Want to see EOG full AI Analyst Report?
EOG Resources (EOG) Risk Analysis
Risk Overview Q2, 2026
Source: the company's latest filing for the period ended Jun 30, 2026, filed Aug 04, 2026
Risk Change Over Time
- Accounting & Financial Operations - Risk 1Dividend Declarations.
On February 24, 2026, the Board declared a quarterly cash dividend on the common stock of $1.02 per share paid on April 30, 2026, to stockholders of record as of April 16, 2026. On May 5, 2026, the Board declared a quarterly cash dividend on the common stock of $1.02 per share to be paid on July 31, 2026, to stockholders of record as of July 17, 2026. Results of Operations The following review of operations for the three months ended March 31, 2026 and 2025 should be read in conjunction with the Condensed Consolidated Financial Statements of EOG and notes thereto included in this Quarterly Report on Form 10-Q.
- Accounting & Financial Operations - Risk 2Operating Revenues and Other.
During the first quarter of 2026, total operating revenues increased $1,252 million, or 22%, to $6,921 million from $5,669 million for the same period of 2025. Total revenues from sales of EOG's production of crude oil and condensate, NGLs and natural gas for the first quarter of 2026 increased $760 million, or 17%, to $5,262 million from $4,502 million for the same period of 2025. EOG recognized net gains on the mark-to-market of financial commodity and other derivative contracts of $113 million for the first quarter of 2026 compared to net losses of $191 million for the same period of 2025. Gathering, processing and marketing revenues for the first quarter of 2026 increased $156 million, or 12%, to $1,496 million from $1,340 million for the same period of 2025. EOG recognized net gains on asset dispositions of $31 million for the first quarter of 2026 compared to net losses on asset dispositions of $1 million for the same period of 2025. Volume and price statistics for the three-month periods ended March 31, 2026 and 2025 were as follows (see Note 8 for segment financial information): Three Months EndedMarch 31,20262025Crude Oil and Condensate Volumes (MBbld) (1)United States546.5 500.9 Trinidad1.9 1.2 Other International (2)0.1 - Total548.5 502.1 Average Crude Oil and Condensate Prices ($/Bbl) (3)United States$72.48 $72.90 Trinidad68.91 61.12 Other International (2)89.12 - Composite72.47 72.87 Natural Gas Liquids Volumes (MBbld) (1)United States332.1 241.7 Total332.1 241.7 Average Natural Gas Liquids Prices ($/Bbl) (3)United States$22.20 $26.29 Natural Gas Volumes (MMcfd) (1)United States2,769 1,834 Trinidad239 246 Other International (2)12 - Total3,020 2,080 Average Natural Gas Prices ($/Mcf) (3)United States$3.75 $3.36 Trinidad3.91 3.78 Other International (2)3.26 - Composite3.76 3.41 Crude Oil Equivalent Volumes (MBoed) (4)United States1,340.1 1,048.3 Trinidad41.7 42.1 Other International (2)2.0 - Total1,383.8 1,090.4 Total MMBoe (4)124.5 98.1 Thousand barrels per day or million cubic feet per day, as applicable. Production volumes from Bahrain operations; natural gas realized price represents contract price less partner's processing and distribution costs. Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity and other derivative instruments (see Note 9 to the Condensed Consolidated Financial Statements). 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 for the first quarter of 2026 increased $284 million, or 9%, to $3,577 million from $3,293 million for the same period of 2025, primarily due to an increase of 46.4 MBbld, or 9%, in crude oil and condensate deliveries ($304 million), partially offset by a lower composite average price ($20 million). Increased production was primarily from the Utica. EOG's composite crude oil and condensate price for the first quarter of 2026 decreased 1% to $72.47 per barrel compared to $72.87 per barrel for the same period of 2025. NGL revenues for the first quarter of 2026 increased $92 million, or 16%, to $664 million from $572 million for the same period of 2025 due to an increase of 90.4 MBbld, or 37%, in NGL deliveries ($215 million), partially offset by a lower composite average price ($123 million). Increased production was primarily from the Utica and Permian Basin. EOG's composite NGL price for the first quarter of 2026 decreased 16% to $22.20 per barrel compared to $26.29 per barrel for the same period of 2025. Natural gas revenues for the first quarter of 2026 increased $384 million, or 60%, to $1,021 million from $637 million for the same period of 2025, primarily due to an increase of 940 MMcfd, or 45%, in natural gas deliveries ($289 million) and a higher composite average price ($95 million). Increased deliveries were primarily from the Utica and Permian Basin. EOG's composite natural gas price for the first quarter of 2026 increased 10% to $3.76 per Mcf compared to $3.41 per Mcf for the same period of 2025. During the first quarter of 2026, EOG recognized net gains on the mark-to-market of financial commodity and other derivative contracts of $113 million compared to net losses of $191 million for the same period of 2025. The net gains of $113 million included gains of $119 million related to the Brent crude oil (Brent) linked gas sales contract. During the first quarter of 2026, net cash paid for settlements of financial commodity derivative contracts was $53 million compared to net cash paid for settlements of financial commodity derivative contracts of $38 million for the same period of 2025. 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 for the first three months of 2026 increased $97 million as compared to the same period of 2025 primarily due to higher margins on crude oil marketing activities.
- Accounting & Financial Operations - Risk 3Operating and Other Expenses.
For the first quarter of 2026, operating expenses of $4,323 million were $513 million higher than the $3,810 million incurred during the first quarter of 2025. The following table presents the costs per barrel of oil equivalent (Boe) for the three-month periods ended March 31, 2026 and 2025: Three Months EndedMarch 31,20262025Lease and Well$3.71 $4.09 Gathering, Processing and Transportation Costs (GP&T)5.25 4.48 Depreciation, Depletion and Amortization (DD&A) -Oil and Gas Properties9.03 9.71 Other Property, Plant and Equipment 0.55 0.61 General and Administrative (G&A)1.49 1.74 Interest Expense, Net0.53 0.48 Total (1)$20.56 $21.11 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 the three months ended March 31, 2026, compared to the same period of 2025, are set forth below. See "Operating Revenues and Other" above for a discussion of volumes. Lease and well expenses 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, 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 $462 million for the first quarter of 2026 increased $61 million from $401 million for the same prior year period primarily due to increased operating and maintenance costs in the United States ($44 million) and increased lease and well administrative expenses ($19 million). 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 of $654 million for the first quarter of 2026 increased $214 million from $440 million for the same prior year period primarily due to increased GP&T costs related to increased production in the Utica ($221 million) and Permian Basin ($11 million), partially offset by decreased costs in the Eagle Ford play ($15 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 for the first quarter of 2026 increased $180 million to $1,193 million from $1,013 million for the same prior year period. DD&A expenses associated with oil and gas properties for the first quarter of 2026 were $172 million higher than the same prior year period. The increase primarily reflects increased production in the United States ($248 million), partially offset by decreased unit rates in the United States ($69 million) and Trinidad ($9 million). DD&A expenses associated with other property, plant and equipment for the first quarter of 2026 were $8 million higher than the same prior year period primarily related to GP&T assets and equipment. G&A expenses of $185 million for the first quarter of 2026 increased $14 million from $171 million for the same prior year period primarily due to increased employee-related costs. Interest expense, net of $66 million for the first quarter of 2026 increased $19 million compared to the same prior year period primarily due to the issuance in July 2025 of the $1,250 million aggregate principal amount of 5.350% Senior Notes due 2036 ($17 million), $1,250 million aggregate principal amount of 5.000% Senior Notes due 2032 ($16 million), $500 million aggregate principal amount of 5.950% Senior Notes due 2055 ($7 million) and $500 million aggregate principal amount of 4.400% Senior Notes due 2028 ($6 million), and the issuance in November 2025 of the $750 million aggregate principal amount of 4.400% Senior Notes due 2031 ($9 million) and $250 million aggregate principal amount of 5.950% Senior Notes due 2055 ($4 million), partially offset by increased capitalized interest ($25 million), the repayment in December 2025 of the $750 million aggregate principal amount of 4.15% Senior Notes due 2026 ($8 million), and the maturity in April 2025 of the $500 million aggregate principal amount of 3.15% Senior Notes due 2025 ($4 million). Impairments include: amortization of individually insignificant unproved oil and gas property costs as well as impairments of proved oil and gas properties; other property, plant and equipment; individually significant unproved oil and gas property costs; and other assets. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. Unproved properties with individually significant acquisition costs are reviewed individually for impairment. The following table sets forth impairments for the first quarter of 2026 and 2025 (in millions): Three Months EndedMarch 31,20262025Proved properties$- $32 Unproved properties19 12 Inventories20 - Total$39 $44 Other income, net of $23 million for the first quarter of 2026 decreased $42 million from $65 million for the same prior year period primarily due to decreased interest income ($37 million) and an increase in deferred compensation expense ($6 million). Income taxes of $575 million for the first quarter of 2026 increased from $414 million for the first quarter of 2025 primarily due to increased pretax income. The net effective tax rate for the first quarter of 2026 increased to 23% from 22% for the first quarter of 2025. Capital Resources and Liquidity
- Accounting & Financial Operations - Risk 4Cash Flow.
Net cash provided by operating activities of $2,966 million for the first three months of 2026 increased $677 million compared to the same period of 2025 primarily due to an increase in revenues from sales of crude oil and condensate, NGLs and natural gas ($760 million), a decrease in net cash paid for income taxes ($728 million) and an increase in gathering, processing and marketing revenues less marketing costs ($97 million), partially offset by an increase in net cash used in working capital and other assets and liabilities ($386 million), an increase in cash operating expenses ($282 million) and an increase in interest paid ($71 million). Net cash used in investing activities of $1,545 million for the first three months of 2026 increased $115 million compared to the same period of 2025 primarily due to an increase in additions to oil and gas properties ($110 million), an increase in cash used in working capital associated with investing activities ($86 million) and an increase in additions to other property, plant and equipment ($51 million), partially offset by an increase in proceeds from sales of assets ($132 million). Net cash used in financing activities of $968 million for the first three months of 2026 included dividend payments to stockholders ($544 million) and share repurchases and other purchases of treasury stock ($418 million). Net cash used in financing activities of $1,352 million for the first three months of 2025 included share repurchases and other purchases of treasury stock ($806 million) and dividend payments to stockholders ($538 million).
- Accounting & Financial Operations - Risk 5Total Expenditures.
Total Expenditures. For the full-year 2026, EOG's updated budget for exploration and development and other property, plant and equipment expenditures is 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 table below sets out the components of total expenditures for the three-month periods ended March 31, 2026 and 2025 (in millions): Three Months EndedMarch 31,20262025Expenditure CategoryCapitalExploration and Development Drilling$1,280 $1,152 Facilities118 145 Leasehold Acquisitions (1)77 48 Property Acquisitions (2)23 (1)Capitalized Interest37 12 Subtotal1,535 1,356 Exploration Costs45 41 Dry Hole Costs23 34 Exploration and Development Expenditures1,603 1,431 Asset Retirement Costs12 13 Total Exploration And Development Expenditures1,615 1,444 Other Property, Plant and Equipment153 102 Total Expenditures$1,768 $1,546 Leasehold acquisitions included $52 million and $9 million for the three-month periods ended March 31, 2026 and 2025, respectively, related to non-cash property exchanges. Property acquisitions for the three-month period ended March 31, 2026 included $15 million related to revisions to the Encino purchase price allocation. Exploration and development expenditures of $1,603 million for the first three months of 2026 were $172 million higher than the same period of 2025 primarily due to increased exploration and development drilling expenditures ($128 million) and increased capitalized interest ($25 million). Exploration and development expenditures for the first three months of 2026 of $1,603 million consisted of $1,339 million in development drilling and facilities, $204 million in exploration, $37 million in capitalized interest and $23 million in property acquisitions. Exploration and development expenditures for the first three months of 2025 of $1,431 million consisted of $1,317 million in development drilling and facilities, $103 million in exploration and $12 million in capitalized interest. 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.
- Accounting & Financial Operations - Risk 6Financial Commodity and Other Derivative Transactions.
Financial Commodity and Other Derivative Transactions. As more fully discussed in Note 12 to the Consolidated Financial Statements included in EOG's 2025 Annual Report, EOG engages in price risk management activities from time to time. These activities are intended to manage EOG's exposure to fluctuations in commodity prices for crude oil, NGLs and natural gas. EOG utilizes financial commodity derivative instruments, primarily price swap, option, swaption, collar and basis swap contracts, as a means to manage this price risk. EOG has not designated any of its financial commodity and other derivative contracts as accounting hedges and, accordingly, accounts for financial commodity and other derivative contracts using the mark-to-market accounting method, including the Brent linked gas sales contract. Under this accounting method, changes in the fair value of outstanding financial and other derivative instruments are recognized as gains or losses in the period of change and are recorded as Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts on the Condensed Consolidated Statements of Income and Comprehensive Income. The related cash flow impact is reflected in Cash Flows from Operating Activities on the Condensed Consolidated Statements of Cash Flows. The total fair value of EOG's financial commodity and other derivative contracts was reflected on the Condensed Consolidated Balance Sheet at March 31, 2026, as a net asset of $214 million. As discussed in "Operating Revenues and Other," the net cash payments for settlements of financial commodity derivative contracts during the first quarter of 2026 was $53 million. Presented below is a comprehensive summary of EOG's financial commodity derivative contracts settled during the period from January 1, 2026 to April 24, 2026 (closed) and outstanding as of April 24, 2026. Natural gas volumes are presented in MMBtu per day (MMBtud) and prices are presented in dollars per MMBtu ($/MMBtu). NGL volumes are presented in MBbld and prices are presented in $/Bbl. Natural Gas Financial Price Swap ContractsContracts SoldPeriodSettlement IndexVolume (MMBtud in thousands)Weighted Average Price ($/MMBtu)January - April 2026 (closed)NYMEX Henry Hub460$3.78 May - June 2026NYMEX Henry Hub4603.78 July - December 2026NYMEX Henry Hub4503.79 Natural Gas Collar ContractsContracts SoldWeighted Average Price ($/MMBtu)PeriodSettlement IndexVolume(MMBtud in thousands)Ceiling PriceFloor PriceJanuary - April 2026 (closed)NYMEX Henry Hub80$4.28 $3.72 May - June 2026NYMEX Henry Hub804.28 3.72 July - December 2026NYMEX Henry Hub704.23 3.71 January - December 2027NYMEX Henry Hub1204.41 3.42 Ethane Financial Price Swap ContractsContracts SoldPeriodSettlement IndexVolume (MBbld)Weighted Average Price ($/Bbl)January - March 2026 (closed)Mont Belvieu Ethane (non-Tet)11 $10.94 April - December 2026Mont Belvieu Ethane (non-Tet)11 10.94 Propane Financial Price Swap ContractsContracts SoldPeriodSettlement IndexVolume (MBbld)Weighted Average Price ($/Bbl)January - March 2026 (closed)Mont Belvieu Propane (Tet)1 $30.24 April - December 2026Mont Belvieu Propane (Tet)1 30.24 In connection with its financial commodity derivative contracts, EOG had no collateral posted and no collateral held at April 24, 2026. The amount of posted collateral will increase or decrease based on fluctuations in forward NYMEX Henry Hub prices.
- Corporate Activity and Growth - Risk 7Three Months Ended March 31, 2026 vs. Three Months Ended March 31, 2025
Three Months Ended March 31, 2026 vs. Three Months Ended March 31, 2025
Risk Highlights Q2, 2026
Risk Word Cloud
Risk Factors Full Breakdown - Total Risks 24
- Manufacturing - Risk 1A 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.
- Manufacturing - Risk 2If 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.
- Manufacturing - Risk 3Drilling 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.
See a full breakdown of risk according to category and subcategory. The list starts with the category with the most risk. Click on subcategories to read relevant extracts from the most recent report.