EOG RESOURCES, INC. 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 efficient and safe operations and robust environmental stewardship practices and performance, is integral in the implementation of EOG's strategy. Commodity Prices. Prices for crude oil and condensate, natural gas liquids (NGLs) and natural gas have historically been volatile. This volatility is expected to continue due to the many uncertainties associated with the world political and economic environment (e.g., the ongoing conflict in the Middle East and the related disruption of maritime transportation routes for these commodities), the global supply of, and demand for, crude oil and condensate, NGLs and natural gas, the availability of other energy supplies and other factors, including tariffs, trade policies and agreements and trade barriers or other restrictions imposed by the U.S. government or other governments and the related impact of such measures on commodity and financial markets. Compared to its expectations at the beginning of 2026, EOG realized higher crude oil and condensate prices in the first half of 2026 and anticipates realizing higher crude oil and condensate prices for the full-year 2026, in each case as a result of the ongoing conflict in the Middle East. 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 first six months of 2026, the average U.S. New York Mercantile Exchange (NYMEX) crude oil and natural gas prices were $82.57 per barrel and $3.92 per million British thermal units (MMBtu), respectively, representing increases of 22% and 10%, respectively, from the average NYMEX prices for the same period in 2025. Market prices for NGLs are influenced by the components extracted, including ethane, propane and butane and natural gasoline, among others, and the respective market pricing for each component. Including the impact of EOG's NGL financial derivative contracts and based on EOG's tax position, EOG's price sensitivity as of June 30, 2026, for each $1.00 per barrel increase or decrease in crude oil and condensate price, combined with the estimated change in NGL price, is approximately $172 million for net income and $221 million for pretax cash flows from operating activities, in each case for the full-year 2026. Including the impact of EOG's natural gas financial derivative contracts and based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for which prices have not (as of June 30, 2026) been determined under long-term marketing contracts, EOG's price sensitivity as of June 30, 2026, for each $0.10 per thousand cubic feet increase or decrease in natural gas price, is approximately $60 million for net income and $77 million for pretax cash flows from operating activities, in each case for the full-year 2026. 23 Operating Efficiencies. EOG has undertaken (and continues to undertake) initiatives to increase its drilling, completion 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 have resulted in increased footage completed per day and pumping hours per day; (iii) drilling extended laterals, which has 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 completion 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, the ongoing conflict in the Middle East, 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. 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 plays and natural gas plays. During the first six months of 2026, EOG continued to focus on initiatives to increase its drilling, completion and operating efficiencies and improve well performance. In addition, EOG continued to evaluate certain potential crude oil and condensate, NGLs and natural gas exploration and development prospects and to look for opportunities to add drilling inventory through leasehold acquisitions, farm-ins, exchanges or tactical or bolt-on acquisitions. On a volumetric basis, as calculated using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas, crude oil and condensate and NGLs production accounted for approximately 66% and 70% of EOG's United States production during the first six months of 2026 and 2025, respectively. During the first six months of 2026, EOG's drilling and completion activities occurred primarily in the Delaware Basin, the Utica and the Eagle Ford play. EOG's major producing areas in the United States are in New Mexico, Texas and Ohio. Trinidad. In Trinidad, EOG continues to produce natural gas which is sold to the National Gas Company of Trinidad and Tobago Limited under existing supply contracts. Crude oil and condensate are sold to both Heritage Petroleum Company Limited and BP Trinidad and Tobago LLC. During the first six months of 2026, EOG completed its drilling program in the Mento Field located in the Ska, Mento and Reggae Area and continued construction of the Coconut offshore platform. Other International. As discussed in EOG's Annual Report on Form 10-K for the year ended December 31, 2025, filed on February 24, 2026 (EOG's 2025 Annual Report), EOG entered into exploration programs in both the Kingdom of Bahrain (Bahrain) and the United Arab Emirates (UAE). In June 2026, EOG commenced crude oil production in the UAE. EOG expects to advance both programs during the remainder of 2026. 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. 24 2026 Capital and Operating Plan. Total 2026 capital expenditures are estimated to range from approximately $6.3 billion to $6.7 billion, including exploration and development drilling, facilities, leasehold acquisitions, capitalized interest, dry hole costs and other property, plant and equipment and excluding property acquisitions, asset retirement costs, non-cash exchanges and transactions and exploration costs incurred as operating expenses. EOG plans to continue to focus a substantial portion of its exploration and development expenditures in its major producing areas in the United States. In particular, EOG will be focused on United States drilling activity in its plays where it generates the highest rates of return - specifically, in the Delaware Basin, the Utica and the Eagle Ford play. To further enhance the economics of these plays, EOG expects to continue to improve well performance and to focus on improving operating efficiencies; see the above related discussion. Relative to 2025, full-year oil production for 2026 is expected to increase by approximately 5% and full-year total crude oil and condensate, NGLs and natural gas production for 2026 is expected to increase by approximately 14%. In addition, EOG plans to continue to spend a portion of its anticipated 2026 capital expenditures on leasing acreage and evaluating new prospects. Management continues to believe 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. Capital Structure. One of management's key strategies is to maintain a strong balance sheet. EOG's debt-to-total capitalization ratio was 20% at June 30, 2026 and 21% at December 31, 2025. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity. 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 issuances of additional equity and/or debt securities. For related discussion, see ITEM 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity included in EOG's 2025 Annual Report. 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% 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 in EOG's 2025 Annual Report and Part II, Item 2, Unregistered Sales of Equity Securities and Use of Proceeds in this Quarterly Report on Form 10-Q. Dividend Declarations. On February 24, 2026, the Board of Directors (Board) declared a quarterly cash dividend on the common stock of $1.02 per share paid on April 30, 2026, to stockholders of record as of April 16, 2026. On May 5, 2026, the Board declared a quarterly cash dividend on the common stock of $1.02 per share paid on July 31, 2026, to stockholders of record as of July 17, 2026. On August 4, 2026, the Board declared a quarterly cash dividend on the common stock of $1.02 per share to be paid on October 30, 2026, to stockholders of record as of October 16, 2026. Share Repurchases. In November 2021, the Board established a new share repurchase authorization allowing for the repurchase by EOG of up to $5 billion of its common stock and, in November 2024, increased such share repurchase authorization from $5 billion to $10 billion. Effective May 20, 2026, the Board again increased such share repurchase authorization, from $10 billion to $20 billion (Share Repurchase Authorization). For additional information regarding the Share Repurchase Authorization, see Part II, Item 2, Unregistered Sales of Equity Securities and Use of Proceeds in this Quarterly Report on Form 10-Q. 25 Results of Operations The following review of operations for the three months and six months ended June 30, 2026 and 2025 should be read in conjunction with the Condensed Consolidated Financial Statements of EOG and notes thereto included in this Quarterly Report on Form 10‑Q. Three Months Ended June 30, 2026 vs. Three Months Ended June 30, 2025 Operating Revenues and Other. During the second quarter of 2026, total operating revenues increased $3,142 million, or 57%, to $8,620 million from $5,478 million for the same period of 2025. Total revenues from sales of EOG's production of crude oil and condensate, NGLs and natural gas for the second quarter of 2026 increased $2,375 million, or 58%, to $6,483 million from $4,108 million for the same period of 2025. EOG recognized net gains on the mark-to-market of financial commodity and other derivative contracts of $40 million for the second quarter of 2026 compared to net gains of $107 million for the same period of 2025. Gathering, processing and marketing revenues for the second quarter of 2026 increased $764 million, or 61%, to $2,011 million from $1,247 million for the same period of 2025. 26 Volume and price statistics for the three-month periods ended June 30, 2026 and 2025 were as follows (see Note 8 for segment financial information): Three Months Ended June 30, 2026 2025 Crude Oil and Condensate Volumes (MBbld) (1) United States 546.2 503.1 Trinidad 2.1 1.1 Other International (2) 0.5 — Total 548.8 504.2 Average Crude Oil and Condensate Prices ($/Bbl) (3) United States $ 98.18 $ 64.84 Trinidad 88.87 54.50 Other International 103.40 — Composite 98.15 64.82 Natural Gas Liquids Volumes (MBbld) (1) United States 346.8 258.4 Total 346.8 258.4 Average Natural Gas Liquids Prices ($/Bbl) (3) United States $ 24.41 $ 22.70 Natural Gas Volumes (MMcfd) (1) United States 2,784 1,977 Trinidad 293 252 Other International (2) 12 — Total 3,089 2,229 Average Natural Gas Prices ($/Mcf) (3) United States $ 2.77 $ 2.87 Trinidad 3.99 3.65 Other International (2) 3.27 — Composite 2.89 2.96 Crude Oil Equivalent Volumes (MBoed) (4) United States 1,357.1 1,090.9 Trinidad 50.9 43.2 Other International 2.4 — Total 1,410.4 1,134.1 Total MMBoe (4) 128.3 103.2 (1)Thousand barrels per day or million cubic feet per day, as applicable. (2)Crude oil and condensate volumes are from UAE and Bahrain operations. Natural gas volumes are from Bahrain operations; natural gas realized price represents contract price less partner's processing and distribution costs. (3)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). (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 for the second quarter of 2026 increased $1,927 million, or 65%, to $4,901 million from $2,974 million for the same period of 2025, due to a higher composite average price ($1,667 million) and an increase of 44.6 MBbld, or 9%, in crude oil and condensate deliveries ($260 million). Increased production was primarily from the Utica. EOG's composite crude oil and condensate price for the second quarter of 2026 increased 51% to $98.15 per barrel compared to $64.82 per barrel for the same period of 2025. 27 NGL revenues for the second quarter of 2026 increased $236 million, or 44%, to $770 million from $534 million for the same period of 2025 due to an increase of 88.4 MBbld, or 34%, in NGL deliveries ($182 million) and a higher composite average price ($54 million). Increased production was primarily from the Utica and Permian Basin. EOG's composite NGL price for the second quarter of 2026 increased 8% to $24.41 per barrel compared to $22.70 per barrel for the same period of 2025. Natural gas revenues for the second quarter of 2026 increased $212 million, or 35%, to $812 million from $600 million for the same period of 2025, due to an increase of 860 MMcfd, or 39%, in natural gas deliveries ($232 million), partially offset by a lower composite average price ($20 million). Increased deliveries were primarily from the Utica and Permian Basin. EOG's composite natural gas price for the second quarter of 2026 decreased 2% to $2.89 per Mcf compared to $2.96 per Mcf for the same period of 2025. During the second quarter of 2026, EOG recognized net gains on the mark-to-market of financial commodity and other derivative contracts of $40 million compared to net gains of $107 million for the same period of 2025. The net gains of $40 million included gains of $11 million related to the Brent crude oil (Brent) linked gas sales contract. During the second quarter of 2026, net cash received from settlements of financial commodity derivative contracts was $45 million compared to net cash paid for settlements of financial commodity derivative contracts of $24 million for the same period of 2025. Gathering, processing and marketing revenues are revenues generated from sales of third-party crude oil and condensate, NGLs and natural gas, as well as fees associated with gathering third-party natural gas and revenues from sales of EOG-owned sand. Purchases and sales of third-party crude oil and condensate and natural gas may be utilized in order to balance firm capacity at third-party facilities with production in certain areas and to utilize excess capacity at EOG-owned facilities. Marketing costs represent the costs to purchase third-party crude oil and condensate, natural gas and sand and the associated transportation costs, as well as costs associated with EOG-owned sand sold to third parties. Gathering, processing and marketing revenues less marketing costs for the second quarter of 2026 increased $30 million as compared to the same period of 2025 primarily due to higher margins on crude oil and condensate marketing activities. Operating and Other Expenses. For the second quarter of 2026, operating expenses of $5,092 million were $1,361 million higher than the $3,731 million incurred during the second quarter of 2025. The following table presents the costs per barrel of oil equivalent (Boe) for the three-month periods ended June 30, 2026 and 2025: Three Months Ended June 30, 2026 2025 Lease and Well $ 3.64 $ 3.84 Gathering, Processing and Transportation Costs (GP&T) 5.27 4.41 Depreciation, Depletion and Amortization (DD&A) - Oil and Gas Properties 9.27 9.58 Other Property, Plant and Equipment 0.54 0.62 General and Administrative (G&A) 1.66 1.80 Interest Expense, Net 0.52 0.49 Total (1) $ 20.90 $ 20.74 (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 the three months ended June 30, 2026, compared to the same period of 2025, are set forth below. See "Operating Revenues and Other" above for a discussion of volumes. 28 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 $467 million for the second quarter of 2026 increased $71 million from $396 million for the same prior year period primarily due to increased operating and maintenance costs in the United States ($50 million) and increased lease and well administrative expenses in the United States ($18 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 $676 million for the second quarter of 2026 increased $221 million from $455 million for the same prior year period primarily due to increased GP&T costs related to increased production in the Utica ($219 million) and Permian Basin ($9 million), partially offset by decreased costs in the Eagle Ford ($7 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 second quarter of 2026 increased $206 million to $1,259 million from $1,053 million for the same prior year period. DD&A expenses associated with oil and gas properties for the second quarter of 2026 were $201 million higher than the same prior year period. The increase primarily reflects increased production in the United States ($229 million) and Trinidad ($6 million), and increased unit rates in Trinidad ($9 million), partially offset by decreased unit rates in the United States ($47 million). DD&A expenses associated with other property, plant and equipment for the second quarter of 2026 were $5 million higher than the same prior year period primarily related to GP&T assets and equipment. G&A expenses of $213 million for the second quarter of 2026 increased $27 million from $186 million for the same prior year period primarily due to increased employee-related costs ($23 million) and legal expenses ($12 million), partially offset by decreased professional services costs primarily related to the Encino acquisition ($11 million). Interest expense, net of $67 million for the second quarter of 2026 increased $16 million compared to the same prior year period primarily due to the issuance in July 2025 of the $1,250 million aggregate principal amount of 5.350% Senior Notes due 2036 ($17 million), $1,250 million aggregate principal amount of 5.000% Senior Notes due 2032 ($16 million), $500 million aggregate principal amount of 5.950% Senior Notes due 2055 ($7 million) and $500 million aggregate principal amount of 4.400% Senior Notes due 2028 ($6 million), and the issuance in November 2025 of the $750 million aggregate principal amount of 4.400% Senior Notes due 2031 ($9 million) and $250 million aggregate principal amount of 5.950% Senior Notes due 2055 ($4 million), partially offset by increased capitalized interest ($27 million), the repayment in December 2025 of the $750 million aggregate principal amount of 4.15% Senior Notes due 2026 ($8 million), and the absence of financing commitment costs related to the Encino acquisition ($6.5 million). 29 Exploration costs of $47 million for the second quarter of 2026 decreased $27 million from $74 million for the same prior year period primarily due to decreased geological and geophysical expenditures in Other International ($22 million) and the United States ($7 million), partially offset by increased administrative expenses ($6 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 second quarter of 2026 and 2025 (in millions): Three Months Ended June 30, 2026 2025 Proved properties $ — $ 12 Unproved properties 19 12 Other assets — 14 Firm commitment contracts — 1 Total $ 19 $ 39 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 wellhead revenues, and ad valorem/property taxes are generally determined based on the valuation of the underlying assets. Taxes other than income for the second quarter of 2026 increased $130 million to $431 million (6.6% of revenues from sales of crude oil and condensate, NGLs and natural gas) from $301 million (7.3% of revenues from sales of crude oil and condensate, NGLs and natural gas) for the same prior year period. The increase in taxes other than income was primarily due to increased severance/production taxes ($111 million) and increased ad valorem/property taxes ($10 million), all in the United States. Other income, net of $38 million for the second quarter of 2026 decreased $17 million from $55 million for the same prior year period. The decrease was primarily due to decreased interest income. Income taxes of $775 million for the second quarter of 2026 increased from income taxes of $406 million for the second quarter of 2025 primarily due to increased pretax income. The net effective tax rate for the second quarter of 2026 decreased to 22% from 23% for the second quarter of 2025. Six Months Ended June 30, 2026 vs. Six Months Ended June 30, 2025 Operating Revenues and Other. During the first six months of 2026, total operating revenues increased $4,394 million, or 39%, to $15,541 million from $11,147 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 six months of 2026 increased $3,135 million, or 36%, to $11,745 million from $8,610 million for the same period of 2025. During the first six months of 2026, EOG recognized net gains on the mark-to-market of financial commodity and other derivative contracts of $153 million compared to net losses of $84 million for the same period of 2025. Gathering, processing and marketing revenues for the first six months of 2026 increased $920 million, or 36%, to $3,507 million from $2,587 million for the same period of 2025. EOG recognized net gains on asset dispositions of $89 million for the first six months of 2026 compared to net losses on asset dispositions of $1 million for the same period of 2025. 30 Volume and price statistics for the six-month periods ended June 30, 2026 and 2025 were as follows (see Note 8 for segment financial information): Six Months Ended June 30, 2026 2025 Crude Oil and Condensate Volumes (MBbld) United States 546.3 502.0 Trinidad 2.0 1.1 Other International (1) 0.3 — Total 548.6 503.1 Average Crude Oil and Condensate Prices ($/Bbl) (2) United States $ 85.40 $ 68.84 Trinidad 79.20 57.84 Other International 101.81 — Composite 85.38 68.81 Natural Gas Liquids Volumes (MBbld) United States 339.5 250.1 Total 339.5 250.1 Average Natural Gas Liquids Prices ($/Bbl) (2) United States $ 23.34 $ 24.42 Natural Gas Volumes (MMcfd) United States 2,777 1,906 Trinidad 266 249 Other International (1) 12 — Total 3,055 2,155 Average Natural Gas Prices ($/Mcf) (2) United States $ 3.25 $ 3.10 Trinidad 3.95 3.71 Other International (1) 3.27 — Composite 3.32 3.17 Crude Oil Equivalent Volumes (MBoed) United States 1,348.6 1,069.7 Trinidad 46.4 42.7 Other International 2.2 — Total 1,397.2 1,112.4 Total MMBoe 252.9 201.3 (1)Crude oil and condensate volumes are from UAE and Bahrain operations. Natural gas volumes are from Bahrain operations; natural gas realized price represents contract price less partner's processing and distribution costs. (2)Excludes the impact of financial commodity and other derivative instruments (see Note 9 to the Condensed Consolidated Financial Statements). Crude oil and condensate revenues for the first six months of 2026 increased $2,211 million, or 35%, to $8,478 million from $6,267 million for the same period of 2025 due to a higher composite average price ($1,646 million) and an increase of 45.5 MBbld, or 9%, in crude oil and condensate production ($565 million). Increased production was primarily in the Utica. EOG's composite crude oil and condensate price for the first six months of 2026 increased 24% to $85.38 per barrel compared to $68.81 per barrel for the same period of 2025. 31 NGL revenues for the first six months of 2026 increased $328 million, or 30%, to $1,434 million from $1,106 million for the same period of 2025 due to an increase of 89.4 MBbld, or 36%, in NGL deliveries ($394 million), partially offset by a lower composite average price ($66 million). Increased production was primarily from the Utica and Permian Basin. EOG's composite NGL price for the first six months of 2026 decreased 4% to $23.34 per barrel compared to $24.42 per barrel for the same period of 2025. Natural gas revenues for the first six months of 2026 increased $596 million, or 48%, to $1,833 million from $1,237 million for the same period of 2025. The increase was due to an increase in natural gas deliveries ($514 million) and a higher composite average price ($82 million). Natural gas deliveries for the first six months of 2026 increased 900 MMcfd, or 42%, compared to the same period of 2025. Increased deliveries were primarily from the Utica and Permian Basin. EOG's composite natural gas price for the first six months of 2026 increased 5% to $3.32 per Mcf compared to $3.17 per Mcf for the same period of 2025. During the first six months of 2026, EOG recognized net gains on the mark-to-market of financial commodity and other derivative contracts of $153 million compared to net losses of $84 million for the same period of 2025. The net gains of $153 million included gains of $130 million related to the Brent linked gas sales contract. During the first six months of 2026, net cash payments for settlements of financial commodity derivative contracts was $8 million. Net cash payments for settlements of financial commodity derivative contracts was $62 million for the same period of 2025. Gathering, processing and marketing revenues less marketing costs for the first six months of 2026 increased $127 million as compared to the same period of 2025 primarily due to higher margins on crude oil and condensate marketing activities. Operating and Other Expenses. For the first six months of 2026, operating expenses of $9,415 million were $1,874 million higher than the $7,541 million incurred during the same period of 2025. The following table presents the costs per Boe for the six-month periods ended June 30, 2026 and 2025: Six Months Ended June 30, 2026 2025 Lease and Well $ 3.67 $ 3.96 GP&T 5.26 4.45 DD&A - Oil and Gas Properties 9.15 9.65 Other Property, Plant and Equipment 0.55 0.61 G&A 1.57 1.77 Interest Expense, Net 0.53 0.49 Total (1) $ 20.73 $ 20.93 (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 the six months ended June 30, 2026, compared to the same period of 2025 are set forth below. See "Operating Revenues and Other" above for a discussion of volumes. Lease and well expenses of $929 million for the first six months of 2026 increased $132 million from $797 million for the same prior year period primarily due to increased operating and maintenance costs in the United States ($93 million) and increased lease and well administrative expenses ($38 million). GP&T costs of $1,330 million for the first six months of 2026 increased $435 million from $895 million for the same prior year period primarily due to increased GP&T costs related to increased production in the Utica ($440 million) and Permian Basin ($20 million), partially offset by a decrease in costs in the Eagle Ford ($22 million). 32 DD&A expenses for the first six months of 2026 increased $386 million to $2,452 million from $2,066 million for the same prior year period. DD&A expenses associated with oil and gas properties for the first six months of 2026 were $373 million higher than the same prior year period. The increase primarily reflects increased production in the United States ($478 million) and Trinidad ($7 million), partially offset by decreased unit rates in the United States ($115 million). DD&A expenses associated with other property, plant and equipment for the first six months of 2026 were $13 million higher than the same prior year period primarily due to an increase in expenses related to GP&T assets and equipment. G&A expenses of $398 million for the first six months of 2026 increased $41 million from $357 million for the same prior year period primarily due to increased employee-related costs ($34 million), legal expenses ($13 million) and information systems ($7 million), partially offset by a decrease in professional services costs primarily related to the Encino acquisition ($15 million). Interest expense, net of $133 million for the first six months of 2026 increased $35 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 ($34 million), $1,250 million aggregate principal amount of 5.000% Senior Notes due 2032 ($32 million), $500 million aggregate principal amount of 5.950% Senior Notes due 2055 ($15 million) and $500 million aggregate principal amount of 4.400% Senior Notes due 2028 ($12 million), and the issuance in November 2025 of the $750 million aggregate principal amount of 4.400% Senior Notes due 2031 ($17 million) and $250 million aggregate principal amount of 5.950% Senior Notes due 2055 ($7 million), partially offset by increased capitalized interest ($52 million), the repayment in December 2025 of the $750 million aggregate principal amount of 4.15% Senior Notes due 2026 ($16 million), the absence of financing commitment costs related to the Encino acquisition ($6.5 million), and the maturity in April 2025 of the $500 million aggregate principal amount of 3.15% Senior Notes due 2025 ($4 million). Exploration costs of $92 million for the first six months of 2026 decreased $23 million from $115 million for the same prior year period primarily due to decreased geological and geophysical expenditures in Other International ($18 million) and the United States ($11 million), partially offset by increased administrative expenses ($8 million). The following table sets forth impairments for the six-month periods ended June 30, 2026 and 2025 (in millions): Six Months Ended June 30, 2026 2025 Proved properties $ — $ 44 Unproved properties 38 24 Other assets — 14 Inventories 20 — Firm commitment contracts — 1 Total $ 58 $ 83 Taxes other than income for the first six months of 2026 increased $127 million to $769 million (6.5% of revenues from sales of crude oil and condensate, NGLs and natural gas) from $642 million (7.5% of revenues from sales of crude oil and condensate, NGLs and natural gas) for the same prior year period. The increase in taxes other than income was primarily due to increased severance/production taxes ($102 million) and increased ad valorem/property taxes ($12 million), all in the United States. Other income, net of $61 million for the first six months of 2026 decreased $59 million from $120 million for the same prior year period. The decrease was primarily due to decreased interest income. Income taxes of $1,350 million for the first six months of 2026 increased from income taxes of $820 million for the first six months of 2025 primarily due to increased pretax income. The net effective tax rate for the first six months of 2026 decreased to 22% from 23% for the first six months of 2025. 33 Capital Resources and Liquidity Liquidity Overview. At June 30, 2026, EOG maintained a strong financial and liquidity position, including $4.9 billion of cash and cash equivalents on hand and $3.0 billion of availability under its senior unsecured revolving credit facility (which remained undrawn). The primary source of cash for EOG during the six months ended June 30, 2026, was funds generated from operations. The primary uses of cash were funds used in operations; exploration and development expenditures; dividend payments to stockholders; and share repurchases and other purchases of treasury stock. During the first six months of 2026, EOG's cash balance increased $1,511 million to $4,907 million from $3,396 million at December 31, 2025. See Notes 2 and 10 to the Condensed 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 $7,635 million for the first six months of 2026 increased $3,314 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 ($3,135 million), a decrease in net cash paid related to income taxes ($827 million), an increase in gathering, processing and marketing revenues less marketing costs ($127 million) and a decrease in net cash used in working capital and other assets and liabilities ($114 million), partially offset by an increase in cash operating expenses ($697 million). Net cash used in investing activities of $3,326 million for the first six months of 2026 increased $115 million compared to the same period of 2025 primarily due to an increase in additions to other property, plant and equipment ($101 million), an increase in cash used in working capital associated with investing activities ($100 million) and an increase in additions to oil and gas properties ($49 million), partially offset by an increase in proceeds from sales of assets ($135 million). Net cash used in financing activities of $2,798 million for the first six months of 2026 included share repurchases and other purchases of treasury stock ($1,717 million) and dividend payments to stockholders ($1,084 million). Net cash used in financing activities of $2,987 million for the first six months of 2025 included share repurchases and other purchases of treasury stock ($1,408 million), dividend payments to stockholders ($1,066 million) and repayments of long-term debt ($500 million). 34 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 six-month periods ended June 30, 2026 and 2025 (in millions): Six Months Ended June 30, 2026 2025 Expenditure Category Capital Exploration and Development Drilling $ 2,461 $ 2,366 Facilities 251 305 Leasehold Acquisitions (1) 191 83 Property Acquisitions (2) 218 269 Capitalized Interest 75 23 Subtotal 3,196 3,046 Exploration Costs 92 115 Dry Hole Costs 53 45 Exploration and Development Expenditures 3,341 3,206 Asset Retirement Costs (3) 49 27 Total Exploration And Development Expenditures 3,390 3,233 Other Property, Plant and Equipment 297 196 Total Expenditures $ 3,687 $ 3,429 (1)Leasehold acquisitions included $105 million and $11 million for the six-month periods ended June 30, 2026 and 2025, respectively, related to non-cash property exchanges. (2)Property acquisitions for the six-month period ended June 30, 2026, included $13 million related to revisions to the Encino purchase price allocation and $2 million related to non-cash property exchange. (3)Asset retirement costs for the six-month period ended June 30, 2026, included $15 million related to revisions to the Encino purchase price allocation. Exploration and development expenditures of $3,341 million for the first six months of 2026 were $135 million higher than the same period of 2025 primarily due to increased exploration drilling expenditures ($120 million), increased leasehold acquisitions ($108 million), increased capitalized interest ($52 million) and increased dry hole costs ($8 million), partially offset by decreased facility expenditures ($54 million), decreased property acquisitions ($51 million), decreased development drilling expenditures ($25 million) and decreased exploration costs ($23 million). Exploration and development expenditures for the first six months of 2026 of $3,341 million consisted of $2,601 million in development drilling and facilities, $447 million in exploration, $218 million in property acquisitions and $75 million in capitalized interest. Exploration and development expenditures for the first six months of 2025 of $3,206 million consisted of $2,680 million in development drilling and facilities, $269 million in property acquisitions, $234 million in exploration and $23 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. 35 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 and condensate, 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 June 30, 2026, as a net asset of $210 million. As discussed in "Operating Revenues and Other" above, the net cash received from settlements of financial commodity derivative contracts during the second quarter of 2026 was $45 million and the net cash paid for settlements of financial commodity derivative contracts during the first six months of 2026 was $8 million. Presented below is a comprehensive summary of EOG's financial commodity derivative contracts settled during the period from January 1, 2026 to July 24, 2026 (closed) and outstanding as of July 24, 2026. Natural gas volumes are presented in MMBtu per day (MMBtud) and prices are presented in dollars per MMBtu ($/MMBtu). NGL volumes are presented in MBbld and prices are presented in $/Bbl. Natural Gas Financial Price Swap Contracts Contracts Sold Period Settlement Index Volume (MMBtud in thousands) Weighted Average Price ($/MMBtu) January - June 2026 (closed) NYMEX Henry Hub 460 $ 3.78 July 2026 (closed) NYMEX Henry Hub 450 3.79 August - December 2026 NYMEX Henry Hub 450 3.79 Natural Gas Collar Contracts Contracts Sold Weighted Average Price ($/MMBtu) Period Settlement Index Volume (MMBtud in thousands) Ceiling Price Floor Price January - June 2026 (closed) NYMEX Henry Hub 80 $ 4.28 $ 3.72 July 2026 (closed) NYMEX Henry Hub 70 4.23 3.71 August - December 2026 NYMEX Henry Hub 70 4.23 3.71 January - December 2027 NYMEX Henry Hub 120 4.41 3.42 36 Ethane Financial Price Swap Contracts Contracts Sold Period Settlement Index Volume (MBbld) Weighted Average Price ($/Bbl) January - June 2026 (closed) Mont Belvieu Ethane (non-Tet) 11 $ 10.94 July - December 2026 Mont Belvieu Ethane (non-Tet) 11 10.94 Propane Financial Price Swap Contracts Contracts Sold Period Settlement Index Volume (MBbld) Weighted Average Price ($/Bbl) January - June 2026 (closed) Mont Belvieu Propane (Tet) 1 $ 30.24 July - December 2026 Mont Belvieu Propane (Tet) 1 30.24 In connection with its financial commodity derivative contracts, EOG had no collateral posted and no collateral held at July 24, 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. As more fully discussed in Note 12 to the Consolidated Financial Statements included in EOG's 2025 Annual Report, 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 at the counterparty's election. 37 Information Regarding Forward-Looking Statements This Quarterly Report on Form 10-Q 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; 38 •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 uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage; and •the other factors described under ITEM 1A, Risk Factors of EOG's Annual Report on Form 10-K for the year ended December 31, 2025 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. 39 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. 40 PART I. FINANCIAL INFORMATION