates —Oil and Natural Gas Accounting and Reserves of this report. If the prices of oil and natural gas decline, we may be required to further write-down the value of our oil and natural gas properties in the future, which could negatively affect our results of operations.

Our estimated reserves and EURs are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

Oil and natural gas reserve engineering is not an exact science and requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, ultimate recoveries and operating and development costs. As a result, estimated quantities of proved reserves, projections of future production rates and the timing of development expenditures may be incorrect. The EURs for our horizontal wells are based on management’s internal estimates. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing and production. Also, certain assumptions regarding future oil and natural gas prices, production levels and operating and development costs may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of future net cash flows. A substantial portion of our reserve estimates are made without the benefit of a lengthy production history, and are less reliable than estimates based on a lengthy production history. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil and natural gas that we ultimately recover being different from our reserve estimates. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved undeveloped acreage. The reserve estimates represent our net revenue interest in our properties.

The timing of both our production and our incurrence of costs in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves.

The standardized measure of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved reserves.

The present value of future net cash flows from our proved reserves or standardized measure may not represent the current market value of our estimated proved reserves. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than current estimates. In addition, the 10% discount factor we use when calculating discounted future net cash flow for reporting requirements in compliance with the Financial Accounting Standard Board Codification 932, “Extractive Activities—Oil and Gas,” may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks (including weather-related risks) associated with operating in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing horizons within this area.

Our producing properties are currently geographically concentrated in the Permian Basin of West Texas. As a result, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of crude oil, natural gas or natural gas liquids, and extreme weather conditions and their adverse impact on production volumes, availability of electrical power, road accessibility and transportation facilities.

Extreme regional weather events may occur that can affect our suppliers or customers, which could adversely affect us. For example, a significant hurricane or similar weather event could damage refining and other oil and natural gas-related facilities on the Gulf Coast of Texas and Louisiana, which (if significant enough) could limit the availability of gathering and transportation facilities across Texas and could then cause production in the Permian Basin (including potentially our
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production) to be curtailed or shut in or (in the case of natural gas) flared. Climate change may also increase the frequency and severity of significant weather events over time. Further, any increase in flaring of our natural gas production due to weather-related events or otherwise could make it difficult for us to achieve our publicly-announced sustainability and emissions reduction targets, which could expose us to reputational risks and adversely impact our contractual and other business relationships. Any of the above-referenced events could have a material adverse effect on us and our production volumes (and therefore on our financial condition and results of operations).

In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

In addition to the geographic concentration of our producing properties described above, as of December 31, 2025, most of our proved reserves are concentrated in the Wolfberry play in the Midland Basin. This concentration of assets within a small number of producing horizons exposes us to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a field.

The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies, oilfield services or personnel may restrict our operations.

The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. In accordance with customary industry practice, we rely on independent third-party service providers to provide most of the services necessary to drill new wells. If we are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer, and we may not be able to drill all of our acreage before our leases expire. In addition, we do not have long-term contracts securing the use of our existing rigs, and the operators of those rigs may choose to cease providing services to us. Shortages of any of the items referenced above could delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.

Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.

Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners for use in our operations. Over the past several years, Texas has experienced extreme drought conditions. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. Also, in 2021, the Texas Legislature directed the Texas Railroad Commission to adopt rules encouraging fluid oil and gas waste recycling. On January 3, 2025, the Commission published final amendments to its water protection rules to, among other things, encourage waste recycling. The revised rules went into effect on July 1, 2025. If we are unable to obtain water to use in our operations from local sources, or we are unable to effectively utilize flowback water, we may be unable to economically drill for or produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows.

Recent regulatory restrictions on the disposal of produced water and additional monitoring and reporting requirements related to existing and new produced water disposal wells in the Permian Basin to stem rising seismic activity and earthquakes could increase our operating costs and adversely impact our business, results of operations and financial condition.

In September 2021, the Texas Railroad Commission curtailed the amount of produced water companies were permitted to inject into some wells near Midland and Odessa in the Permian Basin and has since indefinitely suspended some permits there and expanded the restrictions to other areas. These actions were taken in an effort to control induced seismic activity and recent increases in earthquakes in the Permian Basin, which have been linked by the U.S. and local seismologists to wastewater disposal in oil fields. The Texas Railroad Commission has since adopted rules governing the permitting or re-permitting of wells used to dispose of produced water and other fluids resulting from the production of oil and gas in order to address these seismic activity concerns within the state. Among other things, these rules require companies seeking permits
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for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells and allow the state to modify, suspend or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. These restrictions and additional monitoring and reporting requirements related to existing and new produced water and produced water disposal wells could result in increased operating costs, requiring us or our service providers to truck produced water, recycle it or dispose of it by other means, all of which could be costly. We or our service providers may also need to limit disposal well volumes, disposal rates and pressures or locations, or require us or our service providers to shut down or curtail the injection of produced water into disposal wells. These factors may make drilling activity in the affected parts of the Permian Basin less economical and adversely impact our business, results of operations and financial condition.

Part of our strategy involves drilling in existing or emerging shale plays using the latest available horizontal drilling and completion techniques; therefore, the results of our planned exploratory drilling in these plays are subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production.

Our operations involve developing and utilizing the latest drilling and completion techniques. Risks that we face while drilling include, but are not limited to, spacing of wells to maximize economic return; landing our well bore in the desired drilling zone; staying in the desired drilling zone while drilling horizontally through the formation; running our casing the entire length of the well bore; and being able to run tools and other equipment consistently through the horizontal well bore.

Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages; run tools the entire length of the well bore during completion operations; successfully clean out the well bore after completion of the final fracture stimulation stage; and prevent unintentional communication with other wells.

Furthermore, certain of the techniques we are adopting, such as infill drilling and multi-well pad drilling, may cause irregularities or interruptions in production due to, in the case of infill drilling, offset wells being shut in and, in the case of multi-well pad drilling, the time required to drill and complete multiple wells before any such wells begin producing. The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas often have limited or no production history and consequently we are less able to predict future drilling results in these areas.

Ultimately, the success of these drilling and completion techniques can only be evaluated as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, and/or declines in natural gas and oil prices, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future.

The marketability of our production is dependent upon transportation and other facilities, certain of which we do not control. If these facilities are unavailable, our operations could be interrupted and our revenues reduced.

The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of transportation facilities owned by third parties. We do not control third-party transportation facilities and our access to them may be limited or denied. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or a significant disruption in the availability of our or third-party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. For example, on certain occasions we have experienced high line pressure at our tank batteries with occasional flaring due to the inability of the gas gathering systems in the areas in which we operate to support the increased production of natural gas in the Permian Basin. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, we may be required to shut in or curtail production. In addition, the amount of oil and natural gas that can be produced and sold may be subject to curtailment in certain other circumstances outside of our control, such as pipeline interruptions due to maintenance, excessive pressure, ability of downstream processing facilities to accept unprocessed gas, physical damage to the gathering or transportation system or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months, and in many cases, we are provided with limited, if any, notice as to when these circumstances will arise and their duration. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our fields, would adversely affect our financial condition and results of operations.

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Our operations are subject to various governmental laws and regulations which require compliance that can be burdensome and expensive.

Our oil and natural gas operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation.

From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil and natural gas. In addition, the production, handling, storage, transportation, remediation, emission and disposal of oil and natural gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of human health and the environment. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, permit revocations, requirements for additional pollution controls and injunctions limiting or prohibiting some or all of our operations. Further, these laws and regulations imposed strict requirements for water and air pollution control and solid waste management. Significant expenditures may be required to comply with governmental laws and regulations applicable to us. In addition, federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. Permanent restrictions imposed to protect threatened or endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures.

Even if federal regulatory burdens temporarily ease, the historic trend of more expansive and stricter environmental legislation and regulations may continue in the long-term, and at the state and local levels. See Items 1 and 2. Business and Properties—Regulation of this report for a detailed description of certain laws and regulations that affect us.

U.S. tax legislation may adversely affect our business, results of operations, financial condition and cash flow.

From time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal income tax laws affecting the oil and natural gas industry, including (i) eliminating the immediate deduction for intangible drilling and development costs, (ii) the repeal of the percentage depletion allowance for oil and natural gas properties, and (iii) an extension of the amortization period for certain geological and geophysical expenditures. No accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. These proposed changes in the U.S. tax law, if adopted, or other similar changes that would impose additional tax on our activities or reduce or eliminate deductions currently available with respect to natural gas and oil exploration, development or similar activities, could adversely affect our business, results of operations, financial condition and cash flow.

In 2022, the IRA enacted a 15% corporate alternative minimum tax (“CAMT”) on the “adjusted financial statement income” of certain large corporations (generally, corporations reporting more than $1 billion average adjusted pre-tax net income on their consolidated financial statements) for tax years beginning after December 31, 2022. While we are subject to CAMT, we did not incur a CAMT liability for 2025.

On July 4, 2025, the One Big Beautiful Bill Act (the “OBBB”) was signed into law. Among other provisions, the OBBB provides for immediate expensing of research or experimental expenses, bonus depreciation for qualified tangible property, deductible intangible drilling costs for purposes of the CAMT, and enhancements to limits on business interest expense deductions. The OBBB also imposes limits on deductibility of charitable contributions by corporations. For 2025, the net effect of the OBBB was to accelerate our tax deductions and thus favorably affect our cash flow, but to the extent that our tax deductions may be limited or deferred by the applicable provisions of the OBBB in future periods, the amount and timing of our cash tax obligations may be adversely affected.

The U.S. Treasury Department, the Internal Revenue Service (“IRS”) and other standard-setting bodies are expected to issue additional guidance on how the CAMT and other provisions of the IRA and OBBB will be applied or otherwise administered, and such guidance may differ from our interpretations. We continue to evaluate the IRA and OBBB and their effect on our financial results and operating cash flow.
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We operate in areas of high industry activity, which may affect our ability to hire, train or retain qualified personnel needed to manage and operate our assets.

Our operations and drilling activity are concentrated in the Permian Basin in West Texas, an area in which industry activity has increased rapidly. As a result, demand for qualified personnel in this area, and the cost to attract and retain such personnel, has increased over the past few years due to competition and may increase substantially in the future. Moreover, our competitors may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer.

Any delay or inability to secure the personnel necessary for us to continue or complete our current and planned development activities could lead to a reduction in production volumes. Any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on our business, financial condition and results of operations.

In addition, many key responsibilities within our business have been assigned to a small number of employees. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our executive team could disrupt our operations. We do not have employment agreements with our executives and may not be able to assure their retention. Further, we do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.

Operating hazards and uninsured risks may result in substantial losses and could prevent us from realizing profits.

Our operations are subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, gas leaks and ruptures or discharges of toxic gases. In addition, our operations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations and repairs required to resume operations.

We endeavor to contractually allocate potential liabilities and risks between us and the parties that provide us with services and goods, which include pressure pumping and hydraulic fracturing, drilling and cementing services and tubular goods for surface, intermediate and production casing. Under our agreements with our vendors, to the extent responsibility for environmental liability is allocated between the parties, (i) our vendors generally assume all responsibility for control and removal of pollution or contamination which originates above the surface of the land and is directly associated with such vendors’ equipment while in their control, and (ii) we generally assume the responsibility for control and removal of all other pollution or contamination which may occur during our operations, including pre-existing pollution and pollution which may result from fire, blowout, cratering, seepage or any other uncontrolled flow of oil, gas or other substances, as well as the use or disposition of all drilling fluids. In addition, we generally agree to indemnify our vendors for loss or destruction of vendor-owned property that occurs in the well hole (except for damage that occurs when a vendor is performing work on a footage, rather than day work, basis) or as a result of the use of equipment, certain corrosive fluids, additives, chemicals or proppants. However, despite this general allocation of risk, we might not succeed in enforcing such contractual allocation, might incur an unforeseen liability falling outside the scope of such allocation or may be required to enter into contractual arrangements with terms that vary from the above allocations of risk. As a result, we may incur substantial losses which could materially and adversely affect our financial condition and results of operations.

In accordance with what we believe to be customary industry practice, we historically have maintained insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations or cash flow. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. We may also be liable for environmental damage caused by previous owners of properties purchased by us, which liabilities may not be covered by insurance.

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Since hydraulic fracturing activities are part of our operations, we maintain insurance to protect against claims made for bodily injury and property damage, and that insurance includes coverage for clean-up costs stemming from a sudden and accidental pollution event. However, we may not have coverage if we are unaware of the pollution event and unable to report the “occurrence” to our insurance company within the time frame required under our insurance policy. We have limited coverage for gradual, long-term pollution events. In addition, these policies do not provide coverage for all liabilities, and we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.

We may not be able to keep pace with technological developments in our industry.

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.

Additionally, the development, deployment and use of artificial intelligence (“AI”) and machine learning in our operations and those of our service providers and partners could introduce new risks, including increased exposure to cybersecurity threats and social engineering, inadvertent disclosure or misuse of confidential, proprietary or personal information, errors, bias or other unexpected outcomes in AI outputs used for operational decision‑making, and evolving and potentially divergent regulatory requirements that may restrict certain uses of AI or increase compliance costs. AI adoption may require significant investment, specialized talent and access to high‑quality data, and our competitors may adopt AI more effectively than we do. Failures or limitations in AI tools, misuse by employees or third parties, or disruptions or breaches involving AI‑enabled systems could adversely affect our business, reputation, financial condition and results of operations.

Our operations depend heavily on electrical power, internet and telecommunication infrastructure and information and computer systems. If any of these systems are compromised or unavailable, our business could be adversely affected.

We are heavily dependent on electrical power, internet and telecommunications infrastructure and our information systems and computer-based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such infrastructure, systems or programs were to fail or become unavailable or compromised, or create erroneous information in our hardware or software network infrastructure, our ability to safely and effectively operate our business will be limited and any such consequence could have a material adverse effect on our business.

Rapid growth in AI-related data centers and other high‑intensity computing is materially increasing regional electricity demand and straining grids, which—together with extreme weather conditions, intermittent renewable generation, and other market constraints—can reduce power availability, increase prices (including scarcity pricing), and cause outages. Reduced power reliability could disrupt our drilling, completion, and production activities; impair midstream operations; hinder remote monitoring and data integrity; and force suspensions or shutdowns or unplanned spending on backup power and communications, any of which could have a material adverse effect on our business and results of operations.

Legal proceedings brought against us could result in substantial liabilities and materially and adversely impact our financial condition.

Like many oil and gas companies, we are involved in various legal proceedings, including threatened claims, such as contractual, title and royalty disputes. The cost to settle legal proceedings (asserted or unasserted) or satisfy any resulting unfavorable judgment against us in such proceedings could result in a substantial liability or the loss of interests, which could materially and adversely impact our cash flows, operating results and financial condition for the period in which any such effect becomes reasonably estimable. Judgments and estimates to determine accruals or range of losses related to legal proceedings are difficult to predict and could change from one period to the next, and such changes could be material. Current accruals may be insufficient to satisfy any such judgments. Legal proceedings could also result in negative publicity about the Company. Defending these actions, especially purported class actions, can be costly and can distract management and other personnel from their primary responsibilities. In addition, many of our proceedings are in their early stages. Where this is the case, the allegations and damage theories have not been fully developed, and are all subject to inherent uncertainties. As a result, management’s view of the likelihood of a material and adverse financial impact from any such
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proceeding may change in the future. See Note 15— Commitments and Contingencies in Item 8. Financial Statements and Supplementary Data of this report.

Failure to comply with cybersecurity and data privacy laws and regulations could have a material adverse effect on our reputation, results of operations or financial condition.

We rely extensively on information technology systems and infrastructure, including but not limited to, data hosting platforms, real-time data acquisition systems, internally developed and third-party software, cloud services and other internally or externally hosted hardware and software platforms (collectively, “IT Systems”) for operational and other purposes, such as to (i) estimate our oil and natural gas reserves, (ii) process and record financial and operating data, (iii) process and analyze all stages of our business operations, including exploration, drilling, completions, production, transportation, pipelines and other related activities, and (iv) communicate with our employees and vendors, suppliers and other third parties. We own and manage certain IT Systems but also rely on third parties for a range of IT Systems and other products or services. We and certain third-party providers also collect, maintain and/or process proprietary data about our business, such as trade secrets, as well as personally identifiable information about our employees, business partners and others (collectively, “Confidential Information”).

We regularly experience attempted cyberattacks and other incidents, including phishing attacks and attacks on certain of our third-party providers, and we expect future cyberattacks and incidents to occur in varying degrees. To date, no incidents have materially affected our company, including our business strategy, results of operations or financial condition, but we cannot guarantee that material incidents will not occur in the future.

Our IT Systems and Confidential Information, and that of our vendors, service providers and other third-party providers and business partners, are vulnerable to evolving cybersecurity threats, including, without limitation, denial-of-service attacks; malicious software (e.g., ransomware); the exploitation of known and unknown misconfigurations, “bugs,” and other hardware or software vulnerabilities; data privacy breaches by employees, insiders or others with authorized access; social engineering (e.g. phishing) attacks; attempts to gain unauthorized access to our data and systems; and other electronic or physical security breaches. More recently, advancements in AI pose serious risks for many of the traditional tools used to identify individuals, including voice recognition (whether by machine or the human ear), facial recognition or screening questions to confirm identities. In addition, generative AI systems are increasingly used by malicious actors to create more sophisticated cyber-attacks (i.e., more realistic phishing or other attacks) and to circumvent controls, evade detection and even remove forensic evidence, rendering incident detection and remediation more challenging. These and other threat-related advancements expose us to increasing costs, including costs to deploy additional personnel, protection technologies and policies and procedures, train employees, and engage third-party experts and consultants. There can be no assurance that our cybersecurity risk management program, including our controls or processes, will be fully implemented, complied with or effective in protecting our IT Systems and Confidential Information. Moreover, we do not manage the security controls or processes deployed by our third-party providers, such as cloud services that support our operations, and therefore, successful cyberattacks that disrupt or result in unauthorized access to third-party IT Systems could materially impact our operations and financial results. Similarly, we have acquired and continue to acquire companies that may have cybersecurity vulnerabilities or unsophisticated measures, which exposes us to significant risk.

A significant cybersecurity attack or incident that compromises our Confidential Information or disrupts our normal operations, including our exploration, completion, production and corporate functions, could materially and adversely affect us in a variety of ways, including, but not limited to the following: exploitation of our Confidential Information such as business data, reserves information, strategic information or other sensitive or proprietary information or personal information of our employees, vendors, service providers, royalty and working interest owners, or other third parties; damage to our ability to compete for oil and gas resources or our competitive advantage over other companies; failure to reach the intended target or a drilling incident; loss of production or accidental discharges; supply chain disruptions resulting from attacks on third party providers, vendors or business partners that delay or halt our operations, result in reduced demand for our production or delay or prevent us from transporting and marketing our production, in either case resulting in a loss of revenues; a cybersecurity attack involving commodities exchanges or financial institutions could slow or halt commodities trading, thus preventing us from marketing our production or engaging in hedging activities, resulting in a loss of revenues; a deliberate corruption of our financial or operating data could result in events of non-compliance, which could then lead to regulatory enforcement actions, fines or penalties; a cybersecurity attack on a communications network or power grid, which could cause operational disruptions resulting in a loss of revenues; and a cybersecurity attack on our automated and surveillance systems, which could cause a loss of production and potential environmental hazards. We could also be subject to significant regulatory investigations and enforcement actions, fines and penalties and/or legal claims that result in a material impact to our business, operating results or financial condition.

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We maintain specialized insurance for possible liability resulting from a cyberattack on our assets, however, we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.

A variety of U.S. federal, state and international laws and regulations govern the collection, use, retention, sharing and security of personal data. All 50 states have enacted legislation on data breach notification requirements and many states continue to enact laws on matters of privacy, data protection and cybersecurity. The existing privacy-related laws and regulations are evolving and subject to potentially differing interpretations. In addition, various U.S. federal, state and foreign legislative and regulatory bodies continue to enact new laws regarding privacy and data protection, as well as expand the scope of existing laws. We cannot predict the impact of any such evolving privacy-related laws on our business, operations or financial condition, but may find it necessary to enhance our existing systems and procedures, which may involve substantial expense or distraction from other aspects of our business. In addition, any violations of applicable privacy-related laws or regulations may require us to address legal claims, sustain monetary penalties or incur other liabilities, as well as cause reputational damage, any of which could adversely impact our business, results of operations or financial condition.

Following the closing of the Endeavor Acquisition, the Endeavor equityholders have the ability to significantly influence our business, and their interest in our business may be different from that of other stockholders.

As of December 31, 2025, Endeavor’s equityholders held approximately 35.8% of our common stock. Pursuant to an agreement with the Endeavor equityholders, the Company appointed four additional directors to our board of directors of the Company. We will not be permitted to take certain actions without the consent of the holders of a majority of the shares of our common stock held by the Endeavor equityholders. The Endeavor equityholders’ level of ownership and influence may make some transactions (such as those involving mergers, material share issuances or changes in control) more difficult or impossible, which in turn could adversely affect the market price of our shares of common stock or prevent our shareholders from realizing a premium over the market price for their shares of our common stock. The interests of the Endeavor equityholders may conflict with the interests of other stockholders, including that Endeavor equityholders may decide to reduce their investment in us. Such sales of our common stock or the perception that these sales may occur could have the effect of depressing the market price for our common stock.

Risks Related to Our Indebtedness

Our substantial indebtedness could adversely affect our results of operations, business flexibility and our ability to service our debt.

We have incurred a substantial amount of debt to finance our recent acquisitions and for other corporate purposes. Our ability to make scheduled payments of the principal, to pay interest on or to refinance our indebtedness, including our senior notes, depends on our future performance, which is subject to economic, financial, competitive and other factors beyond our control. If we are unable to generate sufficient cash flow to service our debt, we may be required to adopt one or more alternatives, such as reducing or delaying capital expenditures, selling assets, restructuring debt or obtaining additional equity capital on terms that may be onerous or highly dilutive. However, we cannot assure you that alternative financing plans would be consummated on desirable terms or would be adequate to meet any debt service obligations then due.

We and our subsidiaries may be able to incur substantial additional indebtedness in the future under our current debt agreement. Our increased level of debt could have negative consequences on us, including, among other things, (i) requiring us to dedicate a larger portion of cash flow from operations to servicing and repayment of the debt, (ii) reducing funds available for strategic initiatives and opportunities, working capital and other general corporate needs, (iii) limiting our ability to incur additional indebtedness, which could restrict our flexibility to react to changes in our business, our industry and economic conditions, and (iv) placing us at a competitive disadvantage compared to our competitors that have less debt.

Certain of our debt instruments contain, and the terms of any future indebtedness may contain, restrictive covenants that limit our ability to, among other things: incur or guarantee additional indebtedness; make certain investments; create liens; sell or transfer assets; issue preferred stock; merge or consolidate with another entity; pay dividends or make other distributions; create unrestricted subsidiaries; and engage in transactions with affiliates. We and our subsidiaries may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants. If a default occurs under our revolving credit facility, the lenders thereunder may elect to declare all borrowings outstanding, together with accrued interest and other fees, to be immediately due and payable, which would result in an event of default under the indentures governing our senior notes. The lenders will also have the right in these circumstances to terminate any commitments they have to provide further borrowings.

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Lastly, our earnings are exposed to interest rate risk associated with borrowings under our and Viper’s revolving credit facilities and under our Term Loan Agreement. The terms of the term loan and revolving credit facilities provide for interest on borrowings at a floating rate equal to an alternate base rate tied to SOFR. SOFR tends to fluctuate based on multiple factors, including general short-term interest rates, rates set by the U.S. Federal Reserve and other central banks and general economic conditions. If interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition.

A downgrade in our debt ratings could restrict our access to, and negatively impact the terms of, current or future financings or trade credit.

Our ability to obtain financings and trade credit and the terms of any financings or trade credit is, in part, dependent on the credit ratings assigned to our debt by independent credit rating agencies. We cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales and near-term and long-term production growth opportunities, liquidity, asset quality, cost structure, product mix and commodity pricing levels. A ratings downgrade could adversely impact our ability to access financings or trade credit and increase our borrowing costs.

Risks Related to Our Common Stock

The declaration of base and variable dividends and any repurchases of our common stock are each within the discretion of our board of directors based upon a review of relevant considerations, and there is no guarantee that we will pay any dividends on or repurchase shares of our common stock in the future or at levels anticipated by our stockholders.

The decision to pay any future base and variable dividends is solely within the discretion of, and subject to approval by, our board of directors. Our board of directors’ determination with respect to any such dividends, including the record date, the payment date and the actual amount of the dividend, will depend upon our profitability and financial condition, contractual restrictions, restrictions imposed by applicable law and other factors that the board deems relevant at the time of such determination. Based on its evaluation of these factors, the board of directors may determine not to declare a dividend, whether base or variable, or declare dividends at rates that are less than currently anticipated, either of which could reduce returns to our stockholders.

In July 2025, our board of directors approved an increase in our common stock repurchase program to acquire up to $8.0 billion. We may be limited in our ability to repurchase shares of our common stock by various governmental laws, rules and regulations which prevent us from purchasing our common stock during periods when we are in possession of material non-public information. Through December 31, 2025, approximately $5.3 billion has been repurchased through the repurchase program. Even though this program is in place, we may not repurchase any shares through the program and any such repurchases are completely within the discretion of our board of directors. In addition, the stock repurchase program has no time limit and may be suspended, modified, or discontinued by the board of directors at any time. Any elimination of, or reduction in, the Company’s base or variable dividend or common stock repurchase program could adversely affect the total return of an investment in and have a material adverse effect on the market price of our common stock.

Despite our return of capital commitment to return at least 50% of Adjusted Free Cash Flow to stockholders, the amount of cash available to return to our stockholders, if any, can vary significantly from quarter to quarter for a number of reasons, including commodity prices, liquidity, debt levels, capital resources and other factors. The price of our common stock may deteriorate if we are unable to meet investor expectations with respect to the timing and amount of our return of capital commitment to our shareholders, and such deterioration may be material.

A change of control could limit our use of net operating losses and certain other tax attributes.

Under Sections 382 and 383 of the Internal Revenue Code of 1986, as amended (the “Code”), a corporation that experiences an “ownership change” (as defined in the Code) may be subject to limitations on its ability to offset taxable income arising after the ownership change with net operating losses (“NOLs”) and other tax attributes (such as tax credits and capital loss carryforwards) generated prior to the ownership change. In general, an ownership change occurs if there is a cumulative increase in the ownership of a corporation’s stock totaling more than 50 percentage points by one or more “5% shareholders” (as defined in the Code) at any time during a rolling three-year period. An ownership change would establish an annual limitation on the amount of a corporation’s pre-change NOLs, tax credits and capital loss carryforwards that could be utilized to offset taxable income in any future taxable year. The amount of the limitation is generally equal to the value of the corporation’s stock immediately prior to the ownership change multiplied by an interest rate, referred to as the long-term
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tax-exempt rate, periodically promulgated by the IRS. This limitation, however, may be significantly increased if there is “net unrealized built-in gain” in the assets of the corporation undergoing the ownership change.

As of December 31, 2025, we had an NOL carryforward of approximately $436 million, capital loss carryforwards of approximately $26 million and tax credits of $4 million for U.S. federal income tax purposes, principally consisting of tax attributes acquired from QEP Resources, Inc. (“QEP”), Sitio and Rattler. As a result of ownership changes for Diamondback Energy, Inc., QEP and Rattler, which occurred in connection with the acquisition of QEP and the Company’s merger with Rattler in 2022, our NOLs and other carryforwards, including those acquired from QEP and Rattler, are subject to an annual limitation under Sections 382 and 383 of the Code. Similarly, as a result of an ownership change for Sitio in connection with Viper’s Sitio Acquisition, carryforwards acquired from Sitio are subject to an annual limitation under Sections 382 and 383 of the Code.

Future changes in our stock ownership could result in an additional ownership change under Section 382 of the Code. Any such ownership change may limit our ability to offset taxable income arising after such an ownership change with NOLs or other tax attributes generated prior to such an ownership change, possibly substantially.

We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.

Our certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.

Provisions in our certificate of incorporation and bylaws and Delaware law make it more difficult to effect a change in control of our company, which could adversely affect the price of our common stock.

The existence of some provisions in our certificate of incorporation and bylaws could delay or prevent a change in control of our company, even if that change would be beneficial to our stockholders. Our certificate of incorporation and bylaws contain provisions that may make acquiring control of our company difficult, including provisions regulating the ability of our stockholders to nominate directors for election or to bring matters for action at annual meetings of our stockholders; limitations on the ability of our stockholders to call a special meeting and act by written consent; the ability of our board of directors to adopt, amend or repeal bylaws; and the authorization given to our board of directors to issue and set the terms of preferred stock without the approval of our stockholders.

These provisions also could discourage proxy contests and make it more difficult for our stockholders to elect directors and take other corporate actions. 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 that investors are willing to pay in the future for shares of our common stock.

The provision of our certificate of incorporation and bylaws requiring exclusive venue in the Court of Chancery in the State of Delaware for certain types of lawsuits may have the effect of discouraging lawsuits against us and our directors, officers and employees.

Our certificate of incorporation and bylaws provide that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware generally shall be the sole and exclusive forum for (i) any derivative action or proceeding brought on behalf of the Company, (ii) any action asserting a claim of breach of a fiduciary duty owed by any director, officer or employee of the Company to the Company or its stockholders, (iii) any action asserting a claim arising pursuant to any provision of the General Corporation Law of the State of Delaware, our certificate of incorporation or bylaws or (iv) any other action asserting a claim against the Company governed by the internal affairs doctrine. This choice of forum provision does not waive our compliance with our obligations under the federal securities laws and the rules and regulations thereunder. Moreover, the provision does not apply to suits brought to enforce a duty or liability created by the Securities Exchange Act or by the Securities Act of 1933, as amended.

This choice of forum provision may increase costs to bring a claim, discourage claims or limit a stockholder’s ability to bring a claim in a judicial forum that the stockholder finds favorable for disputes with the Company or our directors, officers or employees, which may discourage such lawsuits against the Company and its directors, officers and employees, even though an action, if successful, might benefit our stockholders. Alternatively, if a court were to find the choice of forum
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provision to be inapplicable or unenforceable in an action, we may incur additional costs associated with resolving such matters in other jurisdictions, which could increase our costs of litigation and adversely affect our business and financial condition.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 1C. CYBERSECURITY

Cybersecurity Risk Management Strategy

We have implemented and invested in, and will continue to implement and invest in, controls, procedures and protections (including internal and external personnel) that are designed to protect our systems, identify and remediate on a regular basis vulnerabilities in our systems and related infrastructure and monitor and mitigate the risk of data loss and other cybersecurity threats. We have engaged third-party consultants to conduct penetration testing and risk assessments. Our cybersecurity program is informed by the National Institute of Standards and Technology (“NIST”) Cybersecurity Framework and measured by the Maturity and Risk Assessment Ratings associated with the NIST Cybersecurity Framework and the Capability Maturity Model Integration.

Our cybersecurity risk management program is integrated into our overall enterprise risk management program, and shares common methodologies, reporting channels and governance processes that apply across the enterprise risk management program to other legal, compliance, strategic, operational, and financial risk areas.

Our cybersecurity risk management program includes:

• risk assessments designed to help identify material cybersecurity risks to our critical systems, information, products, services, and our broader enterprise IT and operational technology, or OT, environments;
• a security team principally responsible for managing (i) our cybersecurity risk assessment processes, (ii) our security controls, and (iii) our response to cybersecurity incidents;
• the use of external service providers, where appropriate, to assess, test, train or otherwise assist with aspects of our security controls;
• security tools deployed in the IT and OT environments for protection against and monitoring for suspicious activity;
• cybersecurity awareness training of our employees, including incident response personnel and senior management;
• cybersecurity tabletop exercises for members of our cybersecurity incident response team and legal department;
• a cybersecurity incident response plan that includes procedures for responding to cybersecurity incidents; and
• a third-party risk management process for service providers, which may include diligence, assessments and/or contractual requirements, depending on each service provider’s operational criticality and relative risk profile.

Cybersecurity Governance

Our cybersecurity governance program is led by the Senior Vice President and Chief Information Officer , with support from the internal information technology department. The Senior Vice President and Chief Information Officer has over 20 years of technological leadership experience in the oil and gas industry, providing oversight of all information technology disciplines, including cybersecurity, networking, infrastructure, applications, and data management and protection. The Senior Vice President and Chief Information Officer and his team, which consists of individuals who hold designations as Certified Information Systems Security Professional (CISSP), Certified Information Systems Auditor (CISA), and CompTIASecurity+, are responsible for leading enterprise-wide cybersecurity strategy, policy, standards, architecture and processes. In addition, our cybersecurity incident response team is responsible for responding to cybersecurity incidents and are guided by our Computer Security Incident Response Plan. Progress and developments in our cybersecurity governance program are communicated to members of the executive team. Our management team takes steps to remain informed about and monitor efforts to prevent, detect, mitigate and remediate cybersecurity risks and incidents through various means, which may include briefings from internal security personnel; threat intelligence and other information obtained from governmental, public or private sources, including third-party consultants engaged by us; alerts and reports produced by security tools deployed in our IT and OT environments; and through reporting by employees and service providers. While our board of directors is ultimately responsible for enterprise-wide risk oversight, the board’s committees assist the board in fulfilling its oversight responsibilities in certain areas of risk. In particular, the board’s audit committee is responsible, among other things, for risk management relating to legal and regulatory requirements, including cybersecurity, which plays an integral role in our risk management strategy and continues to be an area of increasing focus for our board, the audit committee and our management team.
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The audit committee of the board of directors receives quarterly updates from our Senior Vice President and Chief Information Officer on the status of our cybersecurity governance program, including as related to new or developing initiatives and any significant security incidents that may occur. Board members also receive presentations on cybersecurity topics from the Senior Vice President and Chief Information Officer as part of the board’s continuing education on topics that impact public companies. Our cybersecurity governance program also includes processes to assess cybersecurity risks related to third-party service providers, suppliers and vendors.

Risks from identified cybersecurity threats have not materially affected, and are not currently anticipated to materially affect, our Company, including our business strategy, results of operations or financial condition. See, however, Item 1A. Risk Factors of this report for additional information regarding cybersecurity risks we face and their potentially material impact on our business strategy, results of operations and financial condition.

ITEM 3. LEGAL PROCEEDINGS

Diamondback has elected to use a $1 million threshold for disclosing certain environmental proceedings to which a federal, state or local governmental authority is a party.

We are a party to various routine legal proceedings, disputes and claims arising in the ordinary course of our business, including those that arise from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry, personal injury claims, title disputes, royalty disputes, contract claims, employment claims, claims alleging violations of antitrust laws, contamination claims relating to oil and natural gas exploration and development and environmental claims, including claims involving assets previously sold to third parties and no longer part of our current operations. While the ultimate outcome of the pending proceedings, disputes or claims, and any resulting impact on us, cannot be predicted with certainty, we believe that none of these matters, if ultimately decided adversely, will have a material adverse effect on our financial condition, results of operations or cash flows. For additional information regarding environmental matters, see Note 15— Commitments and Contingencies in Item 8. Financial Statements and Supplementary Data of this report.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Listing and Holders of Record

Our common stock is listed on Nasdaq under the symbol “FANG”. There were 4,438 holders of record of our common stock on February 20, 2026.

Dividend Policy

In the first quarter of 2024, our board of directors approved a reduction in our return of capital commitment to our shareholders to at least 50% (down from 75%) of our quarterly Adjusted Free Cash Flow through repurchases under our share repurchase program, base dividends and variable dividends to accelerate the repayment of indebtedness incurred in connection with the Endeavor Acquisition and the Double Eagle Acquisition. Our board of directors intends to continue the payment of dividends to the holders of the Company’s common stock in the future; however, the Company can provide no assurance that dividends will be authorized or declared in the future or as to the amount or type of any future dividends. Our board of directors’ determination with respect to any such dividends, whether base or variable, including the record date, the payment date and the actual amount of the dividend, will depend upon our outlook for commodity prices, our profitability and financial condition, contractual restrictions, restrictions imposed by applicable law and other factors that the board deems relevant at the time of such determination.

Recent Sales of Unregistered Securities

During the three months ended December 31, 2025, the Company issued a total of 105,607 shares of common stock as partial consideration in connection with the acquisition of certain oil and gas leases from the sellers thereof in a private transaction exempt from registration pursuant to Section 4(a)(2) of the Securities Act.

Issuer Purchases of Equity Securities

Our common stock repurchase activity for the three months ended December 31, 2025 was as follows:

Period Total Number of Shares Purchased (1)(2)
Average Price Paid Per Share (3)(4)
Total Number of Shares Purchased as Part of Publicly Announced Plan (2)
Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plan (4)(5)

(In millions, except per share amounts, shares in thousands)
October 1, 2025 - October 31, 2025 614 $ 143.21  611 $ 3,011 
November 1, 2025 - November 30, 2025 2,275 $ 151.22  2,275 $ 2,667 
December 1, 2025 - December 31, 2025 18 $ 144.98  18 $ 2,665 
Total 2,907 $ 149.49  2,904

(1) Includes 3,301 shares of common stock repurchased from executives in order to satisfy tax withholding requirements. Such shares are cancelled and retired immediately upon repurchase.
(2) Includes 2.0 million shares repurchased from SGF FANG Holdings, LP (“SGF”) during the fourth quarter of 2025 pursuant to a privately negotiated letter agreement dated November 28, 2025. For further discussion on the repurchase from SGF, see Note 7— Related Party Transactions in Item 8. Financial Statements and Supplementary Data of this report.
(3) The average price paid per share includes any commissions paid to repurchase stock.
(4) In September 2021, our board of directors initiated our stock repurchase program. On July 31, 2025, our board of directors approved a $2.0 billion increase in our common stock repurchase program from $6.0 billion to $8.0 billion, excluding excise tax. The stock repurchase program has no time limit and may be suspended, modified, or discontinued by the board of directors at any time.
(5) The IRA, which was enacted into law on August 16, 2022, imposed a nondeductible 1% excise tax on the net value of certain stock repurchases made after December 31, 2022. All dollar amounts presented exclude such excise taxes, as applicable.
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Stock Performance Graph

The following performance graph and related information should not be deemed “soliciting material” or to be “filed” with the SEC, nor should such information be incorporated by reference into any future filing under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, except to the extent that we specifically incorporate such information by reference into such a filing. The performance graph and information are included for historical comparative purposes only and should not be considered indicative of future stock performance.

The performance graph includes a comparison of our cumulative total stockholder return over a five-year period with the cumulative total returns of the Standard & Poor’s 500 Stock Index, or the S&P 500, and the SPDR S&P Oil & Gas Exploration and Production ETF, or XOP. The graph assumes an investment of $100 on December 31, 2020, and that all dividends were reinvested.

As of December 31,
Calculated Values: 2020 2021 2022 2023 2024 2025
Diamondback Energy, Inc. $100.00 $227.44 $308.19 $368.65 $406.86 $383.98
S&P 500 $100.00 $128.68 $105.36 $133.03 $166.28 $195.98
XOP $100.00 $166.76 $242.36 $250.96 $248.37 $243.04

ITEM 6. [RESERVED]

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto in Item 8. Financial Statements and Supplementary Data of this report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expected performance. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors discussed further in Item 1A. Risk Factors and Cautionary Statement Regarding Forward-Looking Statements of this report.

Overview

We are an independent oil and natural gas company focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves primarily in the Permian Basin in West Texas. As of December 31, 2025, we have one reportable segment, the upstream segment. See Note 1— Description of the Business and Basis of Presentation and Note 17— Segment Information in Item 8. Financial Statements and Supplementary Data of this report for further discussion.

2025 Financial and Operating Highlights

• Recorded net income of $1.7 billion, which includes impairment of approximately $3.7 billion recorded on our proved oil and natural gas properties during the fourth quarter of 2025.
• Our cash operating costs were $10.23 per BOE, including lease operating expenses of $5.55 per BOE, cash general and administrative expenses of $0.62 per BOE and production and ad valorem taxes and gathering, processing and transportation expenses of $4.06 per BOE.
• Incurred cash capital expenditures, excluding acquisitions, of $3.5 billion.
• Paid dividends to stockholders of $1.2 billion during 2025 and declared a base cash dividend payable in the first quarter of 2026 of $1.05 per share of common stock.
• Increased our common stock repurchase program authorization to $8.0 billion, excluding excise taxes, and repurchased $2.0 billion of our common stock in 2025, leaving approximately $2.7 billion available for future repurchases at December 31, 2025.
• Issued $1.2 billion aggregate principal amount of 5.550% Senior Notes due April 1, 2035 (the “2035 Notes”) to fund a portion of the cash consideration for the Double Eagle Acquisition.
• Repurchased an aggregate of approximately $455 million of our senior notes.
• Our average production was 921.0 MBOE/d.
• Drilled 463 gross horizontal wells (including 459 in the Midland Basin and 4 in the Delaware Basin).
• Turned 503 gross operated horizontal wells (including 488 in the Midland Basin and 15 in the Delaware Basin) to production.
• As of December 31, 2025, we had approximately 869,036 net acres in the Permian Basin, which primarily consisted of 774,645 net acres in the Midland Basin and 94,391 net acres in the Delaware Basin. As of December 31, 2025, we had an estimated 8,854 gross horizontal locations that we believe to be economic at $50.00 per Bbl WTI. Our publicly traded subsidiary, Viper, also owns mineral interests underlying approximately 36,004 net royalty acres in the Delaware Basin and approximately 50,595 net royalty acres in the Midland Basin. We operate approximately 35% of these net royalty acres.

Transactions and Recent Developments

Diamondback Acquisition and Divestitures

EPIC Divestiture

On October 31, 2025, we divested our 27.5% equity interest in EPIC for approximately $504 million in cash and an additional $96 million in contingent consideration (the “EPIC Divestiture”), which resulted in a gain on the sale of equity method investments of approximately $299 million. The gain is included in the caption “Other income (expense), net” on the consolidated statements of operations for the year ended December 31, 2025.

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Divestiture of Water Assets to Deep Blue

On October 1, 2025, we divested EDS, a subsidiary originally acquired in connection with the Endeavor Acquisition, to our affiliate, Deep Blue Midland Basin LLC (“Deep Blue”), in exchange for upfront net cash proceeds of $694 million, subject to customary post-closing adjustments, and approximately $34 million of additional equity interests issued by Deep Blue as non-cash consideration. This transaction provides for the potential for us to earn up to an additional $200 million. If certain completion thresholds are not met, we could owe up to $150 million in contingent consideration for the years 2026 through 2028. The divestiture resulted in a gain of approximately $168 million, which is included in the caption “Other operating expenses, net” on the consolidated statements of operations for the year ended December 31, 2025. As part of the divestiture, we renewed our 15-year dedication to Deep Blue for its produced water and supply water within a 12-county area of mutual interest in the Midland Basin.

2025 Drop Down

On May 1, 2025, our wholly owned subsidiary, EER LP, divested the Endeavor Subsidiaries to Viper and Viper LLC in exchange for consideration consisting of (i) $873 million in cash including customary post-closing adjustments, and (ii) the issuance of 69.63 million Viper LLC units and an equal number of shares of Viper’s Class B common stock.

Double Eagle Acquisition

On April 1, 2025, we completed the Double Eagle Acquisition for consideration of $3.1 billion in cash and approximately 6.84 million shares of our common stock, including transaction costs and certain customary post-closing adjustments. The Double Eagle Acquisition consisted of approximately 67,700 gross (40,000 net) acres, which are primarily located in the Midland Basin, and approximately 407 gross (342 net) horizontal locations in primary development targets.

Viper Acquisitions and Divestitures

Divestiture of Non-Permian Assets

On February 9, 2026, Viper completed the Viper Non-Permian Divestiture for net cash proceeds of approximately $617 million, subject to customary post-closing adjustments. The divested properties consisted of approximately 9,400 net royalty acres in the Denver-Julesburg, Eagle Ford and Williston basins with current production of approximately 4,750 BO/d. Proceeds from the Viper Non-Permian Divestiture were used to repay the Viper 2025 Term Loan (as defined below) and to reduce borrowings outstanding on the Viper Revolving Credit Facility (as defined and discussed in Note 8— Debt in Item 8. Financial Statements and Supplementary Data of this report).

Sitio Acquisition

On August 19, 2025, Viper and Viper LLC completed the Sitio Acquisition in an all-equity transaction valued at approximately $4.0 billion, including customary transaction costs and post-closing adjustments and the partial retirement of Sitio’s net debt of approximately $1.2 billion. The mineral and royalty interests acquired in the Sitio Acquisition represent approximately 25,300 net royalty acres in the Permian Basin and approximately 9,000 net royalty acres in the Denver-Julesburg, Eagle Ford and Williston basins, for total acreage of approximately 34,300 net royalty acres.

See Note 4— Acquisitions and Divestitures and Note 16— Subsequent Events in Item 8. Financial Statements and Supplementary Data of this report for further discussion of the acquisitions and divestitures discussed above.

Diamondback Capital Transactions

2025 Term Loan Agreement

In connection with the Double Eagle Acquisition, Diamondback Energy, Inc., as guarantor, entered into a term loan credit agreement with Diamondback E&P, as borrower, and Bank of America, N.A., as administrative agent (the “2025 Term Loan”). The 2025 Term Loan provided the Company with the ability to borrow up to $1.5 billion, which we drew in a single borrowing to fund a portion of the cash consideration for the Double Eagle Acquisition.

2035 Notes Offering

On March 20, 2025, we issued the 2035 Notes for net proceeds of $1.2 billion, after underwriters’ discounts and transaction costs, which we used to fund a portion of the cash consideration for the Double Eagle Acquisition.
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Diamondback Retirement of Notes

During the year ended December 31, 2025, we opportunistically repurchased an aggregate principal amount of $455 million of our senior notes in open market transactions for total cash consideration, including accrued interest paid, of approximately $363 million, at an average of 79.3% of par value.

Viper Capital Transactions

Viper 2025 Notes Offering and Retirement of Notes

On July 23, 2025, Viper LLC issued $1.6 billion in aggregate principal amount of senior notes consisting of (i) $500 million aggregate principal amount of 4.900% Senior Notes due August 1, 2030 (the “Viper 2030 Notes”), and (ii) $1.1 billion aggregate principal amount of 5.700% Senior Notes due August 1, 2035 (the “Viper 2035 Notes” and together with the Viper 2030 Notes, the “Viper 2025 Notes”). Viper used approximately $824 million of the net proceeds from the issuance of the Viper 2025 Notes to redeem all of Viper’s 7.375% Senior Notes maturing on November 1, 2031 (the “Viper 2031 Notes”), and on November 1, 2025, Viper redeemed all of their 5.375% Senior Notes due 2027 (the “Viper 2027 Notes”), including accrued and unpaid interest through the date of redemption and any redemption premiums. Viper used the remaining net proceeds to partially retire Sitio’s net debt of approximately $1.2 billion including any fees, costs and expenses related to the redemption or repayment of such debt, and for general corporate purposes. On December 23, 2025, Viper Energy Partners LLC converted its legal form (the “Viper LLC Conversion”), in accordance with the applicable laws of the State of Delaware, to a Delaware limited partnership named Viper Energy Partners LP (“Viper LP”), which is now the issuer under the Viper 2025 Notes.

Viper 2025 Term Loan

On July 23, 2025, Former Viper, as guarantor, Viper LLC, as borrower, and Goldman Sachs Bank USA, as administrative agent, entered into a $500 million term loan credit agreement (the “Viper 2025 Term Loan”), which was fully drawn to partially fund the retirement of Sitio’s net debt. Following the closing of the Sitio Acquisition, New Viper became an additional guarantor of the borrower’s obligations under the Viper 2025 Term Loan. Further, after the Viper LLC Conversion, Viper LP, as successor to Viper Energy Partners LLC, became the borrower with respect to the Viper 2025 Term Loan. The Viper 2025 Term Loan was repaid in full in February 2026.

Viper 2025 Equity Offering

On February 3, 2025, Viper completed an underwritten public offering of approximately 28.34 million shares of its Class A common stock, which included approximately 3.70 million shares issued pursuant to an option to purchase additional shares of its Class A common stock granted to the underwriters at a price to the public of $44.50 per share, for total net proceeds to Viper of approximately $1.2 billion, after the underwriters’ discount and transaction costs (the “Viper 2025 Equity Offering”).

See Note 8— Debt and Note 9— Stockholders’ Equity and Earnings (Loss) Per Share in Item 8. Financial Statements and Supplementary Data of this report for further discussion of the capital transactions above.

Commodity Prices

Prices for oil, natural gas and natural gas liquids are determined primarily by prevailing market conditions. Regional and worldwide economic activity, changes in trade or other government policies or regulations, including with respect to U.S. energy and monetary policies, tariffs or other trade barriers and any resulting trade tensions, regional conflicts and political instability, extreme weather conditions and other substantially variable factors, influence market conditions for these products. These factors are beyond our control and are difficult to predict. During 2025, 2024 and 2023, WTI prices averaged $64.73, $75.76 and $77.60 per Bbl, respectively, and Henry Hub prices averaged $3.62, $2.41 and $2.66 per MMBtu, respectively.

Given the overall decline in SEC Prices through 2025 as compared to 2024, we believe a material non-cash impairment of our assets is reasonably likely to occur in the first quarter of 2026. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties, income tax rate assumptions and other factors will determine our actual ceiling test calculation and impairment analysis in future periods. Based on the number of factors that may impact our future estimate of proved reserves, we are currently unable to determine
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an estimate of the amount or range of amounts of any potential impairment charge in the first quarter of 2026. Impairment charges affect our results of operations but do not reduce our cash flow.

For additional information around risks related to commodity prices, see Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk .

Outlook

Our cash capital expenditures for 2025 were consistent with our guidance presented in November 2025. Given the soft outlook for oil prices currently, our 2026 plan is to keep activity and production essentially flat relative to our fourth quarter 2025 levels at approximately 926 MBOE/d to 962 MBOE/d, as adjusted for the impact of the Viper Non-Permian Divestiture. We have currently budgeted 2026 total cash capital spend of $3.60 billion to $3.90 billion, which at the midpoint is an increase of 7% from our 2025 cash capital budget. In 2026, we will continue to target an industry‑leading breakeven oil price by capturing incremental technical and operational efficiencies, driving higher margins and maximizing Adjusted Free Cash Flow to fund our dividend, opportunistically repurchase shares, and continue strengthening the balance sheet.

Our board of directors has approved a return of capital commitment to our shareholders of at least 50% of our quarterly Adjusted Free Cash Flow. We exceeded our commitment to sell at least $1.5 billion of non-core assets during 2025 to help accelerate debt reduction and maintain a strong balance sheet. We also remain focused on our long-term priority to return cash to our stockholders.

In 2025, we successfully delineated the Barnett/Woodford zone across our Midland Basin acreage, confirming reservoir continuity and improving our development line of sight, which will add meaningful incremental drilling locations to our inventory. As a result, we plan to allocate approximately 3% to 4% of our 2026 total capital budget to further advance the Barnett/Woodford across our acreage.

As of December 31, 2025, we were operating 15 drilling rigs and four completion crews and currently intend to operate between 15 and 18 drilling rigs and approximately five completion crews in 2026 on average across our current acreage position in the Midland and Delaware Basins.

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Results of Operations

For a discussion of the results of operations for the year ended December 31, 2024 as compared to the year ended December 31, 2023, please refer to Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2024 (filed with the SEC on February 26, 2025), which is incorporated in this report by reference from such prior report on Form 10-K.

Comparison of the Years Ended December 31, 2025 and 2024

The following table sets forth selected historical operating data for the periods indicated:

Year Ended December 31,
2025 2024
Revenues (in millions):
Oil sales $ 11,621  $ 9,067 
Natural gas sales 400  89 
Natural gas liquid sales 1,432  944 
Total oil, natural gas and natural gas liquid revenues $ 13,453  $ 10,100 

Production Data:
Oil (MBbls) 181,462  123,325 
Natural gas (MMcf) 447,855  275,680 
Natural gas liquids (MBbls) 80,073  49,700 
Combined volumes (MBOE) (1)
336,178  218,972 

Daily oil volumes (BO/d) 497,156  336,954 
Daily combined volumes (BOE/d) 921,036  598,284 

Average Prices:
Oil ($ per Bbl) $ 64.04  $ 73.52 
Natural gas ($ per Mcf) $ 0.89  $ 0.32 
Natural gas liquids ($ per Bbl) $ 17.88  $ 18.99 
Combined ($ per BOE) $ 40.02  $ 46.12 

Oil, hedged ($ per Bbl) (2)
$ 63.14  $ 72.68 
Natural gas, hedged ($ per Mcf) (2)
$ 1.84  $ 0.91 
Natural gas liquids, hedged ($ per Bbl) (2)
$ 17.88  $ 18.99 
Average price, hedged ($ per BOE) (2)
$ 40.79  $ 46.38 

(1) Bbl equivalents are calculated using a conversion rate of six Mcf per Bbl.
(2) Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices and include gains and losses on cash settlements for matured commodity derivatives, which we do not designate for hedge accounting. Hedged prices exclude gains or losses resulting from the early settlement of commodity derivative contracts.

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Production Data. Substantially all of our revenues are generated through the sale of oil, natural gas and natural gas liquids production. The following table provides information on the mix of our production for the periods indicated:

Year Ended December 31,
2025 2024
Oil (MBbls) 54  % 56  %
Natural gas (MMcf) 22  % 21  %
Natural gas liquids (MBbls) 24  % 23  %
100  % 100  %

See Items 1 and 2. Business and Properties —Oil and Natural Gas Data—Oil and Natural Gas Production and Price History of this report for further discussion of production by basin.

Oil, Natural Gas and Natural Gas Liquids Revenues. Our revenues are a function of oil, natural gas and natural gas liquids production volumes sold and average sales prices received for those volumes.

Our oil, natural gas and natural gas liquids revenues increased by approximately $3.4 billion, or 33%, to $13.5 billion in 2025 compared to 2024. This net increase consisted of an additional $4.9 billion attributable to the 54% growth in our combined production volumes, partially offset by a net reduction of $1.6 billion primarily due to lower average prices received for our oil production.

Approximately 42% of the growth in our combined production volumes is attributable to new wells added between periods, 41% of the increase is attributable to the Endeavor Acquisition and 12% is attributable to the Double Eagle Acquisition.

See Note 4— Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report for further discussion of the Endeavor Acquisition and the Double Eagle Acquisition.

Net Sales of Purchased Oil . We enter into purchase transactions with third parties and separate sale transactions with third parties to satisfy certain of our unused oil pipeline capacity commitments.

The following table presents the net sales of purchased oil from third parties for the periods indicated:

Year Ended December 31,
(In millions) 2025 2024
Sales of purchased oil $ 1,476  $ 923 
Purchased oil expense 1,474  921 
Net sales of purchased oil $ 2  $ 2 

Other Revenues. The following table shows the other revenues for the periods indicated:

Year Ended December 31,
(In millions) 2025 2024
Other operating income $ 97  $ 43 

Other operating income increased by $54 million in 2025 compared to 2024 primarily due to (i) a $35 million increase in midstream revenues attributable to assets acquired in the Endeavor Acquisition, and (ii) a $19 million increase in lease bonus income received during 2025.

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Lease Operating Expenses. The following table shows lease operating expenses for the periods indicated:

Year Ended December 31,
2025 2024
(In millions, except per BOE amounts) Amount Per BOE Amount Per BOE
Lease operating expenses $ 1,865  $ 5.55  $ 1,286  $ 5.87 

Lease operating expenses increased by $579 million in 2025 compared to 2024. The increase primarily consists of (i) $368 million of costs associated with operating wells acquired in the Endeavor Acquisition and the Double Eagle Acquisition, (ii) $114 million in additional well workover, artificial lift, maintenance and utility costs, (iii) $66 million of additional costs related to higher legacy production volumes, (iv) $23 million in additional expense due to an increase in our average working interest, and (v) other individually insignificant changes. Currently, we estimate expenditures for lease operating expenses may range between approximately $2.0 billion and $2.2 billion in 2026 at the midpoint of expected production.

Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the periods indicated:

Year Ended December 31,
2025 2024
(In millions, except per BOE amounts) Amount Per BOE Percentage of Oil, Natural Gas and Natural Gas Liquids Revenue
Amount Per BOE Percentage of Oil, Natural Gas and Natural Gas Liquids Revenue

Production taxes $ 634  $ 1.89  4.7  % $ 462  $ 2.11  4.6  %
Ad valorem taxes 217  0.64  1.6  176  0.80  1.7 
Total production and ad valorem expense $ 851  $ 2.53  6.3  % $ 638  $ 2.91  6.3  %

In general, production taxes are directly related to production revenues and are based upon current year commodity prices and ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices. For 2025 compared to 2024, both production taxes and ad valorem taxes as a percentage of oil, natural gas and natural gas liquids revenues remained relatively flat. Rates per BOE for both production taxes and ad valorem taxes declined primarily due to the increase in production volumes for 2025 compared to 2024.

Gathering, Processing and Transportation Expense. The following table shows gathering, processing and transportation expense for the periods indicated:

Year Ended December 31,
2025 2024
(In millions, except per BOE amounts) Amount Per BOE Amount Per BOE
Gathering, processing and transportation $ 515  $ 1.53  $ 356  $ 1.63 

Gathering, processing and transportation expense increased by $159 million in 2025 compared to 2024 primarily due to (i) $54 million incurred on additional production acquired in the Endeavor Acquisition, (ii) an additional $44 million in transportation costs incurred to meet our minimum volume commitments on certain pipelines, (iii) $34 million associated with production from new wells completed between 2025 and 2024, (iv) $18 million related to new firm transportation contracts that became effective during 2025, and (v) other individually insignificant changes. Currently, we estimate expenditures for gathering, processing and transportation may range between approximately $507 million and $597 million in 2026 at the midpoint of expected production.
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Depreciation, Depletion, Amortization and Accretion. The following table shows the components of our depreciation, depletion and amortization expense for the periods indicated:

Year Ended December 31,
(In millions, except BOE amounts) 2025 2024
Depletion of proved oil and natural gas properties $ 4,908  $ 2,759 
Depreciation of other property and equipment 86  61 
Other amortization 9  8 
Asset retirement obligation accretion 35  22 
Depreciation, depletion, amortization and accretion expense $ 5,038  $ 2,850 
Oil and natural gas properties depletion rate per BOE $ 14.60  $ 12.60 
Depreciation, depletion, amortization and accretion per BOE $ 14.99  $ 13.02 

The increase in depletion of proved oil and natural gas properties of $2.1 billion in 2025 as compared to 2024 consists primarily of $1.5 billion from growth in production volumes and $672 million due to an increase in the depletion rate resulting largely from the addition of higher value leasehold costs and proved reserves from the Endeavor Acquisition, the Double Eagle Acquisition and, to a lesser extent, Viper’s Sitio Acquisition and Viper’s Tumbleweed Acquisitions (as defined and discussed in Note 4— Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report).

Impairment of Oil and Natural Gas Properties. The following table shows impairment of oil and natural gas properties for the periods indicated:

Year Ended December 31,
(In millions) 2025 2024
Impairment of oil and natural gas properties $ 3,652  $ — 

The non-cash ceiling test impairment charge of $3.7 billion for the year ended December 31, 2025 primarily resulted from the decline in SEC Prices during 2025. Impairment charges affect our results of operations but do not reduce our cash flow.

In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties, income tax rate assumptions and other factors will determine our actual ceiling test calculation and impairment analysis in future periods. If the trailing 12-month commodity prices fall as compared to the commodity prices used in prior quarters, we may have material write-downs in subsequent quarters. Given the overall decline in SEC Prices from the first quarter of 2025 through the first two months of 2026, we believe an additional material non-cash impairment of our assets is reasonably likely to occur in the first quarter of 2026; however, based on the number of factors that may impact our future estimate of proved reserves, we are currently unable to determine an estimate of the amount or range of amounts of any potential impairment charge in the first quarter of 2026.

General and Administrative Expenses. The following table shows the components of general and administrative expenses for the periods indicated:

Year Ended December 31,
2025 2024
(In millions, except per BOE amounts) Amount Per BOE Amount Per BOE
General and administrative expenses $ 207  $ 0.62  $ 148  $ 0.68 
Non-cash stock-based compensation 81  0.24  65  0.30 
Total general and administrative expenses $ 288  $ 0.86  $ 213  $ 0.98 

The increase in general and administrative expenses of $59 million in 2025 compared to 2024 was primarily due to a $47 million increase in employee compensation and benefit costs related to increasing headcount largely from the Endeavor Acquisition for the full year of 2025 and other individually insignificant items.

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Other Operating Expenses. The following table shows other operating expenses for the periods indicated:

Year Ended December 31,
(In millions) 2025 2024

Other operating expenses, net $ 77  $ 406 

Other operating expenses decreased by $329 million in 2025 compared to 2024 primarily due to (i) a $198 million reduction in merger and transaction costs largely due to 2024 including $303 million in costs associated with the Endeavor Acquisition compared to $105 million of costs incurred in 2025 for transactions including the 2025 Drop Down, Viper’s Sitio Acquisition and additional severance and other costs for the Endeavor Acquisition, (ii) a $168 million gain on the sale of our EDS subsidiary during the fourth quarter of 2025, and (iii) other individually insignificant expenses. These decreases were partially offset by a $38 million increase in midstream costs incurred in connection with EDS prior to its sale in the fourth quarter of 2025.

Derivative Instruments. The following table shows the net gain (loss) on derivative instruments and the net cash received (paid) on settlements of derivative instruments for the periods indicated:

Year Ended December 31,
(In millions) 2025 2024
Gain (loss) on derivative instruments, net $ 341  $ 137 
Net cash received (paid) on settlements (1)
$ 181  $ (51)

(1) Includes cash paid on interest rate swaps terminated prior to their contractual maturity of $67 million for 2025 and $37 million for 2024.

The increase in gain on derivative instruments for the year ended December 31, 2025, compared to the same period in 2024 primarily reflects (i) a $118 million net gain on natural gas contracts, which was comprised of a $262 million increase in cash received on the settlement of contracts partially offset by a $144 million decrease in the value of our unsettled natural gas contracts primarily due to an increase in market prices for natural gas compared to our contract prices, (ii) an $89 million gain on our interest rate swaps, which was comprised of a $59 million increase in the value of our unsettled interest rate swap contracts primarily due to a decline in expected future interest rates and the early termination of $600 million in notional amount of the interest rate swaps in 2025 and a $30 million net decrease in cash paid for the settlement and early termination of our interest rate derivatives and treasury locks, and (iii) other individually insignificant changes.

See Note 12— Derivatives in Item 8. Financial Statements and Supplementary Data of this report for further details regarding our derivative instruments and interest rate swaps.

Other Income (Expense). The following table shows other income and expenses for the periods indicated:

Year Ended December 31,
(In millions) 2025 2024
Interest expense, net $ (244) $ (135)
Other income (expense), net $ 455  $ 101 

Gain (loss) on extinguishment of debt $ 56  $ 2 

Interest expense, net increased by $109 million in 2025, compared to 2024. This increase primarily consisted of (i) a $131 million reduction in interest income (which reduces interest expense) attributable to holding funds raised for the Endeavor Acquisition in cash in short-term interest bearing accounts during the year ended December 31, 2024, (ii) $111 million of interest expense on the 2025 Term Loan and 2035 Notes, which were both issued in March 2025, (iii) $91 million of additional interest expense on the April 2024 Notes, and (iv) a net $31 million increase related to Viper comprised of additional interest expense on the Viper 2025 Notes and Viper 2025 Term Loan partially offset by a reduction in interest expense attributable to Viper’s redemption of the Viper 2027 Notes and the Viper 2031 Notes. These increases were partially offset by (i) a $237 million increase in capitalized interest costs, which reduces interest expense, (ii) a $24 million reduction in amortization of debt issuance costs primarily related to fully amortizing costs related to our bridge facility in 2024 upon its termination, and (iii) other individually insignificant offsetting changes. Currently, we estimate expenditures for interest expense, net may range between approximately $237 million and $316 million in 2026.
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See Note 8— Debt in Item 8. Financial Statements and Supplementary Data of this report for further details regarding outstanding borrowing, interest expense and gain (loss) on extinguishment of debt.

Other income for the year ended December 31, 2025, increased by $354 million compared to the same period in 2024, primarily due to an increase of $363 million in the gain recognized on the sale of various equity method investments in 2025 compared to 2024. This net gain was partially offset by a $30 million decrease in the value of an investment recorded at fair value during 2025, compared to 2024 and other individually insignificant items.

Provision for (Benefit from) Income Taxes. The following table shows the provision for (benefit from) income taxes for the periods indicated:

Year Ended December 31,
(In millions) 2025 2024
Provision for (benefit from) income taxes $ 327  $ 800 

The reduction in our income tax provision for 2025 compared to 2024 was primarily due to the decrease in pre-tax income resulting largely from the non-cash ceiling test impairment recognized in 2025. See Note 11— Income Taxes in Item 8. Financial Statements and Supplementary Data of this report for further discussion of our income tax expense.

Liquidity and Capital Resources

Overview of Sources and Uses of Cash

Historically, our primary sources of liquidity have included cash flows from operations, proceeds from our public equity offerings, borrowings under our revolving credit facility and term loan agreements, proceeds from the issuance of senior notes and sales of non-core assets. Our primary uses of capital have been for the acquisition, development and exploration of oil and natural gas properties, repayment of debt and returning capital to stockholders. At December 31, 2025, we had approximately $2.6 billion of liquidity consisting of $91 million in standalone cash and cash equivalents and $2.5 billion available under our credit facility. As discussed below, our cash capital budget guidance for 2026 is approximately $3.60 billion to $3.90 billion, which prioritizes free cash flow generation and debt reduction. As of December 31, 2025, we had approximately $763 million of senior notes maturing in the next 12 months.

Future cash flows are subject to a number of variables, including the level of our oil and natural gas production and the volatility of commodity prices. Further, significant additional capital expenditures will be required to more fully develop our properties. Prices for our commodities are determined primarily by prevailing market conditions, regional and worldwide economic activity, weather and other substantially variable factors. These factors are beyond our control and are difficult to predict. See Item 1A. Risk Factors of this report above. In order to mitigate this volatility, we enter into derivative contracts with a number of financial institutions, all of which are participants in our credit facility, to economically hedge a portion of our estimated future crude oil and natural gas production as discussed further in Note 12— Derivatives in Item 8. Financial Statements and Supplementary Data and Item 7A. Quantitative and Qualitative Disclosures About Market Risk —Commodity Price Risk of this report. The level of our hedging activity and duration of the financial instruments employed depend on our desired cash flow protection, available hedge prices, the magnitude of our capital program and our operating strategy.

Cash Flow

Our cash flows for the years ended December 31, 2025 and 2024 are presented below:

Year Ended December 31,
2025 2024
(In millions)
Net cash provided by (used in) operating activities $ 8,758  $ 6,413 
Net cash provided by (used in) investing activities (7,809) (11,221)
Net cash provided by (used in) financing activities (1,007) 4,387 
Net change in cash $ (58) $ (421)

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Operating Activities

Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for the oil and natural gas we produce.

The increase in operating cash flows for the year ended December 31, 2025 compared to the same period in 2024 primarily resulted from (i) $3.4 billion in additional revenue, excluding sales of purchased oil, and (ii) an increase of $232 million of cash received on settlements of derivatives in 2025 compared to cash paid on settlements of derivatives in 2024, and a reduction of $114 million in cash paid for interest, net of capitalized amounts. These cash inflows were partially offset by (i) higher cash operating expenses, excluding purchased oil expense, of approximately $483 million, (ii) an increase of $629 million in cash paid for taxes, and (iii) fluctuations in other working capital balances due primarily to the timing of when collections were made on accounts receivable and payments were made on accounts payable. See “ — Results of Operations ” for discussion of significant changes in our revenues and expenses.

Investing Activities

The majority of our net cash used in investing activities during the year ended December 31, 2025, was for drilling and completion costs in conjunction with our development program as well as the acquisition of properties and equipment for the Double Eagle Acquisition and Viper’s Sitio Acquisition. The majority of our net cash used in investing activities during the year ended December 31, 2024, was for the Endeavor Acquisition. These cash outflows were partially offset by proceeds received from the divestitures of various oil and gas properties and other assets including EDS and the EPIC Divestiture, which are discussed further in Note 4— Acquisitions and Divestitures in Item 8. Financial Statements and Supplementary Data of this report.

Capital Expenditure Activities

Our capital expenditures excluding acquisitions and equity method investments (on a cash basis) were as follows for the specified period:

Year Ended December 31,
2025 2024
(In millions)
Operated drilling and completion additions to oil and natural gas properties $ (2,951) $ (2,617)
Capital workovers, non-operated additions to oil and natural gas properties and science (335) (15)
Infrastructure, environmental and midstream additions (237) (235)
Total $ (3,523) $ (2,867)

For further discussion regarding our development program, please see Items 1 and 2. Business and Properties —Oil and Natural Gas Data—Wells Drilled and Completed in 2025 of this report.

Financing Activities

During the year ended December 31, 2025, net cash used in financing activities was primarily attributable to (i) $2.2 billion of repurchases as part of our and Viper’s repurchase programs, (ii) $1.9 billion to repay and retire our Tranche A Loans and partially repay the 2025 Term Loan, (iii) $1.2 billion of dividends paid to stockholders, (iv) $1.2 billion paid for the retirement of certain of our and Viper’s senior notes, (v) $382 million in dividends paid to non-controlling interest, (vi) and various other individually insignificant costs. These cash outflows were partially offset by (i) $2.8 billion of proceeds from the issuance of the 2035 Notes and Viper 2025 Notes, (ii) $2.0 billion of aggregate proceeds from the 2025 Term Loan and the Viper 2025 Term Loan, (iii) $1.2 billion in proceeds from the Viper 2025 Equity Offering, and (iv) $156 million in borrowings on our credit facilities, net of repayments.

During the year ended December 31, 2024, net cash provided by financing activities was primarily attributable to (i) $5.5 billion of proceeds from the issuance of the April 2024 Notes, (ii) $900 million in borrowings on our Tranche A Loans, net of repayments, (iii) $476 million in proceeds from the Viper 2024 Equity Offering (as defined and discussed in Note 9— Stockholders’ Equity and Earnings (Loss) Per Share in Item 8. Financial Statements and Supplementary Data of this report), (iv) $451 million in proceeds from the sale of our shares of Viper’s Class A common stock, and (v) $2 million in borrowings on our credit facilities, net of repayments. These cash inflows were partially offset by (i) $1.6 billion of dividends paid to stockholders, (ii) $959 million of repurchases as part of our and Viper’s share repurchase programs, (iii) $227 million in
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distributions to non-controlling interest, (iv) $99 million of debt issuance costs primarily associated with the April 2024 Notes and Tranche A Loans, and (v) $39 million in cash paid for tax withholdings on vested employee stock awards.

Capital Resources

Our working capital requirements are primarily supported by our cash and cash equivalents and available borrowings under our revolving credit facility. We may draw on our revolving credit facility to meet short-term cash requirements, or issue debt or equity securities as part of our longer-term liquidity and capital management program. Because of the alternatives available to us, we believe that our short-term and long-term liquidity are adequate to fund not only our current operations, but also our near-term and long-term capital requirements.

As we pursue our business and financial strategy, we regularly consider which capital resources, including cash flow and equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future ability to grow proved reserves and production will be highly dependent on the capital resources available to us. Any prolonged volatility in the capital, financial and/or credit markets and/or adverse macroeconomic conditions may limit our access to, or increase our cost of, capital or make capital unavailable on terms acceptable to us or at all.

Revolving Credit Facilities

Diamondback’s Credit Agreement

As of December 31, 2025, the maximum credit amount available under our undrawn revolving credit facility was $2.5 billion, which may be increased to a total maximum commitment amount of $2.6 billion and has a maturity date of June 12, 2030.

Viper’s Revolving Credit Facility

In 2025, Former Viper, as guarantor, entered into a credit agreement with Viper LLC, as borrower, and Wells Fargo, as the administrative agent (the “Viper Revolving Credit Facility”), which matures on June 12, 2030, and provides for a commitment amount of $1.5 billion. As of December 31, 2025, the Viper Revolving Credit Facility had $105 million in outstanding borrowings and $1.4 billion available for future borrowings. Following the Viper LLC Conversion, Viper LP, as successor to Viper Energy Partners LLC, became the borrower with respect to the Viper Revolving Credit Facility.

For additional discussion of our outstanding debt as of December 31, 2025, see Note 8— Debt in Item 8. Financial Statements and Supplementary Data of this report.

Debt Ratings

We receive debt ratings from the major ratings agencies in the U.S which impact the interest rates we receive on our variable rate debt and interest rate swaps. In determining our debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, commodity pricing levels, our liquidity, asset quality, reserve mix, debt levels, cost structure, planned asset sales and production growth opportunities. Currently, our credit ratings from the three main credit rating agencies are as follows:

• Standard and Poor’s Global Ratings Services (BBB);
• Fitch Investor Services (BBB+); and
• Moody’s Investor Services (Baa2).

Any rating downgrades may result in additional letters of credit or cash collateral being posted under certain contractual arrangements.

Capital Requirements

In addition to future operating expenses and working capital commitments discussed in “ — Outlook , ” our primary short and long-term liquidity requirements consist primarily of (i) capital expenditures, (ii) payments of principal and interest on our revolving credit facility, 2025 Term Loan and senior notes, (iii) payments of other contractual obligations, and (iv) cash used to pay for dividends and repurchases of securities.

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2026 Capital Spending Plan

We currently estimate that our 2026 cash capital budget will be $3.60 billion to $3.90 billion, which includes $3.05 billion to $3.27 billion for operated horizontal drilling and completions.

The amount and timing of our capital expenditures are largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. We will continue monitoring commodity prices and overall market conditions and can adjust our rig cadence and our capital expenditure budget up or down in response to changes in commodity prices and overall market conditions.

Payments of Principal and Interest on Debt Instruments

As of December 31, 2025, our debt, including the debt of Viper, consisted of approximately $13.5 billion in aggregate outstanding principal amount of senior notes, $550 million outstanding under the 2025 Term Loan due in 2027, $500 million outstanding under the Viper 2025 Term Loan due in 2027, which was repaid in February 2026, and $105 million in outstanding borrowings under the Viper Revolving Credit Facility, which was repaid in the first quarter of 2026.

At December 31, 2025, we have total principal payments due on our outstanding senior notes, including those of Viper, of $763 million in 2026, $850 million in 2027, $73 million in 2028, $915 million in 2029, $1.4 billion in 2030 and $9.6 billion thereafter. Additionally, we expect to incur future cash interest costs on these senior notes of approximately $693 million in 2026, $1.3 billion cumulatively in the years from 2027 through 2028, $1.2 billion cumulatively in the years from 2029 and 2030, and $6.8 billion cumulatively between 2031 and 2064.

See Note 8— Debt in Item 8. Financial Statements and Supplementary Data of this report for further details regarding our outstanding borrowing and interest expense.

Other Contractual Obligations and Commitments

At December 31, 2025, our other significant contractual obligations consist primarily of (i) minimum transportation commitments totaling $3.0 billion, (ii) electrical power purchase commitments totaling $495 million, (iii) asset retirement obligations totaling $542 million, (iv) electric fracturing fleet and related power generation services commitments totaling $124 million, (v) compressor rental commitments totaling $90 million, and (vi) minimum purchase commitments for quantities of sand used in our drilling operations totaling $56 million. We expect to make aggregate payments of approximately $586 million for these commitments during 2026. See Note 6— Asset Retirement Obligatio ns and Note 15— Commitments and Contingencies in Item 8. Financial Statements and Supplementary Data of this report for further discussion of these and other contractual obligations and commitments.

We and Five Point Energy LLC currently anticipate collectively contributing $500 million in follow-on capital to fund future growth in our Deep Blue Midland Basin LLC joint venture projects and acquisitions.

Return of Capital Commitment

Our board of directors has approved a return of capital commitment of at least 50% of our quarterly Adjusted Free Cash Flow to our stockholders through repurchases under our share repurchase program, base dividends and variable dividends. The remainder of our Adjusted Free Cash Flow will be used primarily to reduce debt. On February 19, 2026, our board of directors declared a base cash dividend for the fourth quarter of 2025 of $1.05 per share of common stock.

Future base and variable dividends are at the discretion of our board of directors, and the board of directors may change the dividend amount from time to time based on our outlook for commodity prices, liquidity, debt levels, capital resources, Adjusted Free Cash Flow and other factors. We can provide no assurance that dividends will be authorized or declared in the future or as to the amount and type of any future dividends. Any future dividends, whether base or variable, if declared and paid, will by their nature fluctuate based on our free cash flow, which will depend on a number of factors beyond our control, including commodity prices.

On July 31, 2025, our board of directors approved an increase in our common stock repurchase program from $6.0 billion to $8.0 billion, excluding the 1% U.S. federal excise tax on certain repurchases of stock by publicly traded U.S. corporations enacted as part of the IRA. Since the inception of the stock repurchase program through February 20, 2026, we
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have repurchased an aggregate 40.69 million shares of our common stock for a total cost of $5.7 billion, which includes $637 million for the repurchase of 4.0 million shares from SGF, excluding excise tax, leaving approximately $2.3 billion for future repurchases under such stock repurchase program. Subject to regulatory restrictions and other factors discussed elsewhere in this report, we intend to continue to purchase shares under this repurchase program opportunistically with available funds primarily from cash flow from operations and liquidity events such as the sale of assets while maintaining sufficient liquidity to fund our capital expenditure programs; however, the stock repurchase program is at the discretion of our board of directors and can be amended, terminated or suspended at any time. Repurchases may be executed in privately negotiated or open-market transactions, consistent with Rule 10b-18 under the Securities Exchange Act of 1934 and other applicable requirements. All shares repurchased will be retired. See Note 9— Stockholders’ Equity and Earnings (Loss) Per Share in Item 8. Financial Statements and Supplementary Data of this report for further discussion of our stock repurchase program.

Guarantor Financial Information

Diamondback E&P is the sole guarantor under the indentures governing the outstanding Guaranteed Senior Notes.

Guarantees are “full and unconditional,” as that term is used in Regulation S-X, Rule 3-10(b)(3), except that such guarantees will be released or terminated in certain circumstances set forth in the indentures governing the Guaranteed Senior Notes, such as, with certain exceptions, (i) in the event Diamondback E&P (or all or substantially all of its assets) is sold or disposed of, (ii) in the event Diamondback E&P ceases to be a guarantor of or otherwise be an obligor under certain other indebtedness, and (iii) in connection with any covenant defeasance, legal defeasance or satisfaction and discharge of the relevant indenture.

Diamondback E&P’s guarantees of the Guaranteed Senior Notes are senior unsecured obligations and rank senior in right of payment to any of its future subordinated indebtedness, equal in right of payment with all of its existing and future senior indebtedness, including its obligations under its revolving credit facility and effectively subordinated to any of its existing and future secured indebtedness, to the extent of the value of the collateral securing such indebtedness.

The rights of holders of the Guaranteed Senior Notes against Diamondback E&P may be limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law. Each guarantee contains a provision intended to limit Diamondback E&P’s liability to the maximum amount that it could incur without causing the incurrence of obligations under its guarantee to be a fraudulent conveyance. However, there can be no assurance as to what standard a court will apply in making a determination of the maximum liability of Diamondback E&P. Moreover, this provision may not be effective to protect the guarantee from being voided under fraudulent conveyance laws. There is a possibility that the entire guarantee may be set aside, in which case the entire liability may be extinguished.

The following tables present summarized financial information for Diamondback Energy, Inc., as the parent, and Diamondback E&P, as the guarantor subsidiary, on a combined basis after elimination of (i) intercompany transactions and balances between the parent and the guarantor subsidiary, and (ii) equity in earnings from and investments in any subsidiary that is a non-guarantor. The information is presented in accordance with the requirements of Rule 13-01 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of results of operations or financial position had the guarantor subsidiary operated as an independent entity.

December 31, 2025
Summarized Balance Sheets: (In millions)
Assets:
Current assets $ 844 
Property and equipment, net $ 19,670 
Other noncurrent assets $ 142 
Liabilities:
Current liabilities $ 3,304 
Intercompany accounts payable, non-guarantor subsidiary $ 6,970 
Long-term debt $ 11,540 
Other noncurrent liabilities $ 2,186 

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Year Ended December 31, 2025
Summarized Statement of Operations: (In millions)
Revenues $ 6,765 
Income (loss) from operations (1)
$ (1,296)
Net income (loss) $ (1,001)

(1) During the year ended December 31, 2025, the Company recorded a significant noncash impairment that is reflected in the summarized results of the guarantor group. This impairment is not indicative of cash flows available for debt service.

Critical Accounting Estimates

The discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States.

Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated by our management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities and our disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates and assumptions on a regular basis. Critical accounting estimates are those estimates made in accordance with generally accepted accounting principles that involve a significant level of estimation uncertainty and have had or are reasonably likely to have a material impact on the financial condition or results of operations of the registrant. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

We consider the following to be our most critical accounting estimates and have reviewed these critical accounting estimates with the Audit Committee of our board of directors.

Oil and Natural Gas Accounting and Reserves

We account for our oil and natural gas producing activities using the full cost method of accounting, which is dependent on the estimation of proved reserves to determine the rate at which we record depletion on our oil and natural gas properties and whether the value of our evaluated oil and natural gas properties is permanently impaired based on the quarterly full cost ceiling impairment test. Further, we utilize estimated proved reserves to assign fair value to acquired proved oil and natural gas properties including mineral and royalty interests. As such, we consider the estimation of proved reserves to be a critical accounting estimate.

Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Proved oil and natural gas reserve estimates and their associated future net cash flows were prepared by our internal reservoir engineers and audited by Ryder Scott Company, L.P., independent petroleum engineers, as of December 31, 2025, 2024 and 2023. The process of estimating oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. Significant inputs included in the calculation of future net cash flows include our estimate of operating and development costs, anticipated production of proved reserves and other relevant data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time, and reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. Although every reasonable effort is made to ensure that reported reserve estimates represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future depletion of capitalized costs and result in impairment of assets that may be material. Revisions of previous reserve estimates accounted for approximately $4.2 billion, or 143% of the net change in the standardized measure of our total reserves from December 31, 2024 to December 31, 2025. The Company recorded a material impairment during the year ended December 31, 2025 as discussed in Note 5— Property and Equipment in Item 8. Financial Statements and Supplementary Data of this report. No impairments were recorded for our proved oil and gas properties during the years ended December 31, 2024 and 2023. Based on the historical 12-month average trailing SEC prices
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for oil and natural gas throughout 2025 and into 2026, we are currently projecting a material full cost ceiling impairment in the first quarter of 2026. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties, income tax rate assumptions and other factors will determine our actual ceiling test calculation and impairment analysis in future periods. Based on the number of factors that may impact our future estimate of proved reserves, we are currently unable to determine an estimate of the amount or range of amounts of any potential impairment charge in the first quarter of 2026. Impairment charges affect our results of operations but do not reduce our cash flow.