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YoY shift: Neutral
Year-over-year tone shift - average net-tone change across Risk Factors and MD&A vs the prior 10-K. This filing is -0.10pp more bearish than last year's.
Why YoY instead of absolute: the LM lexicon has ~6.6× more negative words than positive (legal/risk-disclosure language is heavy on hedging), so every 10-K reads bearish on raw tone. Year-over-year change strips that bias and surfaces the actual shift in management's framing.
Tone shift by section
The two components the gauge averages: how Risk Factors and MD&A each shifted in net tone versus last year's 10-K. The headline above is their average, so a green needle over a soft section just means the other section carried it.
Risk Factors
-0.06pp
Flat
Net-tone change vs last year's 10-K.
MD&A
-0.15pp
Flat
Net-tone change vs last year's 10-K.
Per-snippet highlights
Sentence-level sentiment highlighting with category and subcategory filters is coming once the snippet-scoring pipeline lands. For now, dig into the actual section text on the Sections tab.
Language change vs prior 10-K
Risk Factors (Item 1A) - words with the biggest YoY frequency increase
Negative rising
barriers+2
challenged+2
conflicts+1
Positive rising
successful+2
efficiencies+2
effective+1
improve+1
enhanced+1
Risk Factors (Item 1A)
10,043 words
ITEM 1A. Risk Factors
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.
Risks Related to our Financial Condition, Results of Operations and Cash Flows
Crude oil, NGLs and natural gas prices are volatile, and a substantial and extended decline in commodity prices can have a material and adverse effect on us.
Prices for crude oil and natural gas (including prices for natural gas liquids (NGLs) and condensate) fluctuate widely. Among the interrelated factors that can or could cause these price fluctuations are:
Language change vs prior 10-K
MD&A (Item 7) - words with the biggest YoY frequency increase
Negative rising
closed+10
losses+2
barriers+2
arrears+2
disruptions+1
Positive rising
efficiencies+3
successful+2
strong+1
improve+1
advantageous+1
MD&A (Item 7)
10,506 words
ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Overview
EOG Resources, Inc., together with its subsidiaries (collectively, EOG), is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States of America (United States) with proved reserves in the United States and the Republic of Trinidad and Tobago (Trinidad). EOG is focused on being among the highest return and lowest cost producers, committed to strong environmental performance and playing a significant role in the long-term future of energy. EOG operates under a consistent business and operational strategy that focuses on a comprehensive approach to developing acreage through industry cycles. EOG evaluates rate of return, net present value, margins, payback period and other key metrics. This strategy is intended to enhance the generation of cash flow and earnings from each unit of production on a cost-efficient basis, allowing EOG to maximize long-term growth in shareholder value and maintain a strong balance sheet. EOG implements its strategy primarily by emphasizing the drilling of internally generated prospects in order to find and develop low-cost reserves. Maintaining the lowest possible operating cost structure, coupled with and safe operations and robust environmental stewardship practices and performance, is integral in the implementation of EOG's strategy.
• domestic and worldwide supplies of, and consumer and industrial/commercial demand for, crude oil, NGLs and natural gas;
• domestic and international drilling activity;
• the actions of 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, tariffs; trade policies, trade agreements and trade restrictions; other economic sanctions or barriers; and political instability or armed conflicts in oil and gas producing regions;
• the availability, proximity and capacity of appropriate gathering, processing, compression, storage, transportation, refining, liquefaction and export facilities;
• the price and availability of, and demand for, competing energy sources, including alternative energy sources;
• the effect of worldwide energy conservation measures, alternative fuel requirements and climate change-related legislation, policies, initiatives and developments;
• technological advances and consumer and industrial/commercial behavior, preferences and attitudes, in each case affecting energy generation, transmission, storage and consumption;
• the nature and extent of governmental regulation, including environmental and other climate change-related regulation, regulation of financial and other derivative transactions and hedging activities, tax laws and regulations and laws and regulations with respect to the import and export of crude oil, NGLs, and natural gas and related commodities;
• the level and effect of trading in commodity futures markets, including trading by commodity price speculators and others;
• natural disasters, weather conditions and changes in weather patterns, each of which may be exacerbated by climate change; and
• the economic and financial impact of epidemics, pandemics or other public health issues.
The above-described factors and the volatility of commodity prices make it difficult to predict crude oil, NGLs and natural gas prices in 2026 and thereafter. As a result, there can be no assurance that the prices for crude oil, NGLs and/or natural gas will sustain, or increase from, their current levels, nor can there be any assurance that the prices for crude oil, NGLs and/or natural gas will not decline.
Our cash flows, financial condition and results of operations depend to a great extent on prevailing commodity prices. Accordingly, substantial and extended declines in commodity prices can materially and adversely affect the amount of cash flows we have available for our capital expenditures and operating costs; the terms on which we can access the credit and capital markets; our results of operations; and our financial condition, including (but not limited to) our ability to pay regular and special dividends on our common stock or repurchase shares of our common stock under the share repurchase authorization established by our Board of Directors (Board). As a result, the trading price of our common stock may be materially and adversely affected.
Lower commodity prices can also reduce the amount of crude oil, NGLs and natural gas that we can produce economically. Substantial and extended declines in the prices of these commodities can render uneconomic a portion of our exploration, development and exploitation projects, resulting in our having to make downward adjustments (“write-downs”) to our estimated reserves and also possibly shut in, or plug and abandon, certain wells. In addition, significant prolonged decreases in commodity prices may cause the expected future cash flows from our properties to fall below their respective net book values, which would require us to recognize an impairment expense in respect of the value of our properties. Such reserve write-downs and asset impairments can materially and adversely affect our results of operations and financial position and, in turn, the trading price of our common stock.
We have substantial capital requirements, and we may be unable to obtain needed financing on satisfactory terms, if at all.
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 fund 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 financing transactions.
Similarly, a reduction in our cash flows (for example, as a result of lower crude oil, NGLs and/or natural gas prices or unanticipated well shut-ins) and the corresponding adverse effect on our financial condition and results of operations may also increase the interest rates that lenders and commercial paper investors require us to pay. A substantial increase in interest rates would decrease our net cash flows available for reinvestment (and, as noted above, for the payment of regular and special dividends on our common stock and for the repurchase of shares of our common stock). Any of these factors could have a material and adverse effect on our business, financial condition and results of operations and, in turn, the trading price of our common stock.
Further, our ability to obtain financings, our borrowing costs and the terms of any financings are, in part, dependent on the credit ratings assigned to our debt by independent credit rating agencies. The interrelated factors that may impact our credit ratings include our debt levels; planned capital expenditures and sales of assets; near-term and long-term production growth opportunities; liquidity; asset quality; cost structure; product mix; and commodity pricing levels (including, but not limited to, the estimates and assumptions of credit rating agencies with respect to future commodity prices). We cannot provide any assurance that our current credit ratings will remain in effect for any given period of time or that our credit ratings will be raised in the future, nor can we provide any assurance that any of our credit ratings will not be lowered.
In addition, companies in the oil and gas sector may be exposed to 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 may, 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.
Our continued initiatives to increase operating efficiencies may not be successful in offsetting any future inflationary pressures on our operating costs and capital expenditures.
We have undertaken (and continue to undertake) initiatives to increase our drilling, completions and operating efficiencies and improve the performance of our wells. Such initiatives include (among others): (i) our downhole drilling motor program; (ii) enhanced techniques for completing our wells; (iii) drilling extended laterals; and (iv) our self-sourced sand program. In addition, from time to time (when available and advantageous), we enter into agreements with service providers to secure the costs and availability of certain drilling and completions services we utilize as part of our operations.
We plan to continue these initiatives and actions. However, such efforts may not be successful or may not be sufficient to offset the impacts of any future inflationary pressures (such as from tariffs, other trade barriers or other macroeconomic factors) on our operating costs and capital expenditures and, in turn, on our cash flows and results of operations. For additional discussion, see ITEM 7, Management's Discussion and Analysis of Financial Condition and Results of Operations – Overview – Recent Developments.
Reserve estimates depend on many interpretations and assumptions. Any significant inaccuracies in these interpretations and assumptions could cause the reported quantities of our reserves to be materially misstated.
Estimating quantities of crude oil, NGLs and natural gas reserves and the future net cash flows from such reserves is a complex, inexact process. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors, made by our management. Any significant inaccuracies in these interpretations or assumptions could cause the reported quantities of our reserves and future net cash flows from such reserves to be overstated or understated. Also, the data for a given reservoir may also change substantially over time as a result of numerous factors, including, but not limited to, additional development activity, evolving production history, crude oil and condensate, NGLs and natural gas prices, continual reassessment of the viability of production under varying economic conditions and improvements and other changes in geological, geophysical and engineering evaluation methods.
To prepare estimates of our economically recoverable crude oil, NGLs and natural gas reserves and future net cash flows from our reserves, we analyze many variable factors, such as historical production from the area compared with production rates from other producing areas. We also analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also involves economic assumptions relating to commodity prices, production costs, gathering, processing, compression, storage and transportation costs, severance, ad valorem and other applicable taxes, capital expenditures and workover and remedial costs. Many of these factors are or may be beyond our control. The quantities of reserves ultimately recovered and the future net cash flows from such reserves most likely will vary from our estimates. Any significant variance, including any significant downward revisions (“write-downs”) to our existing reserve estimates, could materially and adversely affect our business, financial condition and results of operations and, in turn, the trading price of our common stock. For related discussion, see ITEM 2, Properties - Oil and Gas Exploration and Production - Properties and Reserves and Supplemental Information to Consolidated Financial Statements.
If we fail to acquire or find sufficient additional reserves over time, our reserves and production will decline from their current levels.
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 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 and considerations, including:
• cash available for dividends or share repurchases;
• our results of operations and anticipated future results of operations;
• our financial condition, especially in relation to the anticipated future capital expenditures and other commitments requiring cash necessary to conduct our operations and carry out our business strategy;
• our operating costs;
• the levels of dividends paid by comparable companies; and
• other factors our Board deems relevant.
We expect to continue to pay dividends to our stockholders; however, our payment of dividends in the future is solely within the discretion of our Board. Accordingly, our Board may reduce our dividends or cease declaring dividends at any time, including if it determines that our current or forecasted future cash flows provided by our operating activities (after deducting our capital expenditures and other commitments requiring cash) are not sufficient to pay our desired levels of dividends to our stockholders or to pay dividends to our stockholders at all. Any reduction in the amount of dividends we pay to stockholders could have an adverse effect on the trading price of our common stock.
In November 2021, our Board established a share repurchase authorization allowing for the repurchase by us of up to $5 billion of our common stock, which was subsequently increased by the Board, from $5 billion to $10 billion, in November 2024 (Share Repurchase Authorization). Beginning in March 2023, we have repurchased shares from time to time under the Share Repurchase Authorization. The timing and amount of repurchases is at the discretion of our management and depends on a variety of factors, including the trading price of our common stock, corporate and regulatory requirements, other market and economic conditions, the availability of cash to effect repurchases and our anticipated future capital expenditures and other commitments requiring cash. For further discussion regarding the Share Repurchase Authorization and our share repurchases thereunder, see ITEM 5, “Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities” below.
Our hedging activities may prevent us from fully benefiting from increases in crude oil, NGLs and natural gas prices and may expose us to other risks, including counterparty risk, and our future production may not be sufficiently protected from any declines in commodity prices by our existing or future hedging arrangements.
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 2026 is subject to fluctuating market prices. To the extent we do not hedge our production volumes for 2026 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 financial derivative instruments fail to perform under the contracts.
The inability of our customers and other contractual counterparties to satisfy their obligations to us may have a material and adverse effect on us.
We have various customers for the crude oil, natural gas and related commodities that we produce as well as various other contractual counterparties, including 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.
Moreover, our customers and other contractual counterparties may be unable to satisfy their contractual obligations to us for reasons unrelated to these conditions and factors, such as (i) the unavailability of required facilities or equipment due to mechanical failure or market conditions or (ii) financial, operational or strategic actions taken by the customer or counterparty that adversely impact its financial condition, results of operations and cash flows and, in turn, its ability to satisfy its contractual obligations to us. Furthermore, if a customer is unable to satisfy its contractual obligation to purchase crude oil, natural gas or related commodities from us, we may be unable to sell such production to another customer on terms we consider acceptable, if at all, due to the geographic location of such production; the availability, proximity and capacity of appropriate gathering, processing, compression, storage, transportation, export, liquefaction and refining facilities; or market or other factors and conditions.
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.
Risks Related to our Operations
Drilling crude oil and natural gas wells is a high-risk activity and subjects us to a variety of risks that we cannot control.
Drilling crude oil and natural gas wells involves numerous risks, including the risk that we may not encounter commercially productive crude oil, NGLs and/or natural gas reserves. As a result, we may not recover all or any portion of our investment in new wells.
Specifically, we often are uncertain as to the future cost or timing of drilling, completing and operating wells, and our drilling and completions operations and those of our third-party operators may be curtailed, delayed or canceled, the cost of such operations may increase and/or our results of operations and cash flows from such operations may be impacted, as a result of a variety of factors, including:
• unexpected drilling conditions;
• leasehold title problems;
• pressure or irregularities in formations;
• equipment failures or accidents;
• adverse weather events, such as winter storms, flooding, wildfires, tropical storms and hurricanes, and other natural disasters, which may be exacerbated by climate change;
• compliance with, or changes in (including the adoption of new), environmental, health and safety laws and regulations relating to air emissions, hydraulic fracturing, access to and use of water, disposal or other discharge (e.g., into injection wells) of produced water, drilling fluids and other wastes, laws and regulations imposing conditions or restrictions on drilling and completion operations and on the transportation of crude oil, NGLs and natural gas, and other laws and regulations, such as tax laws and regulations;
• the availability and timely issuance of required federal, state, tribal and other permits and licenses, which may be adversely affected by (among other things) bans or restrictions on drilling, government shutdowns or other suspensions of, or delays in, government services;
• the availability of, costs associated with, and terms of contractual arrangements for properties, including mineral licenses and leases, pipelines, crude oil hauling trucks and qualified drivers and facilities and equipment to gather, process, compress, store, transport, market and export crude oil, NGLs and natural gas and related commodities; and
• the costs of, or shortages or delays in the availability of, drilling rigs, hydraulic fracturing services, pressure pumping equipment and supplies, tubular materials, water, sand, disposal facilities, qualified personnel and other necessary facilities, equipment, materials, supplies and services.
Our failure to recover our investment in wells, increases in the costs of our drilling and completions operations or those of our third-party operators, and/or curtailments, delays or cancellations of our drilling and completions operations or those of our third-party operators, in each case, due to any of the above factors or other factors, may materially and adversely affect our business, financial condition and results of operations. For related discussion of the risks and potential losses and liabilities inherent in our crude oil and natural gas operations generally, see the immediately following risk factor.
Our crude oil, NGLs and natural gas operations and supporting activities and operations involve many risks and expose us to potential losses and liabilities, and insurance may not fully protect us against these risks and potential losses and liabilities.
Our crude oil, NGLs and natural gas operations and supporting activities and operations are subject to all of the risks associated with exploring and drilling for, and producing, gathering, processing, compressing, storing, transporting and exporting crude oil, NGLs and natural gas, including the risks of:
• well blowouts and cratering;
• loss of well control;
• crude oil spills, natural gas leaks, formation water (i.e., produced water) spills and pipeline ruptures;
• pipe failures and casing collapses;
• uncontrollable flows of crude oil, natural gas, formation water or drilling fluids;
• releases of chemicals, wastes or pollutants;
• adverse weather events, such as winter storms, flooding, wildfires, tropical storms and hurricanes, and other natural disasters, which may be exacerbated by climate change;
• fires and explosions;
• terrorism, vandalism and physical, electronic and cyber breaches and related threats;
• formations with abnormal or unexpected pressures;
• leaks or spills in connection with, or associated with, the gathering, processing, compression, storage, transportation and export of crude oil, NGLs and natural gas; and
• malfunctions of, or damage to, gathering, processing, compression, storage, transportation and export facilities and equipment and other facilities and equipment utilized in support of our crude oil and natural gas operations.
If any of these events occur, we could incur losses, liabilities and other costs as a result of:
• injury or loss of life;
• damage to, or destruction of, property, facilities, equipment and crude oil and natural gas reservoirs;
• pollution or other environmental damage;
• regulatory investigations, penalties and injunctions as well as cleanup and remediation responsibilities and costs;
• the lack of availability of, or access to, necessary third-party services and facilities, such as gathering, processing, compression, storage, transportation and export services and facilities;
• loss of production due to temporary cessation of our operations (for example, to conduct repairs necessary to resume operations) or damage to necessary facilities and equipment; and
• compliance with laws and regulations enacted as a result of such events.
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. Further, in the future, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates or at all. As a result of market conditions, premiums, retentions and deductibles for our insurance policies will change over time and could increase. In addition, some forms of insurance may become unavailable or unavailable on economically acceptable terms.
Our ability to sell and deliver our crude oil, NGLs and natural gas production could be materially and adversely affected if adequate gathering, processing, compression, storage, transportation, refining, liquefaction and export facilities and equipment are unavailable.
The sale of our crude oil, NGLs and natural gas production depends on a number of factors beyond our control, including the availability, proximity and capacity of, and costs associated with, gathering, processing, compression, storage, transportation, refining, liquefaction and export facilities and equipment owned by third parties. These facilities and equipment may be temporarily unavailable to us due to market conditions, supply chain disruptions, regulatory reasons, mechanical reasons or other factors or conditions, and may not be available to us in the future on terms we consider acceptable, if at all. In particular, in certain newer plays, the capacity of gathering, processing, compression, storage, transportation, refining, liquefaction and export facilities and equipment may not be sufficient to accommodate potential production from existing and new wells. In addition, lack of financing, construction and permitting delays, permitting costs and regulatory or other constraints could limit or delay the construction, manufacture or other acquisition of new gathering, processing, compression, storage, transportation, refining, liquefaction and export facilities and equipment by third parties or us, and we may experience delays or increased costs in accessing the pipelines, gathering systems or transportation systems necessary to transport our production to points of sale or delivery.
Any significant change in market or other conditions affecting gathering, processing, compression, storage, transportation, refining, liquefaction and export facilities and equipment or the availability of these facilities and equipment, including due to our failure or inability to obtain access to these facilities and equipment on terms acceptable to us or at all, could materially and adversely affect our business and, in turn, our financial condition and results of operations.
A portion of our crude oil, NGLs and natural gas production may be subject to interruptions that could have a material and adverse effect on us.
A portion of our crude oil, NGLs and natural gas production may be interrupted, or shut in, from time to time for various reasons, including, but not limited to, as a result of accidents, weather conditions or natural disasters, the unavailability of gathering, processing, compression, storage, transportation, refining, liquefaction or export facilities or equipment or field labor issues, or intentionally as a result of market conditions such as crude oil, NGLs or natural gas prices that we deem uneconomic. If a substantial amount of our production is interrupted or shut in, our cash flows and, in turn, our financial condition and results of operations could be materially and adversely affected.
Our operations are substantially dependent upon the availability of water. Restrictions or limitations on our ability to obtain water may have a material and adverse effect on our financial condition, results of operations and cash flows.
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, severedrought 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 or 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 acquire crude oil and natural gas properties. Although we perform reviews of properties to be acquired in a manner that we believe are 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 or achieve anticipated synergies.
Competition in the oil and gas exploration and production industry is intense, and some of our competitors have greater resources than we have.
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.
Risks Related to Sustainability, Regulatory and Legal Matters
Developments and concerns related to climate change may have a material and adverse effect on us.
Governmental and regulatory bodies, investors, consumers, industry and other stakeholders have been 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 these rules have been stayed in abeyance by the U.S. Court of Appeals for the Eighth Circuit until such time as the SEC reconsiders the challenged rules by notice-and-comment rulemaking or renews its defense of the rules), (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.
In addition to potentially adversely affecting the demand for, and prices of, the crude oil, NGLs and natural gas that we produce and sell, such developments may also adversely impact, among other things, the availability to us of necessary third-party services and facilities that we rely on, which may increase our operational costs and adversely affect our ability to explore for, produce, transport and process crude oil, NGLs and natural gas and successfully carry out our business strategy. For further discussion of the potential impact of such availability-related risks on our financial condition and results of operations, see the discussion in the section above entitled "Risks Related to our Operations."
Further, climate change-related developments (such as the climate-related disclosure mandates 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."
In addition, the enactment of climate change-related regulations, policies and initiatives (at the government, corporate and/or investor community levels) may also result in increases in our compliance costs and other operating costs. For further discussion regarding the risks to us of climate change-related regulations, policies and initiatives, see the discussion in this section. Also, continuing political and social concerns relating to climate change may have adverse effects on our business and operations, such as a greater potential for shareholder activism, governmental inquiries and enforcement actions and litigation (including, but not limited to, litigation brought by governmental entities and shareholder litigation) and resulting expenses and potential disruption to our day-to-day operations.
Regulatory, legislative and policy changes may materially and adversely affect the oil and gas exploration and production industry.
New or revised rules, regulations and policies may be issued, and new legislation may be 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, 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 completions 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.
For related discussion, see the below risk factors regarding legislative and regulatory matters impacting the oil and gas exploration and production industry and the discussion in ITEM 1, Business - Regulation.
We incur certain costs to comply with government regulations, particularly regulations relating to environmental protection and safety, and could incur even greater costs in the future.
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 condition, cash flows and capital expenditures.
Specifically, as a current or past owner or lessee and operator of crude oil and natural gas properties, we are subject to various federal, state, tribal, local and foreign regulations relating to the discharge of materials into, and the protection of, the environment. These regulations may, among other things, impose liability on us for the cost of pollution cleanup resulting from current or past operations, subject us to liability for pollution damages and require suspension or cessation of operations in affected areas. Changes in, or additions to, these regulations, could lead to increased operating and compliance costs and, in turn, materially and adversely affect our business, results of operations, financial condition 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 completions operations. The U.S. Environmental Protection Agency (U.S. EPA) has, however, issued certain regulations relating to hydraulic fracturing and there have been various other proposals to regulate hydraulic fracturing at the federal level.
Any new requirements, restrictions, conditions or prohibitions could lead to operational delays and increased operating and compliance costs and, further, could delay or effectively prevent the development of crude oil and natural gas from formations which would not be economically viable without the use of hydraulic fracturing. Accordingly, our production of crude oil and natural gas could be materially and adversely affected. For additional discussion regarding hydraulic fracturing regulation, see Regulation of Hydraulic Fracturing and Other Operations - United States under ITEM 1, Business - Regulation.
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.
Regulations, government policies and government and corporate initiatives relating to greenhouse gas emissions and climate change could have a significant impact on our operations and we could incur significant cost in the future to comply.
Local, state, federal and international regulatory bodies have been focused on GHG emissions and climate change issues in recent years. For discussion of the rules and regulations adopted by the U.S. EPA and the Bureau of Land Management with respect to GHG emissions and related matters and the related actions taken by the U.S. Congress, see ITEM 1, Business – Regulation – Climate Change – United States.
At the international level, the Paris Agreement calls for nations to undertake efforts with respect to global temperatures and GHG emissions and the UAE Consensus calls on parties, including the U.S., to contribute to the transitioning away from fossil fuels, reduce methane emissions, and increase renewable energy capacity, among other things, to achieve net zero emissions by 2050. The U.S. withdrew from the Paris Agreement effective January 27, 2026 and, on January 7, 2026, it was announced that the U.S. will also withdraw from the United Nations Framework Convention on Climate Change. For further discussion regarding the Paris Agreement, the UAE Consensus and related matters, see ITEM 1, Business – Regulation – Climate Change – United States. State and local officials may, however, continue efforts to uphold the commitments set forth in the international accord.
It is possible that the Paris Agreement, the related UAE Consensus, and subsequent domestic and international regulations and government policies related to climate change and GHG emissions will have adverse effects on the market for crude oil, NGLs and natural gas as well as adverse effects on the business and operations of companies engaged in the exploration for, and production of, crude oil, NGLs and natural gas.
We are unable to predict the timing, scope and effect of any currently proposed or future investigations, laws, regulations, treaties or policies regarding climate change and GHG emissions (including any laws and regulations that may be enacted in the U.S.), but the direct and indirect costs of such developments (if enacted, issued or applied) could materially and adversely affect our operations, financial condition, results of operations and capital expenditures. The potential increase in the costs of our operations could include costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions, pay taxes or fees related to our GHG emissions, or administer and manage a GHG emissions program. In addition, changes in regulatory policies that result in a reduction in the demand for hydrocarbon products that are deemed to contribute to GHG emissions, or restrictions on their use, could also adversely affect market demand for, and in turn the prices we receive for our production of, crude oil, NGLs and natural gas. For additional discussion regarding the regulation of GHG emissions and climate change generally, see ITEM 1, Business – Regulation.
Our initiatives, targets and ambitions related to emissions and other environmental or safety-related matters, including our related public statements and disclosures, are subject to various factors, contingencies and uncertainties and may expose us to certain risks.
We have developed, and will continue to develop, targets and ambitions related to our environmental and safety initiatives, including, but not limited to, our current emissions 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.
As 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 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. 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, 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 and/or setting new 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, from time to time there has been particular investor and regulatory focus on environmental and social matters, including, in addition to climate change, human rights and human capital management 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 reputation, relationships with investors 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 these rules have been stayed in abeyance by the U.S. Court of Appeals for the Eighth Circuit until such time as the SEC reconsiders the challenged rules by notice-and-comment rulemaking or renews its defense of the rules). To the extent the rules are implemented, we could incur increased costs related to the assessment and disclosure of climate-related information.
Tax laws and regulations, including those applicable specifically to crude oil and natural gas exploration and production companies, may change over time, and such changes could materially and adversely affect our business, cash flows, results of operations and financial condition.
From time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws, including laws specifically applicable to crude oil and natural gas exploration and production companies - such as eliminating the immediate deduction for intangible drilling and development costs. No accurate prediction can be made as to whether any such legislative changes or similar or other tax law changes will be proposed or enacted. Further, no accurate prediction can be made as to what the specific provisions or impact on EOG of any such enacted legislation would be.
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 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.
The elimination or postponement of certain U.S. federal income tax deductions currently available to crude oil and natural gas exploration and production companies, as well as any other changes to, or the imposition of new, U.S. federal, state, local or non-U.S. (i.e., foreign) taxes (including the imposition of, or increases in, production, severance or similar taxes or the enactment of a GMT or similar tax), could materially and adversely affect our business, cash flows, results of operations and financial condition.
In addition, legislation may be proposed with respect to the enactment of a tax levied on the carbon content of fuels based on the GHG emissions associated with such fuels. A carbon tax, whether imposed on producers or consumers, would generally increase the prices for crude oil, NGLs and natural gas. Such price increases may, in turn, reduce demand for crude oil, NGLs and natural gas and materially and adversely affect our cash flows, results of operations and financial condition.
We are unable to predict the timing, scope and effect of any proposed or enacted tax law changes, but any such changes (if enacted) may materially and adversely affect our business. We will continue to monitor and assess any proposed or enacted tax law changes to determine the impact on our business, cash flows, results of operations and financial condition and take appropriate actions, where necessary.
Risks Related to Our International Operations
We operate in other countries and, as a result, are subject to certain political, economic, competitive and other risks.
Our operations in jurisdictions outside the U.S. are subject to various risks inherent in foreign operations. These risks include, among other risks:
• increases in taxes and governmental royalties;
• additional and potentially unfamiliar laws and policies governing the operations of foreign-based companies and changes in such laws and policies;
• loss of revenue, loss of or damage to equipment, property and other assets and interruption of operations as a result of expropriation, nationalization, acts of terrorism, war, civil unrest and other political risks;
• unilateral or forcedrenegotiation, modification or nullification of existing contracts with governmental entities;
• difficulties enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations;
• competition from companies that have established strategic long-term positions or have strong governmental relationships in the foreign jurisdictions in which we operate; and
• currency restrictions and exchange rate fluctuations.
Our international operations may also be adversely affected by U.S. laws and policies affecting foreign trade and taxation, including tariffs and 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.
Risks Related to Cybersecurity and Other External Factors
Our business could be materially and adversely affected by security threats, including cyber threats and cyber attacks, and other disruptions.
As an oil and gas producer, we face various security threats, including (i) cyber threats to gainunauthorized access to, or control of, our sensitive information or to render our data or systems corrupted or unusable; (ii) threats to the security of our facilities and infrastructure or to the security of third-party facilities and infrastructure, such as gathering, transportation, processing, fractionation, refining, liquefaction and export facilities; and (iii) threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material and adverse effect on our business.
We rely extensively on information technology systems, including internally developed software, data hosting platforms, real-time data acquisition systems, third-party software, cloud services and other internally or externally hosted hardware and software platforms, to (i) estimate our oil and 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, gathering and processing, transportation, pipelines and other related activities and (iv) communicate with, and make payments to, our employees and vendors, suppliers and other third parties. Further, our reliance on technology has increased due to the increased use of personal devices and remote communications. Although 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 cyber threats, such measures cannot entirely eliminate cyber threats and the controls, procedures and protections we have implemented and invested in may prove to be ineffective.
Our systems and networks, and those of our business associates, may become the target of cyber attacks, including, without limitation, denial-of-service attacks; malicious software; data privacy breaches by employees, insiders or others with authorized access; phishing attacks; ransomware; attempts to gainunauthorized access to our data and systems; and other electronic security breaches. Security incidents can also occur as a result of non-technical issues, such as physical theft. More recently, advancements in artificial intelligence (AI) may 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 may also be used by malicious actors to create more sophisticated cyber attacks (i.e., more realistic phishing or other attacks). The advancements in AI could also lead to an increase in the frequency of identity fraud or cyber attacks (whether successful or unsuccessful), which could cause us to incur increasing costs, including costs to deploy additional personnel, protection technologies and policies and procedures, train employees, and engage third-party experts and consultants.
If any of these security breaches were to occur, we could sufferdisruptions to our normal operations, including our drilling, completion, production and corporate functions, which could materially and adversely affect us in a variety of ways, including, but not limited to, the following:
• unauthorized access to, and release of, our business data, reserves information, strategic information or other sensitive or proprietary information, which could have a material and adverse effect on our ability to compete for oil and gas resources, or reduce our competitive advantage over other companies;
• data corruption, communication interruption, or other operational disruptions during our drilling activities, which could result in our failure to reach the intended target or a drilling incident;
• data corruption or operational disruptions of our production-related infrastructure, which could result in loss of production or accidental discharges;
• unauthorized access to, and release of, personal information of our royalty owners, employees and vendors, which could expose us to allegations that we did not sufficiently protect such information;
• a cyber attack on a vendor or service provider, which could result in supply chain disruptions and could delay or halt our operations;
• a cyber attack on third-party gathering, transportation, processing, fractionation, refining, liquefaction or export facilities, which could 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 cyber 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 deliberatecorruption of our financial or operating data could result in events of non-compliance which could then lead to regulatory fines or penalties;
• a cyber attack on a communications network or power grid, which could cause operational disruptions resulting in a loss of revenues; and
• a cyber attack on our automated and surveillance systems, which could cause a loss of production and potential environmental hazards.
Further, strategic targets, such as energy-related assets, may be at a greater risk of terrorist attacks or cyber attacks than other targets in the United States. Moreover, external digital technologies control nearly all of the crude oil and natural gas distribution systems in the U.S. and abroad, which are necessary to transport and market our production. A cyber attack directed at, for example, crude oil, NGLs and natural gas distribution systems could (i) damagecritical distribution and storage assets or the environment; (ii) disrupt energy supplies and markets, by delaying or preventing delivery of production to markets; and (iii) make it difficult or impossible to accurately account for production and settle transactions.
Any such terrorist attack or cyber attack that affects us, our customers, suppliers, or others with whom we do business and/or energy-related assets could have a material adverse effect on our business, including disruption of our operations, damage to our reputation, a loss of counterparty trust, reimbursement or other costs, increased compliance costs, significant litigation exposure and legal liability or regulatory fines, penalties or intervention. Although we have business continuity plans in place, our operations may be adversely affected by significant and widespread disruption to our systems and the infrastructure that supports our business. While we continue to evolve and modify our business continuity plans as well as our cyber threat detection and mitigation systems, there can be no assurance that they will be effective in avoiding disruption and business impacts. Further, our insurance may not be adequate to compensate us for all resulting losses, and the cost to obtain adequate coverage may increase for us in the future and some insurance coverage may become more difficult to obtain, if available at all.
While we have experienced limited cyber incidents in the past, we have not had, to date, any business interruptions or material losses from breaches of our information technology systems and related infrastructure. However, there is no assurance that we will not suffer any such interruptions or losses in the future. Further, as technologies evolve and cyber threats become more sophisticated, we are continually expending additional resources to modify or enhance our security measures to protect against such threats and to identify and remediate on a regular basis any vulnerabilities in our information systems and related infrastructure that may be detected, and these expenditures in the future may be significant. Additionally, the continuing and evolving threat of cyber attacks has resulted in evolving legal and compliance matters, including increased regulatory focus on prevention and new disclosure requirements recently enacted by the SEC with respect to material cyber incidents and cyber risk management, strategy and governance, which could require us to expend significant additional resources to meet such requirements.
Terrorist activities and military and other actions could materially and adversely affect us.
Terrorist attacks and the threat of terrorist attacks (including cyber-related attacks), whether domestic or foreign, as well as military or other actions taken in response to these acts, could cause instability in the global financial and energy markets. The U.S. government has from time to time issued public warnings that indicate that energy-related assets, such as transportation and refining facilities, might be specific targets of terrorist organizations.
Any such actions and the threat of such actions, including any resulting political instability or societal disruption, could materially and adversely affect us in unpredictable ways, including, but not limited to, the disruption of energy supplies and markets, the reduction of overall demand for crude oil, NGLs and natural gas, increased volatility in crude oil, NGLs and natural gas prices or the possibility that the facilities and other infrastructure on which we rely could be a direct target or an indirect casualty of an act of terrorism, and, in turn, could materially and adversely affect our business, financial condition and results of operations.
efficient
EOG realized net income of $4,980 million for 2025 as compared to net income of $6,403 million for 2024. At December 31, 2025, EOG's total estimated net proved reserves were 5,514 million barrels of oil equivalent (MMBoe), an increase of 766 MMBoe from December 31, 2024. During 2025, net proved crude oil and condensate and natural gas liquids (NGLs) reserves increased by 187 million barrels (MMBbl), and net proved natural gas reserves increased by 3,470 billion cubic feet, or 579 MMBoe, in each case from December 31, 2024.
Recent Developments
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, the global supply of, and demand for, crude oil, 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.
The market prices of crude oil and condensate, NGLs and natural gas impact the amount of cash generated from EOG's operating activities, which, in turn, impact EOG's financial position and results of operations.
For the year ended December 31, 2025, the average U.S. New York Mercantile Exchange (NYMEX) crude oil and natural gas prices were $64.78 per barrel and $3.43 per million British thermal units (MMBtu), respectively, representing a decrease of 14% and an increase of 51%, respectively, from the average NYMEX prices for the year ended December 31, 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, completions and operating efficiencies and improve the performance of its 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 have 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 operational efficiencies 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 completions 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 be successful and sufficient to offset the impacts of any future inflationary pressures (such as from tariffs, 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 any such pressures or factors 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.
Operations
Several important developments have occurred since January 1, 2025.
United States. EOG's efforts to identify plays with large reserve potential have proven to be successful. EOG continues to drill numerous wells in large acreage plays, which in the aggregate have contributed substantially to, and are expected to continue to contribute substantially to, EOG's crude oil and condensate, NGLs and natural gas production. EOG has placed an emphasis on applying its horizontal drilling and completion expertise to unconventional crude oil and natural gas plays.
In 2025, 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 68% and 72% of EOG's United States production during 2025 and 2024, respectively. During 2025, EOG's drilling and completion activities occurred primarily in the Delaware Basin play, Eagle Ford play and Utica play. EOG's major producing areas in the United States are in New Mexico, Texas and Ohio. See ITEM 1, Business - Exploration and Production for further discussion regarding EOG's 2025 United States operations.
On July 4, 2025, the One Big Beautiful Bill Act was signed into law, which primarily made permanent (generally with amendments) certain tax provisions of the 2017 Tax Cuts and Jobs Act. Included, among others, were changes to business tax provisions such as permanently restoring 100% bonus depreciation and full domestic research expensing. While the legislation reduced EOG's 2025 cash tax payments, it did not have a material impact on EOG's earnings.
On August 1, 2025, EOG completed its acquisition of Encino Acquisition Partners, LLC (Encino) for $5.7 billion, inclusive of Encino's net debt. The assets of Encino include 675,000 core net acres in the Utica play. The financial results of Encino have been included in EOG's consolidated financial statements beginning August 1, 2025. This acquisition impacted revenues and operating and other expenses as described in the Results of Operations section below. Additionally, see Note 16 to the Consolidated Financial Statements for further discussion of the acquisition.
In January 2026, EOG signed a purchase and sale agreement for the sale of its entire interest and related fixed assets in the northern Midland Basin for $165 million, subject to customary closing adjustments. The transaction closed on February 18, 2026. Crude oil production attributable to EOG's interest was approximately 4 MBbld for the quarter ended December 31, 2025.
Trinidad. In Trinidad, EOG continues to produce natural gas which is sold to the National Gas Company of Trinidad and Tobago Limited and its subsidiary under existing supply contracts. Crude oil and condensate are sold to both Heritage Petroleum Company Limited and BP Trinidad and Tobago LLC. In January 2025, EOG executed two production sharing contracts with the Government of Trinidad and Tobago for the Lower Reverse L and North Coast Marine Area 4(a) Blocks.
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 prospect in the Kingdom of Bahrain. In August 2025, the government of the Kingdom of Bahrain approved the 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 be completed in 2026.
In May 2025, a subsidiary of EOG was awarded a new oil exploration concession for Unconventional Onshore Block 3 (UCO3) by Abu Dhabi's Supreme Council for Financial and Economic Affairs. EOG holds a 100 percent equity interest and operatorship and, in coordination with Abu Dhabi National Oil Company (ADNOC), has commenced drilling operations to explore and appraise unconventional oil potential in the concession area. Following a three-year appraisal period, EOG may enter into a production concession in which ADNOC has the option to participate.
EOG continues to evaluate other select crude oil and natural gas opportunities outside the United States, primarily by pursuing exploration opportunities in countries where crude oil and natural gas reserves have been identified.
Capital Structure
One of management's key strategies is to maintain a strong balance sheet with a consistently below average debt-to-total capitalization ratio as compared to those in EOG's peer group. EOG's debt-to-total capitalization ratio was 21% at December 31, 2025 and 14% at December 31, 2024. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.
At December 31, 2025, EOG maintained a strong financial and liquidity position, including $3.4 billion of cash and cash equivalents on hand and $3.0 billion of availability under its senior unsecured revolving credit facility (discussed below).
The Internal Revenue Service previously announced tax relief related to 2024 severe weather events occurring in various Texas counties, including Harris County, where EOG's corporate offices are located. The tax relief permitted eligible taxpayers to postpone certain tax filings and payments. In February 2025, EOG paid approximately $700 million of such federal tax payments related to the 2024 tax year.
On April 1, 2025, EOG repaid upon maturity the $500 million aggregate principal amount of its 3.15% Senior Notes due 2025.
On July 1, 2025, EOG closed on its offering of $500 million aggregate principal amount of its 4.400% Senior Notes due 2028, $1.25 billion aggregate principal amount of its 5.000% Senior Notes due 2032, $1.25 billion aggregate principal amount of its 5.350% Senior Notes due 2036 and $500 million aggregate principal amount of its 5.950% Senior Notes due 2055 (collectively, the July Notes). Interest on the July Notes is payable semi-annually in arrears on January 15 and July 15 of each year, beginning on January 15, 2026. EOG received net proceeds of $3.47 billion from the issuance of the July Notes, which were used for general corporate purposes, including the payment of a portion of the consideration for the acquisition of Encino and related fees, costs and expenses.
On November 24, 2025, EOG closed on its offering of $750 million aggregate principal amount of its 4.400% Senior Notes due 2031 and $250 million aggregate principal amount of its 5.950% Senior Notes due 2055 (collectively, the November Notes). Interest on the November Notes is payable semi-annually in arrears on January 15 and July 15 of each year, beginning on January 15, 2026. EOG received net proceeds of $996 million from the issuance of the November Notes, which were used for general corporate purposes, including the repayment of the $750 million aggregate principal amount of its 4.15% Senior Notes due 2026 discussed below.
On December 3, 2025, EOG entered into a new $3.0 billion senior unsecured Revolving Credit Agreement (New Facility) with domestic and foreign lenders, which has a scheduled maturity date of December 3, 2030. The New Facility replaced EOG's $1.9 billion senior unsecured Revolving Credit Agreement, dated as of June 7, 2023, with domestic and foreign lenders, which had a scheduled maturity date of June 7, 2028 and which was terminated by EOG (without penalty), effective as of December 3, 2025, in connection with the completion of the New Facility.
On December 24, 2025, EOG redeemed the $750 million aggregate principal amount of its 4.15% Senior Notes prior to their maturity in January 2026.
During 2025, EOG funded $13.6 billion in exploration and development and other property, plant and equipment expenditures (excluding asset retirement obligations), paid $2.2 billion in dividends to common stockholders and paid $2.6 billion to repurchase shares of common stock, primarily by utilizing net cash provided by its operating activities, issuances of senior notes and cash on hand.
Total anticipated 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. The majority of 2026 expenditures will be focused on United States crude oil drilling activities. EOG has significant flexibility with respect to financing alternatives, including borrowings under its commercial paper program, bank borrowings, borrowings under its senior unsecured revolving credit facility, joint development agreements and similar agreements and equity and debt offerings.
Management believes that 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 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 regular 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.
Dividend Declarations. On February 27, 2025, the Board of Directors (Board) declared a quarterly cash dividend on the common stock of $0.975 per share paid on April 30, 2025, to stockholders of record as of April 16, 2025.
On May 1, 2025, the Board declared a quarterly cash dividend on the common stock of $0.975 per share paid on July 31, 2025, to stockholders of record as of July 17, 2025.
On May 30, 2025, the Board declared a quarterly cash dividend on the common stock of $1.02 per share paid on October 31, 2025, to stockholders of record as of October 17, 2025. This represented an increase from the previous quarterly cash dividend which was $0.975 per share.
On November 6, 2025, the Board declared a quarterly cash dividend on the common stock of $1.02 per share paid on January 30, 2026, to stockholders of record as of January 16, 2026.
On February 24, 2026, the Board declared a quarterly cash dividend on the common stock of $1.02 per share to be paid on April 30, 2026, to stockholders of record as of April 16, 2026.
Results of Operations
This section discusses certain year-to-year comparisons between 2025 and 2024, which should be read in conjunction with the consolidated financial statements of EOG and notes thereto beginning on page F-1. For discussion of certain year-to-year comparisons between 2024 and 2023, see "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II, ITEM 7 of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2024, filed on February 27, 2025, which is incorporated herein by reference.
Operating Revenues and Other
During 2025, total operating revenues decreased $1,066 million, or 4%, to $22,632 million from $23,698 million in 2024. Total revenues from sales of EOG's production of crude oil and condensate, NGLs and natural gas, increased $90 million, or 1%, to $17,668 million in 2025 from $17,578 million in 2024. Revenues from the sales of crude oil and condensate and NGLs in 2025 were 84% of total revenues from sales of crude oil and condensate, NGLs and natural gas compared to 91% in 2024. During 2025, EOG recognized net gains on the mark-to-market of financial commodity and other derivative contracts of $13 million compared to net gains of $204 million in 2024. Gathering, processing and marketing revenues decreased $886 million during 2025, to $4,914 million from $5,800 million in 2024. EOG recognized net losses on asset dispositions of $35 million in 2025 compared to net gains on asset dispositions of $16 million in 2024.
Volume and price statistics for the years ended December 31, 2025, 2024 and 2023 were as follows (see Note 11 for segment financial information):
Year Ended December 31
Crude Oil and Condensate Volumes (MBbld) (1)
United States
Trinidad
Total
Average Crude Oil and Condensate Prices ($/Bbl) (2)
United States
Trinidad
Composite
Natural Gas Liquids Volumes (MBbld) (1)
United States
Total
Average Natural Gas Liquids Prices ($/Bbl) (2)
United States
Composite
Natural Gas Volumes (MMcfd) (1)
United States
Trinidad
Other International (3)
Total
Average Natural Gas Prices ($/Mcf) (2)
United States
Trinidad
Other International (3)
Composite
Crude Oil Equivalent Volumes (MBoed) (4)
United States
Trinidad
Other International (3)
Total
Total MMBoe (4)
(1) Thousand barrels per day or million cubic feet per day, as applicable.
(2) Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity and other derivative instruments (see Note 12 to Consolidated Financial Statements).
(3) Production volumes from Bahrain operations; realized price represents contract price less Bapco's processing and distribution costs.
(4) Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand.
Crude oil and condensate revenues in 2025 decreased $1,420 million, or 10%, to $12,501 million from $13,921 million in 2024, primarily due to a lower composite average crude oil and condensate price ($2,239 million), partially offset by an increase in production ($819 million). EOG's composite crude oil and condensate price for 2025 decreased 15% to $65.63 per barrel compared to $77.40 per barrel in 2024. Crude oil and condensate production in 2025 increased 6% to 522 MBbld as compared to 491 MBbld in 2024. The increased production was primarily in the Utica and the Permian Basin.
NGLs revenues in 2025 increased $270 million, or 13%, to $2,376 million from $2,106 million in 2024 primarily due to an increase in production ($356 million), partially offset by a lower composite average NGLs price ($86 million). EOG's composite average NGLs price decreased 4% to $22.58 per barrel in 2025 compared to $23.40 per barrel in 2024. NGLs production in 2025 increased 17% to 288 MBbld as compared to 246 MBbld in 2024. The increased production was primarily in the Utica and the Permian Basin.
Natural gas revenues in 2025 increased $1,240 million, or 80%, to $2,791 million from $1,551 million in 2024 primarily due to a higher composite natural gas price ($783 million) and an increase in natural gas deliveries ($457 million). EOG's composite average natural gas price increased 39% to $3.02 per Mcf in 2025 compared to $2.17 per Mcf in 2024. Natural gas deliveries in 2025 increased 30% to 2,533 MMcfd as compared to 1,948 MMcfd in 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 the Utica and Dorado.
During 2025, EOG recognized net gains on the mark-to-market of financial commodity and other derivative contracts of $13 million, which included net cash paid for settlements of NGLs and natural gas financial commodity derivative contracts of $56 million and losses of $79 million related to the Brent crude oil (Brent) linked gas sales contract. During 2024, EOG recognized net gains on the mark-to-market of financial commodity and other derivative contracts of $204 million, which included net cash received from settlements of natural gas financial commodity derivative contracts of $214 million and gains of $110 million related to the Brent linked gas sales contract.
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. 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 2025 increased $36 million compared to 2024, primarily due to higher margins on natural gas marketing activities and sand sales, partially offset by lower margins on crude oil marketing activities.
Operating and Other Expenses
During 2025, operating expenses of $16,247 million were $631 million higher than the $15,616 million incurred during 2024. The following table presents the costs per barrel of oil equivalent (Boe) for the years ended December 31, 2025 and 2024:
Lease and Well
Gathering, Processing and Transportation Costs (GP&T)
Depreciation, Depletion and Amortization (DD&A) -
Oil and Gas Properties
Other Property, Plant and Equipment
General and Administrative (G&A)
Interest Expense, Net
Total (1)
(1) Total excludes exploration costs, dry hole costs, impairments, marketing costs and taxes other than income.
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 2025 compared to 2024 are set forth below. See "Operating Revenues and Other" above for a discussion of volumes.
Lease and well expenses include expenses for EOG-operated properties, as well as expenses billed to EOG from other operators where EOG is not the operator of a property. Lease and well expenses can be divided into the following categories: costs to operate and maintain crude oil and natural gas wells, the cost of workovers and lease and well administrative expenses. Operating and maintenance costs include, among other things, pumping services, produced water disposal, equipment repair and maintenance, compression expense, lease upkeep and fuel and power. Workovers are operations to restore or maintain production from existing wells.
Each of these categories of costs individually fluctuates from time to time as EOG attempts to maintain and increase production while maintaining efficient, safe and environmentally responsible operations. EOG continues to increase its operating activities by drilling new wells in existing and new areas. Operating and maintenance costs within these existing and new areas, as well as the costs of services charged to EOG by vendors, fluctuate over time.
Lease and well expenses of $1,675 million in 2025 increased $103 million from $1,572 million in 2024 primarily due to increased operating and maintenance costs ($89 million) in the United States and increased lease and well administrative expenses ($42 million), partially offset by decreased workovers expenditures ($38 million) in the United States.
GP&T costs represent costs to process and deliver hydrocarbon products from the lease to a downstream point of sale. GP&T costs include operating and maintenance expenses from EOG-owned assets, fees paid to third-party operators and administrative expenses associated with operating EOG's GP&T assets. EOG pays third parties to process the majority of its natural gas production to extract NGLs.
GP&T costs increased $412 million to $2,134 million in 2025 compared to $1,722 million in 2024 primarily due to increased production in the Utica ($375 million) and the Permian Basin ($93 million), partially offset by decreased costs in the Eagle Ford play ($45 million) and the Powder River Basin ($14 million).
DD&A of the cost of proved oil and gas properties is calculated using the unit-of-production method. EOG's DD&A rate and expense are the composite of numerous individual DD&A group calculations. There are several factors that can impact EOG's composite DD&A rate and expense, such as field production profiles, drilling or acquisition of new wells, disposition of existing wells and reserve revisions (upward or downward) primarily related to well performance, economic factors and impairments. Changes to these factors may cause EOG's composite DD&A rate and expense to fluctuate from period to period. DD&A of the cost of other property, plant and equipment is generally calculated using the straight-line depreciation method over the useful lives of the assets.
DD&A expenses in 2025 increased $353 million to $4,461 million from $4,108 million in 2024. DD&A expenses associated with oil and gas properties in 2025 were $298 million higher than in 2024. The increase primarily reflects increased production in the United States ($596 million) and Trinidad ($7 million), and increased unit rates in Trinidad ($8 million). This was partially offset by decreased unit rates in the United States ($197 million) and an adjustment to DD&A recorded in 2024 ($117 million) related to natural gas production used by EOG's domestic gathering systems. DD&A expenses associated with other property, plant and equipment in 2025 were $55 million higher than in 2024 primarily due to an increase in expense related to GP&T assets and equipment.
G&A expenses of $820 million in 2025 increased $151 million from $669 million in 2024 primarily due to increased professional services and other costs, including Encino acquisition-related costs ($100 million), employee-related costs ($47 million) and information systems costs ($10 million).
Interest expense, net of $235 million in 2025 increased $97 million from $138 million in 2024 primarily due to the issuance of the July Notes and the November Notes ($95 million), the issuance in November 2024 of the $1,000 million aggregate principal amount of 5.650% Senior Notes due 2054 ($50 million) and financing commitment costs related to the Encino acquisition ($6.5 million), partially offset by increased capitalized interest primarily related to the unproved leasehold acquired through the Encino acquisition ($40 million) and the maturity in April 2025 of the $500 million aggregate principal amount of 3.15% Senior Notes due 2025 ($12 million).
Exploration costs of $236 million in 2025 increased $62 million from $174 million in 2024 primarily due to increased geological and geophysical expenditures in Trinidad ($27 million), the United Arab Emirates ($23 million) and the United States ($7 million) as well as increased administrative expenses ($11 million), partially offset by decreased delay rentals ($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 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.
The following table represents impairments for the years ended December 31, 2025 and 2024 (in millions):
Proved properties
Unproved properties
Other assets
Firm commitment contracts
Total
Impairments of proved properties for the year ended December 31, 2025, were primarily due to the write-down to fair value of natural gas and crude oil assets in the Barnett Shale and Woodford Oil Window, mainly driven by play-specific economics and resource allocation.
Taxes other than income include severance/production taxes, ad valorem/property taxes, payroll taxes, franchise taxes and other miscellaneous taxes. Severance/production taxes are generally determined based on revenues from sales of crude oil and condensate, NGLs and natural gas, and ad valorem/property taxes are generally determined based on the valuation of the underlying assets.
Taxes other than income in 2025 decreased $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) in 2024. The decrease in taxes other than income was primarily due to decreased severance/production taxes ($60 million), partially offset by decreased state severance tax refunds ($30 million) and increased ad valorem/property taxes ($10 million), all in the United States.
Other income, net, was $212 million in 2025 compared to other income, net, of $274 million in 2024. The decrease of $62 million in 2025 was primarily due to a decrease in interest income.
Income taxes of $1,382 million in 2025 decreased from income taxes of $1,815 million in 2024 primarily due to decreased pretax income. The net effective tax rate for 2025 was unchanged from the prior year rate of 22%.
Capital Resources and Liquidity
Liquidity Overview. At December 31, 2025, EOG maintained a strong financial and liquidity position, including $3.4 billion of cash and cash equivalents on hand and $3.0 billion of availability under the New Facility (which remains undrawn).
The primary sources of cash for EOG during the three-year period ended December 31, 2025, were funds generated from operations and net proceeds from the issuance of long-term debt. The primary uses of cash were exploration and development expenditures; funds used in operations; dividend payments to stockholders; share repurchases and other purchases of treasury stock; the acquisition of Encino; repayment of long-term debt; and other property, plant, and equipment expenditures.
See Notes 2 and 13 to the Consolidated Financial Statements for further discussion on our debt obligations, including the fair value of our senior notes.
Cash Flow. Net cash provided by operating activities of $10,044 million in 2025 decreased $2,099 million from $12,143 million in 2024 primarily due to an increase in net cash paid for income taxes and tax credit purchases ($1,090 million), an increase in cash operating expenses ($696 million), net cash paid for 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 ($178 million), partially offset by an increase in revenues from sales of crude oil and condensate, NGLs and natural gas ($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 primarily due to the acquisition of Encino ($4,451 million), an increase in additions to oil and gas properties ($762 million) and a decrease in cash provided by working capital associated with investing activities ($297 million), partially offset by a decrease in additions to other property, plant and equipment ($540 million).
Net cash used in financing activities of $2,804 million in 2025 included share repurchases and other purchases of treasury stock ($2,564 million), repayments of long-term debt ($2,516 million) and dividend payments to stockholders ($2,161 million). Cash provided by financing activities in 2025 included long-term debt borrowings ($4,471 million). Net cash used in financing activities of $4,361 million in 2024 included share repurchases and other purchases of treasury stock ($3,246 million) and cash dividend payments ($2,087 million). Cash provided by financing activities in 2024 included long-term debt borrowings ($985 million).
Total Expenditures
The table below sets out the components of total expenditures for the years ended December 31, 2025, 2024 and 2023 (in millions):
Expenditure Category
Capital
Exploration and Development Drilling (1)
Facilities
Leasehold Acquisitions (2)
Property Acquisitions (3)
Capitalized Interest
Subtotal
Exploration Costs
Dry Hole Costs
Exploration and Development Expenditures
Asset Retirement Costs (4)
Total Exploration and Development Expenditures
Other Property, Plant and Equipment (5)
Total Expenditures
(1) Exploration and development drilling included $90 million related to non-cash development drilling in 2023.
(2) Leasehold acquisitions included $24 million, $85 million and $99 million related to non-cash property exchanges in 2025, 2024 and 2023, respectively.
(3) Property acquisitions for the year ended December 31, 2025, included $6,703 million related to the Encino acquisition. Property acquisitions included $24 million and $6 million related to non-cash property exchanges in 2024 and 2023, respectively.
(4) Asset retirement costs for the year ended December 31, 2025, included $52 million related to the Encino acquisition. Asset Retirement Costs for 2024 included a downward revision to asset retirement obligations of $83 million.
(5) Other property, plant and equipment included $137 million related to the acquisition of a gathering and processing system in South Texas and $134 million related to the acquisition of a gathering and processing system in the Powder River Basin in 2024 and 2023, respectively.
Exploration and development expenditures of $13,078 million for 2025 were $7,442 million higher than the prior year primarily due to increased property acquisitions (including Encino) ($6,970 million), increased development drilling expenditures ($405 million), increased exploration expenses ($62 million), increased capitalized interest ($41 million), increased dry hole costs ($35 million) and increased facility expenditures ($16 million), partially offset by decreased exploration drilling expenditures ($54 million) and decreased leasehold acquisitions ($33 million). The 2025 exploration and development expenditures of $13,078 million included $7,003 million in property acquisitions, $5,365 million in development drilling and facilities, $624 million in exploration and $86 million in capitalized interest. The 2024 exploration and development expenditures of $5,636 million included $4,944 million in development drilling and facilities, $614 million in exploration, $45 million in capitalized interest and $33 million in property acquisitions. The 2023 exploration and development expenditures of $5,761 million included $5,101 million in development drilling and facilities, $611 million in exploration, $33 million in capitalized interest and $16 million in property acquisitions.
The level of exploration and development expenditures, including acquisitions, will vary in future periods depending on energy market conditions and other economic factors. EOG believes it has significant flexibility and availability with respect to financing alternatives and the ability to adjust its exploration and development expenditure budget as circumstances warrant. While EOG has certain continuing commitments associated with expenditure plans related to its operations, such commitments are not expected to be material when considered in relation to the total financial capacity of EOG. Further, EOG believes that its sources of liquidity are adequate for other near-term and long-term funding requirements, including its cash return commitment, debt service obligations, repayments of debt maturities and other commitment and contingencies. However, the adequacy of liquidity sources could be impacted by various factors, including general economic and market conditions, volatility in commodity prices or financial and capital markets and regulatory and other factors discussed in this report under ITEM 1A, Risk Factors.
Financial Commodity and Other Derivative Transactions
Presented below is a comprehensive summary of EOG's financial commodity derivative contracts settled during the year ended December 31, 2025 (closed) and remaining for 2026 and thereafter, as of February 18, 2026 (inclusive of the contracts assumed, via novation, from Encino). Natural gas volumes are presented in MMBtu per day (MMBtud) and prices are presented in dollars per MMBtu ($/MMBtu). NGL volumes are presented in MBbld and prices are presented in $/Bbl.
Natural Gas Financial Price Swap Contracts
Contracts Sold
Period
Settlement Index
Volume
(MMBtud in thousands)
Weighted Average Price
($/MMBtu)
February - July 2025 (closed)
NYMEX Henry Hub
August - December 2025 (closed)
NYMEX Henry Hub
January - February 2026 (closed)
NYMEX Henry Hub
March - June 2026
NYMEX Henry Hub
July - December 2026
NYMEX Henry Hub
Natural Gas Basis Swap Contracts
Contracts Sold
Period
Settlement Index
Volume
(MMBtud in thousands)
Weighted Average Price
Differential
($/MMBtu)
January - December 2025 (closed)
NYMEX Henry Hub Houston Ship Channel (HSC) Differential (1)
(1) This settlement index is used to fix the differential between pricing at the Houston Ship Channel and NYMEX Henry Hub prices.
Natural Gas Collar Contracts
Contracts Sold
Weighted Average Price
($/MMBtu)
Period
Settlement Index
Volume
(MMBtud in thousands)
Ceiling Price
Floor Price
September 2025 (closed)
NYMEX Henry Hub
October - December 2025 (closed)
NYMEX Henry Hub
January - February 2026 (closed)
NYMEX Henry Hub
March - June 2026
NYMEX Henry Hub
July - December 2026
NYMEX Henry Hub
January - December 2027
NYMEX Henry Hub
Ethane Financial Price Swap Contracts
Contracts Sold
Period
Settlement Index
Volume
(MBbld)
Weighted Average Price
($/Bbl)
August - December 2025 (closed)
Mont Belvieu Ethane (non-Tet)
January 2026 (closed)
Mont Belvieu Ethane (non-Tet)
February - December 2026
Mont Belvieu Ethane (non-Tet)
Butane Financial Price Swap Contracts
Contracts Sold
Period
Settlement Index
Volume
(MBbld)
Weighted Average Price
($/Bbl)
August - December 2025 (closed)
Mont Belvieu Butane (non-Tet)
Propane Financial Price Swap Contracts
Contracts Sold
Period
Settlement Index
Volume
(MBbld)
Weighted Average Price
($/Bbl)
August - December 2025 (closed)
Mont Belvieu Propane (Tet)
January 2026 (closed)
Mont Belvieu Propane (Tet)
February - December 2026
Mont Belvieu Propane (Tet)
In connection with its financial commodity derivative contracts, EOG had no collateral posted and no collateral held at February 18, 2026. The amount of posted collateral will increase or decrease based on fluctuations in forward NYMEX Henry Hub prices.
Natural Gas Sales Linked to Brent Crude Oil . In February 2024, EOG entered into a 10-year agreement, commencing in 2027, to sell 180,000 MMBtud of its domestic natural gas production, with 140,000 MMBtud to be sold at a price indexed to Brent and the remaining volumes to be sold at a price indexed to Brent or a U.S. Gulf Coast gas index. It was determined that this agreement meets the definition of a derivative under the Derivatives and Hedging Topic of the ASC and does not qualify for the normal purchases and normal sales scope exception. As such, this agreement is accounted for as a derivative using the mark-to-market accounting method. Changes in the fair value are recognized as gains or losses in the period of change on the Consolidated Statements of Income and Comprehensive Income.
Financing
EOG's debt-to-total capitalization ratio was 21% at December 31, 2025, compared to 14% at December 31, 2024. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.
At December 31, 2025 and 2024, respectively, EOG had outstanding $7,890 million and $4,640 million aggregate principal amount of senior notes, which had estimated fair values of $7,849 million and $4,441 million, respectively. The estimated fair value of debt was based upon quoted market prices and, where such prices were not available, other observable inputs regarding interest rates available to EOG at year-end. EOG's debt is at fixed interest rates. While changes in interest rates affect the fair value of EOG's senior notes, such changes do not expose EOG to material fluctuations in earnings or cash flow.
During 2025, EOG funded its capital program and operations by utilizing cash provided by operating activities, proceeds from the issuances of senior notes and cash on hand. While EOG maintains the New Facility to back its commercial paper program (which replaced its prior $1.9 billion revolving credit facility), there were no borrowings outstanding at any time during 2025 under either facility and the amount outstanding at year-end was zero. EOG considers the availability of the New Facility, as described in Note 2 to Consolidated Financial Statements, to be sufficient to meet its ongoing operating needs.
Outlook
Pricing. Crude oil, NGLs and natural gas prices have been volatile, and this volatility is expected to continue. As a result of the many uncertainties associated with the world economic and political environment, worldwide supplies of, and demand for, crude oil and condensate, NGLs and natural gas, the availability of other energy supplies, the relative competitive relationships of the various energy sources in the view of consumers and other factors, EOG is unable to predict what changes may occur in crude oil and condensate, NGLs, natural gas, ammonia and methanol prices in the future. The market price of crude oil and condensate, NGLs and natural gas in 2026 will impact the amount of cash generated from EOG's operating activities, which will in turn impact EOG's financial position. As of February 18, 2026, the average 2026 NYMEX crude oil and natural gas prices were $63.23 per barrel and $3.84 per MMBtu, respectively, representing a decrease of 2% for crude oil and an increase of 12% for natural gas from the average NYMEX prices in 2025. See ITEM 1A, Risk Factors for additional discussion of the impact of commodity prices (including fluctuations in commodity prices) on our financial condition, cash flows and results of operations.
Based on EOG's tax position, EOG's price sensitivity in 2026 for each $1.00 per barrel increase or decrease in crude oil and condensate price, combined with the estimated change in NGLs price, is approximately $174 million for net income and $223 million for pretax cash flows from operating activities. 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 2026 for which prices have not been determined under long-term marketing contracts, EOG's price sensitivity for each $0.10 per Mcf increase or decrease in natural gas price is approximately $64 million for net income and $83 million for pretax cash flows from operating activities. For information regarding EOG's crude oil, NGLs and natural gas financial commodity derivative contracts through February 18, 2026, see "Financial Commodity and Other Derivative Transactions" above.
Capital. 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 the Delaware Basin play, Eagle Ford play, Dorado gas play and Utica play where it generates its highest rates-of-return. To further enhance the economics of these plays, EOG expects to continue to improve well performance and to focus on improving operating efficiencies. In addition, EOG expects to spend a portion of its anticipated 2026 capital expenditures on leasing acreage, evaluating new prospects, gathering and processing infrastructure, transportation infrastructure and environmental projects.
The total anticipated 2026 capital expenditures of 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, is structured to maintain EOG's strategy of capital discipline by funding its exploration, development and exploitation activities primarily from available internally generated cash flows and cash on hand. EOG has significant flexibility with respect to financing alternatives, including borrowings under its commercial paper program, bank borrowings, borrowings under its $3.0 billion senior unsecured revolving credit facility and equity and debt offerings.
Operations. In 2026, crude oil and total crude oil equivalent production are expected to increase from 2025 levels. In addition, in 2026 EOG expects to (i) continue to undertake initiatives to increase its drilling, completion and operating efficiencies and improve the performance of its wells and (ii) when available and advantageous, enter into agreements with its service providers to secure the costs and availability of certain drilling and completions services it utilizes as part of its operations.
Cash Requirements. Certain of EOG's capital expenditures and operating costs are subject to contracts with minimum commitments, including those that meet the definition of a lease under ASC "Leases (Topic 842)". In 2026, EOG anticipates the following cash requirements under these commitments (in millions):
Finance Leases (1)
Operating Leases (1)
Leases Effective, Not Commenced (1)
Transportation and Storage Service Commitments (2) (3)
Purchase and Service Obligations (3)
Total Cash Requirements
(1) For more information on contracts that meet the definition of a lease under ASC "Leases (Topic 842)," see Note 17 to Consolidated Financial Statements.
(2) Amounts exclude transportation and storage service commitments that meet the definition of a lease. Amounts shown are based on current transportation and storage rates and the foreign currency exchange rates used to convert Canadian dollars into United States dollars at December 31, 2025. Management does not believe that any future changes in these rates before the expiration dates of these commitments will have a material adverse effect on the financial condition or results of operations of EOG.
(3) For years 2026 and beyond, $65 million of capital commitments have been made. For more information on transportation and storage service commitments and purchase and service obligations, see Note 8 to Consolidated Financial Statements.
In 2026, EOG has no senior notes maturing and EOG expects to pay interest of $393 million on senior notes. For more information on EOG's current and long-term debt, see Note 2 to Consolidated Financial Statements.
Cash requirements to settle the liability for EOG's pension and postretirement benefit obligations and the liability for dismantlement, abandonment and asset retirement obligations (see Notes 7 and 15, respectively, to Consolidated Financial Statements) are excluded because they are subject to estimates and the timing of settlement is unknown.
EOG expects to fund its exploration, development and exploitation activities, its cash return commitment, its debt service obligations and other cash requirements, both in 2026 and in future years, primarily from internally generated cash flows and cash on hand. As discussed above, EOG has significant flexibility with respect to financing alternatives, including borrowings under its commercial paper program, bank borrowings, borrowings under the New Facility and equity and debt offerings.
Summary of Critical Accounting Policies and Estimates
EOG prepares its financial statements and the accompanying notes in conformity with accounting principles generally accepted in the United States, which require management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompanying notes. EOG identifies certain accounting policies and estimates as critical based on, among other things, their impact on EOG's financial condition, results of operations or liquidity, and the degree of difficulty, subjectivity and complexity in their application. Critical accounting policies and estimates cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Management routinely discusses the development, selection and disclosure of each of the critical accounting policies and estimates. Following is a discussion of EOG's most critical accounting policies and estimates:
Proved Oil and Gas Reserves
EOG's engineers estimate proved oil and gas reserves in accordance with United States Securities and Exchange Commission (SEC) regulations, which directly impact financial accounting estimates, including depreciation, depletion and amortization and impairments of proved properties and related assets. Proved reserves represent estimated quantities of crude oil and condensate, NGLs and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be economically producible in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made.
The process of estimating quantities of proved oil and gas reserves is complex, requiring significant subjective decisions in the evaluation of available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, crude oil and condensate, NGLs and natural gas prices, continual reassessment of the viability of production under varying economic conditions and improvements and other changes in geological, geophysical and engineering evaluation methods. Proved reserves are estimated using a trailing 12-month average price, in accordance with SEC rules. Crude oil, NGLs and natural gas prices have exhibited significant volatility in the past, and EOG expects that volatility to continue in the future. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time. For related discussion, see ITEM 1A, Risk Factors, and "Supplemental Information to Consolidated Financial Statements."
Depreciation, Depletion and Amortization for Oil and Gas Properties
The quantities of estimated proved oil and gas reserves are a significant component of EOG's calculation of depreciation, depletion and amortization expense, and revisions in such estimates may alter the rate of future expense. Holding all other factors constant, if reserves are revised upward or downward, earnings will increase or decrease, respectively.
Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method. The reserve base used to calculate depreciation, depletion and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base used includes only proved developed reserves.
Impairments
Oil and gas lease acquisition costs are capitalized when incurred. 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. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties.
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 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.
Crude oil, NGLs and natural gas prices have exhibited significant volatility in the past, and EOG expects that volatility to continue in the future. During the five years ended December 31, 2025, WTI crude oil spot prices have fluctuated from approximately $47.47 per barrel to $123.64 per barrel, and Henry Hub natural gas spot prices have ranged from approximately $1.21 per MMBtu to $23.86 per MMBtu. Market prices for NGLs are influenced by the components extracted, including ethane, propane, butane and natural gasoline, among others, and the respective market pricing for each component.
EOG uses the five-year NYMEX futures strip for WTI crude oil and Henry Hub natural gas and the five-year Oil Price Information Services futures strip for NGLs components (in each case as of the applicable balance sheet date) as a basis to estimate future crude oil, NGLs and natural gas prices. EOG's proved reserves estimates, including the timing of future production, are also subject to significant assumptions and judgment, and are frequently revised (upwards and downwards) as more information becomes available. In the future, if any combination of crude oil prices, NGLs prices, natural gas prices or estimated proved reserves diverge negatively from EOG's current estimates, impairment charges may be necessary.
These estimates, which factor into EOG's unproved and proved property impairment calculations, involve the use of various assumptions and judgment. Differing assumptions could impact the timing and amount of an impairment in any given period. Any impairment will decrease earnings in the period in which it is recognized. See Notes 13 and 14 to Consolidated Financial Statements for further discussion of impairments of oil and gas properties and other assets.
Business Combinations
EOG accounts for business combinations under the Business Combinations Topic of the ASC, which requires identifiable assets acquired and liabilities assumed to be recognized at their acquisition date fair values. In estimating the fair values of assets acquired and liabilities assumed, various assumptions are applied.
The most significant assumptions relate to the estimated fair values of proved and unproved crude oil and natural gas properties for which EOG utilized the Income Approach described in ASC 820. The assumptions made in performing the valuation under the Income Approach include future crude oil, NGLs and natural gas prices, future operating and development costs, anticipated production from reserves, a weighted average cost of capital rate and risk adjustment factors for proved undeveloped, probable and possible reserves.
The assumptions and inputs used in determining fair value estimates involve significant management judgment and are based on industry, market and economic conditions at the time of the acquisition. While these estimates are based on assumptions considered reasonable, they are inherently uncertain and actual results may differ.
Information Regarding Forward-Looking Statements
This Annual Report on Form 10-K includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, goals, returns and rates of return, budgets, reserves, levels of production, capital expenditures, operating costs and asset sales, statements regarding future commodity prices, statements regarding the plans and objectives of EOG's management for future operations and statements and projections regarding the strategic rationale for, and anticipated benefits of, EOG's acquisition of Encino Acquisition Partners, LLC (Encino) are forward‐looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "aims," "ambition," "initiative," "goal," "may," "will," "focused on," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward‐looking statements. In particular, statements, express or implied, concerning (i) EOG's future financial or operating results and returns, (ii) EOG's ability to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control drilling, completion and operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, other environmental matters or safety matters, pay and/or increase regular and/or special dividends or repurchase shares or (iii) the successful integration of Encino's assets and operations or the strategic rationale for, or anticipated benefits of, EOG's acquisition of Encino, in each case are forward‐looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that such assumptions are accurate or will prove to have been correct or that any of such expectations will be achieved (in full or at all) or will be achieved on the expected or anticipated timelines. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:
• the timing, magnitude and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids (NGLs), natural gas and related commodities;
• the extent to which EOG is successful in its efforts to acquire or discover additional reserves;
• the extent to which EOG is successful in its efforts to (i) economically develop its acreage in, (ii) produce reserves and achieve anticipated production levels and rates of return from, (iii) decrease or otherwise control its drilling, completion and operating costs and capital expenditures related to, and (iv) maximize reserve recoveries from, its existing and future crude oil and natural gas exploration and development projects and associated potential and existing drilling locations;
• the success of EOG's cost-mitigation initiatives and actions in offsetting the impact of any inflationary or other pressures on EOG's operating costs and capital expenditures;
• the extent to which EOG is successful in its efforts to market its production of crude oil and condensate, NGLs and natural gas;
• security threats, including cybersecurity threats and disruptions to our business and operations from breaches of our information technology systems, physical breaches of our facilities and other infrastructure or breaches of the information technology systems, facilities and infrastructure of third parties with which we transact business, and enhanced regulatory focus on the prevention of, and disclosure requirements relating to, cyber incidents;
• the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, storage, transportation, refining, liquefaction and export facilities and equipment;
• the availability, cost, terms and timing of issuance or execution of mineral licenses, concessions and leases and governmental and other permits and rights-of-way, and EOG's ability to retain mineral licenses, concessions and leases;
• the impact of, and changes in, government policies, laws and regulations, including climate change-related regulations, policies and initiatives (for example, with respect to air emissions); tax laws and regulations (including, but not limited to, carbon tax or other emissions-related legislation); environmental, health and safety laws and regulations relating to disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations affecting the leasing of acreage and permitting for oil and gas drilling and the calculation of royalty payments in respect of oil and gas production; laws and regulations imposing additional permitting and disclosure requirements, additional operating restrictions and conditions or restrictions on drilling and completion operations and on the transportation of crude oil, NGLs and natural gas; laws and regulations with respect to financial commodity and other derivative instruments and hedging activities; laws and regulations with respect to the import and export of crude oil, natural gas and related commodities; and trade policies, tariffs, trade agreements and other trade restrictions;
• the impact of climate change-related legislation, policies and initiatives; climate change-related political, social and shareholder activism; and physical, transition and reputational risks and other potential developments related to climate change;
• the extent to which EOG is able to successfully and economically develop, implement and carry out its emissions and other environmental or safety-related initiatives and achieve its related targets, goals, ambitions and initiatives;
• EOG's failure to realize, in full or at all, the anticipated benefits of its acquisition of Encino and/or business disruptions resulting from the acquisition (e.g., relating to the integration of Encino's assets and operations into EOG's operations) that could harm EOG's business operations (including current plans and operations and the diversion of management's attention from EOG's ongoing business operations);
• EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, identify and resolve existing and potential issues with respect to such properties and accurately estimate reserves, production, drilling, completion and operating costs and capital expenditures with respect to such properties;
• the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully, economically and in compliance with applicable laws and regulations;
• competition in the oil and gas exploration and production industry for the acquisition of licenses, concessions, leases and properties;
• the availability and cost of, EOG's ability to retain, and competition in the oil and gas exploration and production industry for, employees, labor and other personnel, facilities, equipment, materials (such as water, sand, fuel and tubulars) and services;
• the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;
• weather and natural disasters, including its impact on crude oil and natural gas demand, and related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, liquefaction, compression, storage, transportation, and export facilities;
• the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;
• EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;
• the extent to which EOG is successful in its completion of planned asset dispositions;
• the extent and effect of any hedging activities engaged in by EOG;
• the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;
• geopolitical factors and political conditions and developments around the world (such as the imposition of tariffs or trade or other economic sanctions, political instability and armed conflicts), including in the areas in which EOG operates;
• the extent to which EOG incurs uninsuredlosses and liabilities or losses and liabilities in excess of its insurance coverage; and
• the other factors described under ITEM 1A, Risk Factors of this Annual Report on Form 10-K and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.
In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration or extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.
