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

Our business and operations are subject to many risks. The risks described below may not be the only risks we face, as our business and operations may also be subject to risks that we do not yet know of, or that we currently believe are immaterial. If any of the events or circumstances described below actually occurs, our business, financial condition, results of operations and/or cash flows could be materially and adversely affected and the trading price of our common stock could decline. The following risk factors should be read in conjunction with the other information contained herein, including the consolidated financial statements and the related notes. Unless the context requires otherwise, "we," "us," "our" and "EOG" refer to EOG Resources, Inc. and its subsidiaries.

•the actions of other crude oil producing and exporting nations, including the Organization of Petroleum Exporting Countries;

•worldwide economic conditions, geopolitical factors and political conditions, including, but not limited to, the imposition of tariffs or; trade orpolicies, trade agreements and trade restrictions; other economic sanctions or barriers; and political instability or armed conflictconflicts in oil and gas producing regions;

•the availability, proximity and capacity of appropriate transportation, gathering, processing, compression, storage, transportation, refining, liquefaction and export facilities;

•the economic and financial impact of epidemics, pandemics or other public health issues, such as the COVID-19 pandemic.issues.

We make, and expect to continue to make, substantial capital expenditures for the acquisition, exploration, development and production of crude oil, NGLs and natural gas reserves as well as for the gathering, processing and transportation of our production volumes. We intend to financefund our capital expenditures primarily through our cash flows from operations and cash on hand and, if and as necessary, commercial paper borrowings, bank borrowings, borrowings under our revolving credit facility and public and private debt and equity offerings.

Lower crude oil, NGLs and natural gas prices, however, reduce our cash flows and could also delay or impair our ability to consummate any planned acquisitions or divestitures. Further, if the condition of the credit and capital markets materially declines, we might not be able to obtain financing on terms we consider acceptable, if at all. In addition, weakness and/or volatility in domestic and global financial markets or economic conditions or a depressed commodity price environment may increase the interest rates that lenders and commercial paper investors require us to pay or otherwise adversely affect our ability to finance our capital expenditures through debt or equity offerings or other borrowings.financing transactions.

In addition, companies in the oil and gas sector may be exposed to increasing reputational risks and, in turn, certain financial risks. For example, certain financial institutions, investment advisors and sovereign wealth, pension and endowment funds, in response to concerns related to climate change and the requests and other influence of environmental groups and similar stakeholders, have from time to time elected to shift some or all of their investments and financing away from oil and gas-related sectors. Additional financial institutions and other investors maymay, in the future, elect to do likewise or may impose more stringent conditions with respect to investments in, and financing of, oil and gas-related sectors. As a result, fewer financial institutions and other investors may be willing to invest in, and provide capital to, companies in the oil and gas sector.

A material reduction in capital available to the oil and gas sector could make it more difficult (e.g., due to a lack of investor interest in our debt or equity securities) and/or more costly (e.g., due to higher interest rates on our debt securities or other borrowings) to secure funding for our operations, which, in turn, could adversely affect our ability to successfully carry out our business strategy and could have a material and adverse effect on our business, financial condition and operations.

The rate of production from crude oil and natural gas properties generally declines as reserves are produced. Except to the extent that we conduct successful exploration, exploitation and development activities resulting in additional reserves, acquire additional properties containing reserves or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, our reserves will decline as they are produced. Maintaining our production of crude oil, NGLs and natural gas at, or increasing our production from, current level,levels, is, therefore, highly dependent upon our level of success in acquiring or finding additional reserves, which may be adversely impacted by bans or restrictions on leasing and/or drilling. To the extent we are unsuccessful in acquiring or finding additional reserves, our future cash flows and results of operations and, in turn, the trading price of our common stock could be materially and adversely affected.

Our ability to declare and pay regular or special dividends on our common stock and repurchase shares of our common stock is subject to certain factors and considerations.

Regular and special dividends on our common stock and repurchases of our common stock are authorized and determined by our Board in its sole discretion and depend upon a number of factors,factors and considerations, including:

•cash available for dividends or share repurchases;

•our financial condition, especially in relation to the anticipated future capital expenditures and other commitments requiredrequiring cash necessary to conduct our operations and carry out our business strategy;

We use financial derivative instruments (primarily financial basis swap, price swap, option, swaption and collar contracts) and, in certain cases, fixed price physical sales contracts to hedge the impact of fluctuations in crude oil, NGLs and natural gas prices on our results of operations and cash flows. To the extent that we engage in hedging activities to protect ourselves against commodity price declines, we may be prevented from fully realizing the benefits of increases in crude oil, NGLs and natural gas prices above the prices established by our hedging contracts. Further, a majority of our forecasted production for 20252026 is subject to fluctuating market prices. To the extent we do not hedge our production volumes for 20252026 and beyond, we may be materially and adversely impacted by any declines in commodity prices, which may result in lower net cash provided by our operating activities. In addition, our hedging activities may expose us to the risk of financial loss in certain circumstances, including instances in which the counterparties to our hedgingfinancial contractsderivative instruments fail to perform under the contracts.

We have various customers for the crude oil, natural gas and related commodities that we produce as well as various other contractual counterparties, including several financial institutions and affiliates of financial institutions. Domestic and global economic conditions, including the financial condition of financial institutions generally, may adversely affect the ability of our customers and other contractual counterparties to pay amounts owed to us from time to time and to otherwise satisfy their contractual obligations to us, as well as their ability to access the credit and capital markets for such purposes.

The inability of our customers and other contractual counterparties to pay amounts owed to us and/or to otherwise satisfy their contractual obligations to us may materially and adversely affect our business, financial condition, results of operations and cash flows.

We maintain insurance against many, but not all, such losses and liabilities in accordance with what we believe are customary industry practices and in amounts and at costs that we believe to be prudent and commercially practicable. However, the occurrence of any of these events and any losses or liabilities incurred as a result of such events, if uninsured or in excess of our insurance coverage, would reduce the funds available to us for our operations and could, in turn, have a material and adverse effect on our business, financial condition and results of operations. InFurther, in the future, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates.rates or at all. As a result of market conditions, premiums, retentions and deductibles for our insurance policies will change over time and could escalate.increase. In addition, some forms of insurance may become unavailable or unavailable on economically acceptable terms.

Water is an essential component of our operations, both during drilling operations and completions operations. Limitations or restrictions on our ability to secure sufficient amounts of water (including limitations resulting from natural causes such as drought) could materially and adversely impact our operations. Further, severe drought conditions can result in local authorities taking steps to restrict the use of water in their jurisdiction for drilling and completions in order to protect the local water supply. If we are unable to obtain water to use in our operations from local sources, we may need to obtain water from sources that are more distant from our drilling sites, resulting in increased costs, which could have a material and adverse effect on our financial condition, results of operations and cash flows.

If we acquire crude oil, NGLs andor natural gas properties, our failure to fully identify existing and potential issues, to accurately estimate reserves, production rates or costs, or to effectively integrate the acquired properties into our operations could materially and adversely affect our business, financial condition and results of operations.

From time to time, we seek to acquire crude oil and natural gas properties. Although we perform reviews of properties to be acquired in a manner that we believe is dulyare diligent and consistent with industry practices, reviews of records and properties may not necessarily reveal existing or potential issues (such as title defects or environmental issues), nor may they permit us to become sufficiently familiar with the properties in order to fully assess their deficiencies and potential. Even when issues with a property are identified, we often may assume environmental and other risks and liabilities in connection with acquired properties pursuant to the acquisition agreements.

In addition, there are numerous uncertainties inherent in estimating quantities of crude oil, NGLs and natural gas reserves (as discussed further above), actual future production rates and associated costs with respect to acquired properties. Actual reserves, production rates and costs may vary substantially from those assumed in our estimates. In addition, an acquisition may have a material and adverse effect on our financial condition and results of operations, particularly during the periods in which the operations of the acquired properties are being integrated into our ongoing operations or if we are unable to effectively integrate the acquired properties into our ongoing operations.operations or achieve anticipated synergies.

We compete with major integrated oil and gas companies, government-affiliated oil and gas companies and other independent oil and gas companies for the acquisition of licenses, concessions and leases, properties and reserves and access to the facilities, equipment, materials, services and employees and other personnel (including geologists, geophysicists, engineers and other specialists) necessary to explore for, develop, produce, market and transport crude oil, NGLs and natural gas. Certain of our competitors have financial and other resources substantially greater than those we possess and have established strategic long-term positions or strong governmental relationships in countries or areas in which we may seek new or expanded entry. As a consequence, we may be at a competitive disadvantage in certain respects, such as in bidding for drilling rights or in accessing and retaining necessary services, facilities, equipment, materials and personnel. In addition, our larger competitors may have a competitive advantage when responding to factors that affect demand for crude oil, NGLs and natural gas, such as changing worldwide prices and levels of production and the cost and availability of alternative fuels. We also face competition from alternative energy sources, such as renewable energy sources.

Governmental and regulatory bodies, investors, consumers, industry and other stakeholders have been increasingly focused on climate change matters in recent years. For example, (i) in March 2024, the U.S. Securities and Exchange Commission (SEC) finalized extensive climate-related disclosure rules that would require U.S. public companies to significantly expand the climate-related disclosures in their SEC filings (although the newthese rules have been stayed pendingin judicialabeyance reviewby andthe U.S. Court of Appeals for the Eighth Circuit until such time as the SEC has requestedreconsiders the courtchallenged torules pauseby furthernotice-and-comment judicialrulemaking proceedings,or pendingrenews theits SEC's determinationdefense of the appropriate next stepsrules), (ii) in September 2023, California passed climate-related disclosure mandates which are broader than the SEC's final rules and (iii) in November 2023, the European Union approved methane emissions limits on crude oil and natural gas imports beginning in 2030. This focus, together with changes in consumer and industrial/commercial behavior, preferences and attitudes with respect to the generation and consumption of energy, the use of crude oil, NGLs and natural gas and the use of products manufactured with, or powered by, crude oil, NGLs and natural gas, may result in (i) the enactment of climate change-related regulations, policies and initiatives (at the government, corporate and/or investor community levels), including alternative energy requirements, energy conservation measures and emissions-related legislation, (ii) technological advances with respect to the generation, transmission, storage and consumption of energy (e.g., wind, solar and hydrogen power, smart grid technology and battery technology) and (iii) increased availability of, and increased consumer and industrial/commercial demand for, non-hydrocarbon energy sources (e.g., alternative energy sources. such as renewable energy sources) and products manufactured with, or powered by, non-hydrocarbon sources (e.g., electric vehicles and renewable residential and commercial power supplies). These developments may adversely affect the demand for products manufactured with, or powered by, crude oil, NGLs and natural gas and the demand for, and in turn the prices of, the crude oil, NGLs and natural gas that we sell. See the risk factors above for a discussion of the impact of commodity prices (including fluctuations in commodity prices) on our financial condition, cash flows and results of operations.

Further, climate change-related developments (such as the climate-related disclosure mandates as referenced above) may result in negative perceptions of the oil and gas industry and, in turn, reputational risks associated with the exploration for, and production of, hydrocarbons. Such negative perceptions and reputational risks may adversely affect our ability to successfully carry out our business strategy, for example, by adversely affecting the availability and cost of capital to us. For further discussion of the potential impact of such risks on our financial condition, cash flows and results of operations, see the discussion below in this section and in the section above entitled "Risks Related to Our Operations."

New or revised rules, regulations and policies may be issued, and new legislation may be proposed,enacted, that could impact the oil and gas exploration and production industry. Such rules, regulations, policies and legislation may affect, among other things, (i) permitting for oil and gas drilling on state, tribal and federal lands, (ii) the leasing of state, tribal and federal lands for oil and gas development, (iii) the regulation and disclosure of greenhouse gas (GHG) emissions and/or other climate change-related matters associated with oil and gas operations, (iv) the use of hydraulic fracturing on state, tribal and federal lands, (v) the calculation of royalty payments in respect of oil and gas production from state, tribal and federal lands (including, but not limited to, an increase in applicable royalty percentages), (vi) U.S. federal income tax laws applicable to oil and gas exploration and production companies and (vii) the use of financial derivative instruments to hedge the financial impact of fluctuations in crude oil, NGLs and natural gas prices.

Further, such regulatory, legislative and policy changes may, among other things, result in additional permitting and disclosure requirements, additional operating restrictions and/or the imposition of various conditions and restrictions on drilling and completioncompletions operations or other aspects of our business, any of which could lead to operational delays, increased operating and compliance costs and/or other impacts on our business and operations and could materially and adversely affect our business, results of operations, financial condition and capital expenditures.

Our crude oil, NGLs and natural gas operations and supporting activities are regulated extensively by federal, state, tribal and local governments and regulatory agencies, both domestically and in the foreign countries in which we do business, and are subject to interruption or termination by governmental and regulatory authorities based on environmental, health, safety or other considerations. Moreover, we have incurred and will continue to incur costs in our efforts to comply with the requirements of environmental, health, safety and other regulations. Further, the regulatory environment could change in ways that we cannot predict and that might substantially increase our costs of compliance and/or adversely affect our business and operations and, in turn, materially and adversely affect our results of operations, financial conditioncondition, cash flows and capital expenditures.

The regulation of hydraulic fracturing is primarily conducted at the state and local level through permitting and other compliance requirements and, further, some state and local governments have imposed or have considered imposing various conditions and restrictions on drilling and completioncompletions operations. The U.S. Environmental Protection Agency (U.S. EPA) hashas, however, issued certain regulations relating to hydraulic fracturing and there have been various other proposals to regulate hydraulic fracturing at the federal level.

We will continue to monitor and assess any proposed or new policies, legislation, regulations and treaties in the areas where we operate to determine the impact on our operations and take appropriate actions, where necessary. We are unable to predict the timing, scope and effect of any currently proposed or future laws, regulations or treaties, but the direct and indirect costs of such laws, regulations and treaties (if enacted) could materially and adversely affect our business, results of operations, financial condition and capital expenditures. See also the risk factor below regarding the provisions of the Dodd-Frank Wall Street Reform and Consumer Protection Act with respect to regulation of financial derivative transactions and entities (such as EOG) that participate in such transactions.

We have developed, and will continue to develop, targets and ambitions related to our environmental and safety initiatives, including, but not limited to, our emissions reduction targets and our ambition to reach net-zero Scope 1 and Scope 2 GHGcurrent emissions by 2040.targets. Our public disclosures and other statements related to these initiatives, targets and ambitions reflect our plans and expectations at the time such disclosures and statements are made and are not a guarantee the initiatives will be successfully developed, implemented and carried out or that the targets or ambitions will be achieved or achieved on the anticipated timelines or that, if achieved, will be sustained.

Our ability to achieve and, if achieved, sustain these targets and ambitions is subject to numerous factors and contingencies, some of which are outside of our control and include (among other commercial, operational, technological, financial, legal and regulatory factors and contingencies) evolving government regulation, the pace of changes in technology, the successful development and deployment of existing or new technologies and business solutions on a commercial scale, the availability, timing and cost of necessary equipment, goods, services and personnel, and the availability of requisite financing and federal and state incentive programs. For example, we are exploring technology to capture and store carbon dioxide emissions, which includes a pilot carbon capture and storage (CCS) project related to our operations. CCS projects face operational, technological, legal and regulatory risks that could be considerable due to the early-stage nature of such projects and the CCS sector generally. Our ability to successfully develop, implement and carry out our CCS activities will depend on a number of factors that we will not be able to fully control, including timing of regulatory approvals and availability of subsurface pore space. Further, financial or tax incentives in respect of CCS projects could be changed or terminated. In addition, our failure to properly operate a CCS project could put at risk certain governmental tax credits and potentially expose us to commercial, legal, reputational and other risks.

Further, asAs both emissions sources and emissions measurements and related technologies, regulations, protocols and methodologies continue to evolve, the emissions that will be included in our emissions inventory may change. This means our current targets and net-zero ambition using calculations and forecasts of our current emissions inventory could be more challenging to meet and sustain if our emissions inventory expands due to evolving practices and/or new regulations. For example, recently adopted U.S. EPA regulations will expand the scope of emissions sources and revise calculation methods. This means a target that we have achieved and maintained in the past could be more challenging to meet and sustain if our emissions inventory changes. Also, while there is rapid evolution taking place in the technologies we may be able to use to reduce emissions and achieve and maintain our targets and net-zero ambition,targets, the timing, cost and anticipated success of these technologies may change.

These uncertainties, evolving practices and regulations and challenges around emissions measurement and reporting and emissions reduction technologies may result in our revising our existing targets, revising our ambitiontargets and/or setting new targets, as well as how we define and work to achieve our net-zero ambition.targets. In addition, the pursuit and achievement of our current or future initiatives, targets and ambitions relating to the reduction of GHG emissions and other environmental or safety-related initiatives may increase our costs – for example, by requiring us to purchase emissions credits or offsets, the availability and price of which are outside of our control - and may impact or otherwise limit our ability to execute on our business strategy. Also, our continuing efforts to research, establish, accomplish and accurately report on our emissions and other environmental or safety-related initiatives, targets and ambitions may create additional operational risks and expenses and expose us to reputational, legal and other risks.

In addition, infrom recenttime yearsto time there has been increasedparticular investor and regulatory focus on environmental and social matters.matters, Inincluding, in addition to climate change, there has been increased investor and regulatory focus on topics such as human rights and human capital management in companies' own operations as well as across their supply chains.matters. If our related initiatives, targets and ambitions do not meet our investors' or other stakeholders' evolving expectations and standards, investment in our stock may be viewed as less attractive and our reputationreputation, andrelationships contractual,with employmentinvestors and other business relationships may be adversely impacted.

Lastly, as noted above, the SEC, in March 2024, finalized extensive climate-related disclosure rules that would require U.S. public companies to significantly expand the climate-related disclosures in their SEC filings (although the newthese rules have been stayed pendingin judicialabeyance reviewby andthe U.S. Court of Appeals for the Eighth Circuit until such time as the SEC has requestedreconsiders the courtchallenged torules pauseby furthernotice-and-comment judicialrulemaking proceedings,or pendingrenews theits SEC's determinationdefense of the appropriate next stepsrules). To the extent the rules are implemented, we could incur increased costs related to the assessment and disclosure of climate-related information.

In addition, certain countries, including countries where EOG currently has operations or may in the future have operations, have implemented (via legislation), or may implement, a global minimum tax (GMT). While such GMT legislation has had, to date, no material impact on EOG, no accurate prediction can be made as to (i) which additional countries or jurisdictions will participate and enact GMT legislation and (ii) what the specific provisions or impact on EOG of any such enacted GMT legislation would be. Recent changes to the GMT rules would exempt U.S. multinationals (like EOG) from certain of its provisions after 2025, if ultimately legislated into law in the countries where EOG has current or may have future operations.

•currency restrictions orand exchange rate fluctuations.

Our international operations may also be adversely affected by U.S. laws and policies affecting foreign trade and taxation, including tariffs orand trade or other economic sanctions; modifications to, or withdrawal from, international trade treaties; and U.S. laws with respect to participation in boycotts that are not supported by the U.S. government. The realization of any of these factors could materially and adversely affect our business, financial condition and results of operations.

EOG realized net income of $6,403$4,980 million duringfor 20242025 as compared to net income of $7,594$6,403 million for 2023.2024. At December 31, 2024,2025, EOG's total estimated net proved reserves were 4,7485,514 million barrels of oil equivalent (MMBoe), an increase of 250766 MMBoe from December 31, 2023.2024. During 2024,2025, net proved crude oil and condensate and natural gas liquids (NGLs) reserves increased by 218187 million barrels (MMBbl), and net proved natural gas reserves increased by 1923,470 billion cubic feet, or 32579 MMBoe, in each case from December 31, 2023.2024.

Commodity Prices. Prices for crude oil and condensate, NGLs and natural gas have historically been volatile. This volatility is expected to continue due to the many uncertainties associated with the world political and economic environment andenvironment, the global supply of, and demand for, crude oil, NGLs and natural gas andgas, the availability of other energy supplies, the relative competitive relationships of the various energy sources in the view of consumerssupplies and other factors.factors, including tariffs, trade policies and agreements and trade barriers or other restrictions imposed by the U.S. government or other governments and the related impact of such measures on commodity and financial markets.

For the year ended December 31, 2024,2025, the average U.S. New York Mercantile Exchange (NYMEX) crude oil and natural gas prices were $75.72$64.78 per barrel and $2.27$3.43 per million British thermal units (MMBtu), respectively, representing decreasesa decrease of 2%14% and 17%,an increase of 51%, respectively, from the average NYMEX prices for the year ended December 31, 2023.2024. Market prices for NGLs are influenced by the components extracted, including ethane, propane and butane and natural gasoline, among others, and the respective market pricing for each component.

Operating Efficiencies. EOG has undertaken (and continues to undertake) initiatives to increase its drilling, completioncompletions and operating efficiencies and improve the performance of its wells and, in turn, mitigate the inflationary pressures experienced in prior periods.wells. Such initiatives include (among others): (i) EOG's downhole drilling motor program, which has resulted in increased footage drilled per day and, in turn, reduced drilling times; (ii) enhanced techniques for completing its wells, which has resulted in increased footage completed per day and pumping hours per day; (iii) drilling extended laterals, which hashave resulted in a decrease in cost per foot drilled; and (iv) EOG's self-sourced sand program, which has provided supply certainty and resulted in costoperational savings for the sand utilizedefficiencies in its well completion operations. In addition, EOG has entered into agreements with its service providers from time to time, when available and advantageous, to secure the costs and availability of certain drilling and completioncompletions services it utilizes as part of its operations.

EOG plans to continue with these initiatives and actions, though there can be no assurance that such efforts will offset,be largelysuccessful orand atsufficient all,to offset the impacts of any future inflationary pressures (such as from tariffstariffs, other trade barriers or other macroeconomic factors) on EOG's operating costs and capital expenditures, cash flows and results of operations. Further, there can be no assurance that the factors contributing to any such futurepressures inflationaryor pressuresfactors will not impact EOG's ability to conduct its future day-to-day drilling, completion and production operations. See ITEM 1A. Risk Factors, for related discussion.

In 2024,2025, EOG continued to focus on initiatives to increase its drilling, completion and operating efficiencies and improve well performance and, in turn, mitigate the inflationary pressures on its operating costs and capital expenditures experienced in prior periods.performance. In addition, EOG continued to evaluate certain potential crude oil and condensate, NGLs and natural gas exploration and development prospects and to look for opportunities to add drilling inventory through leasehold acquisitions, farm-ins, exchanges or tactical or bolt-on acquisitions. On a volumetric basis, as calculated using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas, crude oil and condensate and NGLs production accounted for approximately 72%68% and 73%72% of EOG's United States production during 20242025 and 2023,2024, respectively. During 2024,2025, EOG's drilling and completion activities occurred primarily in the Delaware Basin play, Eagle Ford play and RockyUtica Mountain area.play. EOG's major producing areas in the United States are in New MexicoMexico, Texas and Texas.Ohio. See ITEM 1, Business - Exploration and Production for further discussion regarding EOG's 20242025 United States operations.

Other International. In February 2025, a subsidiary of EOG signed an exploration participation agreement with Bapco Energies B.S.C. (Closed) (Bapco) to evaluate a gas exploration projectprospect in the Kingdom of Bahrain,Bahrain. withIn drillingAugust anticipated to commence in2025, the second halfgovernment of 2025. The transaction, which includes a concession agreement with the Kingdom of Bahrain,Bahrain isapproved subjectthe related concession agreement. As part of the transaction, EOG has a working interest in several producing legacy wells. EOG has commenced drilling of exploratory wells, which are expected to furtherbe government approvals, which the parties anticipate receivingcompleted in the second half of 2025.2026.

EOG continues to evaluate other select exploration,crude developmentoil and exploitationnatural gas opportunities outside the United States, primarily by pursuing exploration opportunities in countries where crude oil and natural gas reserves have been identified.

During 2024,2025, EOG funded $6.7$13.6 billion ($109 million of which was non-cash) in exploration and development and other property, plant and equipment expenditures (excluding asset retirement obligations), paid $2.1$2.2 billion in dividends to common stockholders and paid $3.2$2.6 billion to repurchase shares of common stock, primarily by utilizing net cash provided by its operating activitiesactivities, issuances of senior notes and cash on hand.

Management continuesbelieves to believethat EOG has one of the strongest prospect inventories in EOG's history. When it fits EOG's strategy, EOG will make acquisitions that bolster existing drilling programs or offer incremental exploration and/or production opportunities.

Cash Return Framework. In November 2023, EOG announced an increase in its cash return commitment - specifically, a commitment, effective beginning with fiscal year 2024, to return a minimum of 70%70 percent of annual net cash provided by operating activities before certain balance sheet-related changes, less total capital expenditures, to stockholders through a combination of quarterlyregular dividends, special dividends and share repurchases. For discussion regarding EOG's payment of dividends and share repurchases, see ITEM 1A, Risk Factors, and ITEM 5, Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

On AugustMay 1,30, 2024,2025, the Board declared a quarterly cash dividend on the common stock of $0.91$1.02 per share paid on October 31, 2024,2025, to stockholders of record as of October 17, 2024.2025. This represented an increase from the previous quarterly cash dividend which was $0.975 per share.

On FebruaryNovember 27,6, 2025, the Board declared a quarterly cash dividend on the common stock of $0.975$1.02 per share to be paid on AprilJanuary 30, 2025,2026, to stockholders of record as of AprilJanuary 16, 2025.2026.

During 2024,2025, total operating revenues decreased $488$1,066 million, or 2%,4%, to $22,632 million from $23,698 million from $24,186 million in 2023.2024. Total revenues from sales of EOG's production of crude oil and condensate, NGLs and natural gas, increased $202$90 million, or 1%, to $17,668 million in 2025 from $17,578 million in 2024 from $17,376 million in 2023.2024. Revenues from the sales of crude oil and condensate and NGLs in 20242025 were 91%84% of total revenues from sales of crude oil and condensate, NGLs and natural gas compared to 90%91% in 2023.2024. During 2024,2025, EOG recognized net gains on the mark-to-market of financial commodity and other derivative contracts of $204$13 million compared to net gains of $818$204 million in 2023.2024. Gathering, processing and marketing revenues decreased $6$886 million during 2024,2025, to $4,914 million from $5,800 million fromin $5,8062024. EOG recognized net losses on asset dispositions of $35 million in 2023.2025 EOGcompared recognizedto net gains on asset dispositions of $16 million in 2024 compared to net gains on asset dispositions of $95 million in 2023.2024.

Volume and price statistics for the years ended December 31, 2024,2025, 20232024 and 20222023 were as follows (see Note 11 for segment financial information):

Crude oil and condensate revenues in 20242025 increaseddecreased $173$1,420 million, or 1%,10%, to $12,501 million from $13,921 million from $13,748 million in 2023,2024, primarily due to an increase in production ($491 million), partially offset by a lower composite average crude oil and condensate price ($318$2,239 million), partially offset by an increase in production ($819 million). EOG's composite crude oil and condensate price for 20242025 decreased 2%15% to $65.63 per barrel compared to $77.40 per barrel compared to $79.17 per barrel in 2023.2024. Crude oil and condensate production in 20242025 increased 3%6% to 491522 MBbld as compared to 476491 MBbld in 2023.2024. The increased production was primarily in the Permian BasinUtica and Utica.the Permian Basin.

NGLs revenues in 20242025 increased $222$270 million, or 12%,13%, to $2,376 million from $2,106 million from $1,884 million in 20232024 primarily due to an increase in production ($192$356 million), andpartially offset by a higherlower composite average NGLs price ($30$86 million). EOG's composite average NGLs price increaseddecreased 1%4% to $22.58 per barrel in 2025 compared to $23.40 per barrel in 2024 compared to $23.07 per barrel in 2023.2024. NGLs production in 20242025 increased 10%17% to 246288 MBbld as compared to 224246 MBbld in 2023.2024. The increased production was primarily in the Utica and the Permian Basin.

Natural gas revenues in 20242025 decreasedincreased $193$1,240 million, or 11%,80%, to $2,791 million from $1,551 million from $1,744 million in 20232024 primarily due to a lowerhigher composite natural gas price ($435$783 million), partially offset byand an increase in natural gas deliveries ($242$457 million). EOG's composite average natural gas price decreasedincreased 22%39% to $3.02 per Mcf in 2025 compared to $2.17 per Mcf in 2024 compared to $2.79 per Mcf in 2023.2024. Natural gas deliveries in 20242025 increased 14%30% to 1,9482,533 MMcfd as compared to 1,7111,948 MMcfd in 2023.2024. The increase in production was primarily due to increased production of associated natural gas from the Permian Basin and higher natural gas deliveries in Trinidad.the Utica and Dorado.

Gathering, processing and marketing revenues are revenues generated from sales of third-party crude oil, NGLs and natural gas, as well as fees associated with gathering third-party natural gas and revenues from sales of EOG-owned sand. Purchases and sales of third-party crude oil and natural gas may be utilized in order to balance firm capacity at third-party facilities with production in certain areas and to utilize excess capacity at EOG-owned facilities. EOG sells sand primarily in order to balance the timing of firm purchase agreements with completion operations. Marketing costs represent the costs to purchase third-party crude oil, natural gas and sand and the associated transportation costs, as well as costs associated with EOG-owned sand sold to third parties.

Gathering, processing and marketing revenues less marketing costs in 20242025 decreasedincreased $14$36 million compared to 2023,2024, primarily due to lowerhigher margins on sand sales and natural gas marketing activities,activities and sand sales, partially offset by higherlower margins on crude oil marketing activities.

Lease and well expenses of $1,675 million in 2025 increased $103 million from $1,572 million in 2024 increased $118 million from $1,454 million in 2023 primarily due to increased operating and maintenance costs ($81$89 million), in the United States and increased lease and well administrative expenses ($27$42 million), andpartially increasedoffset by decreased workovers expenditures ($13$38 million), all in the United States. Lease and well expenses increased in the United States primarily due to increased operating activities resulting from increased production.

GP&T costs increased $102$412 million to $2,134 million in 2025 compared to $1,722 million in 2024 compared to $1,620 million in 2023 primarily due to increased production in the Permian BasinUtica ($91$375 million) and the UticaPermian Basin ($35$93 million), partially offset by decreased costs in the Powder River Basin due to reduced operating and maintenance expenses ($17 million), the Eagle Ford play due to lower volumes and reduced third-party fees ($11$45 million) and the BarnettPowder ShaleRiver due to lower gas volumes and operating costsBasin ($5$14 million).

DD&A expenses in 20242025 increased $616$353 million to $4,108$4,461 million from $3,492$4,108 million in 2023.2024. DD&A expenses associated with oil and gas properties in 20242025 were $583$298 million higher than in 2023.2024. The increase primarily reflects increased production in the United States ($233$596 million) and Trinidad ($26$7 million), and increased unit rates in Trinidad ($8 million). This was partially offset by decreased unit rates in the United States ($166$197 million) and in Trinidad ($35 million). In addition, the recording of an adjustment to DD&A recorded in 2024 ($117 million) primarily related to natural gas production used by EOG's domestic gathering systems also contributed to the variance.systems. DD&A expenses associated with other property, plant and equipment in 20242025 were $33$55 million higher than in 20232024 primarily due to an increase in expense related to GP&T assets and equipment.

Exploration costs of $236 million in 2025 increased $62 million from $174 million in 2024 decreased $7 million from $181 million in 2023 primarily due to decreasedincreased geological and geophysical expenditures in Trinidad ($27 million), the United Arab Emirates ($23 million) and the United States ($22$7 million) as well as increased administrative expenses ($11 million), partially offset by increased administrative expenses ($9 million) and increaseddecreased delay rentals ($6$8 million).

Impairments include: amortization of individually insignificant unproved oil and gas property costs as well as impairments of proved oil and gas properties; other property, plant and equipment; individually significant unproved oil and gas property costs; and other assets. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. Unproved properties with individually significant acquisition costs are reviewed individually for impairment. When circumstances indicate that proved oil and gas properties may be impaired, EOG compares expected undiscounted future cash flows at a DD&A group level to the unamortized capitalized cost of the group. If the expected undiscounted future cash flows, based on EOG's estimate of (and assumptions regarding) future crude oil, NGLs and natural gas prices, operating costs, development expenditures, anticipated production from proved reserves and other relevant data (all Level 3 inputs as defined by the FASB's Fair Value Measurement Topic of the Financial Accounting Standards Board's (FASB) Accounting Standards Codification (ASC) (ASC 820)), are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated using the Income Approach described in ASC 820. In certain instances, EOG utilizes accepted offers from third-party purchasers as the basis for determining fair value.

Impairments of proved properties for the year ended December 31, 2024,2025, were primarily due to the write-down to fair value of natural gas and crude oil assets in the RockyBarnett MountainShale area.and Woodford Oil Window, mainly driven by play-specific economics and resource allocation.

Taxes other than income in 20242025 decreased $35$15 million to $1,234 million (7.0% of revenues from sales of crude oil and condensate, NGLs and natural gas) from $1,249 million (7.1% of revenues from sales of crude oil and condensate, NGLs and natural gas) from $1,284 million (7.4% of revenues from sales of crude oil and condensate, NGLs and natural gas) in 2023.2024. The decrease in taxes other than income was primarily due to increaseddecreased severance/production taxes ($60 million), partially offset by decreased state severance tax refunds ($18$30 million), decreasedand increased ad valorem/property taxes ($14 million) and decreased severance/production taxes ($5$10 million), all in the United States.

Other income, net, was $274$212 million in 20242025 compared to other income, net, of $234$274 million in 2023.2024. The increasedecrease of $40$62 million in 20242025 was primarily due to ana increasedecrease in interest income.

The primary sources of cash for EOG during the three-year period ended December 31, 2024,2025, were funds generated from operations and, to a lesser extent,and net proceeds from the issuance of long-term debt and proceeds from asset sales.debt. The primary uses of cash were exploration and development expenditures; funds used in operations; exploration and development expenditures; dividend payments to stockholders; share repurchases and other purchases of treasury stock; netthe cash paid for settlementsacquisition of financialEncino; commodityrepayment derivativeof contractslong-term debt; and other property, plantplant, and equipment expenditures; and repayment of debt.expenditures.

Cash Flow. Net cash provided by operating activities of $10,044 million in 2025 decreased $2,099 million from $12,143 million in 2024 increased $803 million from $11,340 million in 2023 primarily due to aan decreaseincrease in net cash paid for income taxes and tax credit purchases ($450$1,090 million), an increase in cash operating expenses ($696 million), net cash receivedpaid fromfor settlements of financial commodity derivative contracts of $56 million compared to net cash received of $214 million in 2024, an increase in net cash used in working capital and other assets and liabilities ($326$178 million), partially offset by an increase in revenues from sales of crude oil and condensate, NGLs and natural gas ($202 million) and a decrease in net cash used in working capital and other assets and liabilities ($197 million), partially offset by the return in 2023 of cash collateral posted for financial commodity derivative contracts ($324 million) and an increase in cash operating expenses ($185$90 million).

Net cash used in investing activities of $10,936 million in 2025 increased by $4,969 million from $5,967 million in 2024 decreased by $373 million from $6,340 million in 2023 primarily due to athe decreaseacquisition inof net cash used in working capital associated with investing activitiesEncino ($677$4,451 million), andan a decreaseincrease in additions to oil and gas properties ($32$762 million); and a decrease in cash provided by working capital associated with investing activities ($297 million), partially offset by ana increasedecrease in additions to other property, plant and equipment ($219 million) and a decrease in proceeds from the sales of assets ($117$540 million).

Commodity Prices. Prices for crude oil and condensate, natural gas liquids (NGLs) and natural gas have historically been volatile. This volatility is expected to continue due to the many uncertainties associated with the world political and economic environment (e.g., the ongoing conflict in the Middle East and the related disruption of maritime transportation routes for these commodities), the global supply of, and demand for, crude oil,oil and condensate, NGLs and natural gas, the availability of other energy supplies and other factors, including tariffs, trade policies and agreements and trade barriers or other restrictions imposed by the U.S. government or other governments and the related impact of such measures on commodity and financial markets. Compared to its expectations at the beginning of 2026, EOG realized higher crude oil and condensate prices in the first quarterhalf of 2026 and anticipates realizing higher crude oil and condensate prices for the full-year 2026, in each case as a result of the ongoing conflict in the Middle East.

For the first threesix months of 2026, the average U.S. New York Mercantile Exchange (NYMEX) crude oil and natural gas prices were $72.17$82.57 per barrel and $4.96$3.92 per million British thermal units (MMBtu), respectively, representing an increaseincreases of 1%22% and an increase of 36%,10%, respectively, from the average NYMEX prices for the same period in 2025. Market prices for NGLs are influenced by the components extracted, including ethane, propane and butane and natural gasoline, among others, and the respective market pricing for each component.

Including the impact of EOG's NGL financial derivative contracts and based on EOG's tax position, EOG's price sensitivity as of MarchJune 31,30, 2026, for each $1.00 per barrel increase or decrease in crude oil and condensate price, combined with the estimated change in NGL price, is approximately $174$172 million for net income and $223$221 million for pretax cash flows from operating activities, in each case for the full-year 2026.

Including the impact of EOG's natural gas financial derivative contracts and based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for which prices have not (as of MarchJune 31,30, 2026) been determined under long-term marketing contracts, EOG's price sensitivity as of MarchJune 31,30, 2026, for each $0.10 per thousand cubic feet increase or decrease in natural gas price, is approximately $61$60 million for net income and $78$77 million for pretax cash flows from operating activities, in each case for the full-year 2026.

During the first threesix months of 2026, EOG continued to focus on initiatives to increase its drilling, completion and operating efficiencies and improve well performance. In addition, EOG continued to evaluate certain potential crude oil and condensate, NGLs and natural gas exploration and development prospects and to look for opportunities to add drilling inventory through leasehold acquisitions, farm-ins, exchanges or tactical or bolt-on acquisitions. On a volumetric basis, as calculated using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas, crude oil and condensate and NGLs production accounted for approximately 66% and 71%70% of EOG's United States production during the first threesix months of 2026 and 2025, respectively. During the first threesix months of 2026, EOG's drilling and completion activities occurred primarily in the Delaware Basin, the Utica and the Eagle Ford play. EOG's major producing areas in the United States are in New Mexico, Texas and Ohio.

During the first threesix months of 2026, EOG completed its drilling program in the Mento Field located in the Ska, Mento and Reggae Area and continued construction of the Coconut offshore platform.

Other International. As discussed in EOG's Annual Report on Form 10-K for the year ended December 31, 2025, filed on February 24, 2026 (EOG's 2025 Annual Report), EOG entered into exploration programs in both the Kingdom of Bahrain (Bahrain) and the United Arab Emirates.Emirates (UAE). In June 2026, EOG commenced crude oil production in the UAE. EOG expects to advance both programs throughoutduring the remainder of 2026.

2026 Capital and Operating Plan. Total 2026 capital expenditures are estimated to range from approximately $6.3 billion to $6.7 billion, including exploration and development drilling, facilities, leasehold acquisitions, capitalized interest, dry hole costs and other property, plant and equipment and excluding property acquisitions, asset retirement costs, non-cash exchanges and transactions and exploration costs incurred as operating expenses. EOG plans to continue to focus a substantial portion of its exploration and development expenditures in its major producing areas in the United States. In particular, EOG will be focused on United States drilling activity in its plays where it generates the highest rates of return - specifically, in the Delaware Basin, the Utica and the Eagle Ford.Ford play. To further enhance the economics of these plays, EOG expects to continue to improve well performance and to focus on improving operating efficiencies; see the above related discussion. Relative to 2025, full-year oil production for 2026 is expected to increase by approximately 5% and full-year total crude oil,oil and condensate, NGLs and natural gas production for 2026 is expected to increase by approximately 13%.14%. In addition, EOG plans to continue to spend a portion of its anticipated 2026 capital expenditures on leasing acreage and evaluating new prospects.

Capital Structure. One of management's key strategies is to maintain a strong balance sheet. EOG's debt-to-total capitalization ratio was 20% at MarchJune 31,30, 2026 and 21% at December 31, 2025. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.

Dividend Declarations. On February 24, 2026, the Board of Directors (Board) declared a quarterly cash dividend on the common stock of $1.02 per share paid on April 30, 2026, to stockholders of record as of April 16, 2026.

On May 5, 2026, the Board declared a quarterly cash dividend on the common stock of $1.02 per share to be paid on July 31, 2026, to stockholders of record as of July 17, 2026.

The following review of operations for the three months and six months ended MarchJune 31,30, 2026 and 2025 should be read in conjunction with the Condensed Consolidated Financial Statements of EOG and notes thereto included in this Quarterly Report on Form 10‑Q.

Three Months Ended MarchJune 31,30, 2026 vs. Three Months Ended MarchJune 31,30, 2025

Operating Revenues and Other. During the firstsecond quarter of 2026, total operating revenues increased $1,252$3,142 million, or 22%,57%, to $6,921$8,620 million from $5,669$5,478 million for the same period of 2025. Total revenues from sales of EOG's production of crude oil and condensate, NGLs and natural gas for the firstsecond quarter of 2026 increased $760$2,375 million, or 17%,58%, to $5,262$6,483 million from $4,502$4,108 million for the same period of 2025. EOG recognized net gains on the mark-to-market of financial commodity and other derivative contracts of $113$40 million for the firstsecond quarter of 2026 compared to net lossesgains of $191$107 million for the same period of 2025. Gathering, processing and marketing revenues for the firstsecond quarter of 2026 increased $156$764 million, or 12%,61%, to $1,496$2,011 million from $1,340$1,247 million for the same period of 2025. EOG recognized net gains on asset dispositions of $31 million for the first quarter of 2026 compared to net losses on asset dispositions of $1 million for the same period of 2025.

Volume and price statistics for the three-month periods ended MarchJune 31,30, 2026 and 2025 were as follows (see Note 8 for segment financial information):

(2)ProductionCrude oil and condensate volumes are from UAE and Bahrain operations. Natural gas volumes are from Bahrain operations; natural gas realized price represents contract price less partner's processing and distribution costs.

Crude oil and condensate revenues for the firstsecond quarter of 2026 increased $284$1,927 million, or 9%,65%, to $3,577$4,901 million from $3,293$2,974 million for the same period of 2025, primarily due to a higher composite average price ($1,667 million) and an increase of 46.444.6 MBbld, or 9%, in crude oil and condensate deliveries ($304 million), partially offset by a lower composite average price ($20$260 million). Increased production was primarily from the Utica. EOG's composite crude oil and condensate price for the firstsecond quarter of 2026 decreasedincreased 1%51% to $72.47$98.15 per barrel compared to $72.87$64.82 per barrel for the same period of 2025.

NGL revenues for the firstsecond quarter of 2026 increased $92$236 million, or 16%,44%, to $664$770 million from $572$534 million for the same period of 2025 due to an increase of 90.488.4 MBbld, or 37%,34%, in NGL deliveries ($215$182 million), partially offset byand a lowerhigher composite average price ($123$54 million). Increased production was primarily from the Utica and Permian Basin. EOG's composite NGL price for the firstsecond quarter of 2026 decreasedincreased 16%8% to $22.20$24.41 per barrel compared to $26.29$22.70 per barrel for the same period of 2025.

Natural gas revenues for the firstsecond quarter of 2026 increased $384$212 million, or 60%,35%, to $1,021$812 million from $637$600 million for the same period of 2025, primarily due to an increase of 940860 MMcfd, or 45%,39%, in natural gas deliveries ($289$232 million), andpartially offset by a higherlower composite average price ($95$20 million). Increased deliveries were primarily from the Utica and Permian Basin. EOG's composite natural gas price for the firstsecond quarter of 2026 increaseddecreased 10%2% to $3.76$2.89 per Mcf compared to $3.41$2.96 per Mcf for the same period of 2025.

During the firstsecond quarter of 2026, EOG recognized net gains on the mark-to-market of financial commodity and other derivative contracts of $113$40 million compared to net lossesgains of $191$107 million for the same period of 2025. The net gains of $113$40 million included gains of $119$11 million related to the Brent crude oil (Brent) linked gas sales contract. During the firstsecond quarter of 2026, net cash paidreceived forfrom settlements of financial commodity derivative contracts was $53$45 million compared to net cash paid for settlements of financial commodity derivative contracts of $38$24 million for the same period of 2025.

Gathering, processing and marketing revenues are revenues generated from sales of third-party crude oil,oil and condensate, NGLs and natural gas, as well as fees associated with gathering third-party natural gas and revenues from sales of EOG-owned sand. Purchases and sales of third-party crude oil and condensate and natural gas may be utilized in order to balance firm capacity at third-party facilities with production in certain areas and to utilize excess capacity at EOG-owned facilities. Marketing costs represent the costs to purchase third-party crude oil,oil and condensate, natural gas and sand and the associated transportation costs, as well as costs associated with EOG-owned sand sold to third parties.

Gathering, processing and marketing revenues less marketing costs for the firstsecond three monthsquarter of 2026 increased $97$30 million as compared to the same period of 2025 primarily due to higher margins on crude oil and condensate marketing activities.

Operating and Other Expenses. For the firstsecond quarter of 2026, operating expenses of $4,323$5,092 million were $513$1,361 million higher than the $3,810$3,731 million incurred during the firstsecond quarter of 2025. The following table presents the costs per barrel of oil equivalent (Boe) for the three-month periods ended MarchJune 31,30, 2026 and 2025:

The primary factors impacting the cost components of per-unit rates of lease and well, GP&T, DD&A, G&A and interest expense, net for the three months ended MarchJune 31,30, 2026, compared to the same period of 2025, are set forth below. See "Operating Revenues and Other" above for a discussion of volumes.

Lease and well expenses of $462$467 million for the firstsecond quarter of 2026 increased $61$71 million from $401$396 million for the same prior year period primarily due to increased operating and maintenance costs in the United States ($44$50 million) and increased lease and well administrative expenses in the United States ($19$18 million).

GP&T costs of $654$676 million for the firstsecond quarter of 2026 increased $214$221 million from $440$455 million for the same prior year period primarily due to increased GP&T costs related to increased production in the Utica ($221$219 million) and Permian Basin ($11$9 million), partially offset by decreased costs in the Eagle Ford play ($15$7 million).

DD&A expenses for the firstsecond quarter of 2026 increased $180$206 million to $1,193$1,259 million from $1,013$1,053 million for the same prior year period. DD&A expenses associated with oil and gas properties for the firstsecond quarter of 2026 were $172$201 million higher than the same prior year period. The increase primarily reflects increased production in the United States ($248$229 million) and Trinidad ($6 million), and increased unit rates in Trinidad ($9 million), partially offset by decreased unit rates in the United States ($69 million) and Trinidad ($9$47 million). DD&A expenses associated with other property, plant and equipment for the firstsecond quarter of 2026 were $8$5 million higher than the same prior year period primarily related to GP&T assets and equipment.

G&A expenses of $185$213 million for the firstsecond quarter of 2026 increased $14$27 million from $171$186 million for the same prior year period primarily due to increased employee-related costs.costs ($23 million) and legal expenses ($12 million), partially offset by decreased professional services costs primarily related to the Encino acquisition ($11 million).

Interest expense, net of $66$67 million for the firstsecond quarter of 2026 increased $19$16 million compared to the same prior year period primarily due to the issuance in July 2025 of the $1,250 million aggregate principal amount of 5.350% Senior Notes due 2036 ($17 million), $1,250 million aggregate principal amount of 5.000% Senior Notes due 2032 ($16 million), $500 million aggregate principal amount of 5.950% Senior Notes due 2055 ($7 million) and $500 million aggregate principal amount of 4.400% Senior Notes due 2028 ($6 million), and the issuance in November 2025 of the $750 million aggregate principal amount of 4.400% Senior Notes due 2031 ($9 million) and $250 million aggregate principal amount of 5.950% Senior Notes due 2055 ($4 million), partially offset by increased capitalized interest ($25$27 million), the repayment in December 2025 of the $750 million aggregate principal amount of 4.15% Senior Notes due 2026 ($8 million), and the maturity in April 2025absence of financing commitment costs related to the $500Encino million aggregate principal amount of 3.15% Senior Notes due 2025acquisition ($4$6.5 million).

The following table sets forth impairments for the firstsecond quarter of 2026 and 2025 (in millions):

Other income, net of $23$38 million for the firstsecond quarter of 2026 decreased $42$17 million from $65$55 million for the same prior year periodperiod. The decrease was primarily due to decreased interest income ($37 million) and an increase in deferred compensation expense ($6 million).income.

Income taxes of $575$775 million for the firstsecond quarter of 2026 increased from $414income taxes of $406 million for the firstsecond quarter of 2025 primarily due to increased pretax income. The net effective tax rate for the firstsecond quarter of 2026 increaseddecreased to 23%22% from 22%23% for the firstsecond quarter of 2025.