EOG Resources, Inc. press release

EOG Resources Reports Third Quarter 2025 Results

2025-11-06

NYSE - New York Stock Exchange · Oil · Natural Gas · Natural Gas Liquids · United States · Corporate Finance

PR Newswire

HOUSTON, Nov. 6, 2025/PRNewswire/ -- EOG Resources, Inc. (EOG) today reported third quarter 2025 results. The attached supplemental financial tables and schedules for the reconciliation of non–GAAP measures to GAAP measures and related definitions and discussion, along with a related presentation, are also available on EOG's website at http://investors.eogresources.com/investors.

| Key Financial Results

In millions of USD, except per–share, per–Boe and ratio data | | | | | | | | | | | | GAAP | 3Q 2025 | | 2Q 2025 | | 1Q 2025 | | 4Q 2024 | | 3Q 2024 | | | Total Revenue | 5,847 | | 5,478 | | 5,669 | | 5,585 | | 5,965 | | | Net Income | 1,471 | | 1,345 | | 1,463 | | 1,251 | | 1,673 | | | Net Income Per Share | 2.70 | | 2.46 | | 2.65 | | 2.23 | | 2.95 | | | Net Cash Provided by Operating Activities | 3,111 | | 2,032 | | 2,289 | | 2,763 | | 3,588 | | | Total Expenditures | 8,544 | | 1,883 | | 1,546 | | 1,446 | | 1,573 | | | Current and Long–Term Debt | 7,694 | | 4,236 | | 4,744 | | 4,752 | | 3,776 | | | Cash and Cash Equivalents | 3,530 | | 5,216 | | 6,599 | | 7,092 | | 6,122 | | | Debt–to–Total Capitalization | 20.3 % | | 12.7 % | | 13.8 % | | 13.9 % | | 11.3 % | | | Cash Operating Costs ($/Boe) | 10.50 | | 10.05 | | 10.31 | | 10.15 | | 10.15 | | | | | | | | | | | | | | | Non–GAAP | | | | | | | | | | | | Adjusted Net Income | 1,472 | | 1,268 | | 1,586 | | 1,535 | | 1,644 | | | Adjusted Net Income Per Share | 2.71 | | 2.32 | | 2.87 | | 2.74 | | 2.89 | | | Adjusted CFO1 | 3,031 | | 2,496 | | 2,813 | | 2,635 | | 2,988 | | | Capital Expenditures | 1,648 | | 1,523 | | 1,484 | | 1,358 | | 1,497 | | | Free Cash Flow | 1,383 | | 973 | | 1,329 | | 1,277 | | 1,491 | | | Net Debt | 4,164 | | (980) | | (1,855) | | (2,340) | | (2,346) | | | Net Debt–to–Total Capitalization | 12.1 % | | (3.5 %) | | (6.7 %) | | (8.7 %) | | (8.6 %) | | | Cash Operating Costs ($/Boe) 2,3 | 9.93 | | 9.94 | | 10.31 | | 10.15 | | 10.05 | |

Third Quarter Highlights

Earned adjusted net income of $1.5 billion, or $2.71per share Generated $1.4 billionof free cash flow Paid $545 millionin regular dividends and repurchased $440 millionof shares Oil, NGLs and natural gas production above guidance midpoints Capital expenditures and per–unit operating costs better than guidance midpoints Closed on the acquisition of Encino Acquisition Partners (Encino)

Third Quarter 2025 Highlights and Cash Return

Volumes and Capital Expenditures

| Volumes | 3Q 2025 | | 3Q 2025 Guidance Midpoint | | 2Q 2025 | | 1Q 2025 | | 4Q 2024 | | 3Q 2024 | | Crude Oil and Condensate (MBod) | 534.5 | | 532.4 | | 504.2 | | 502.1 | | 494.6 | | 493.0 | | Natural Gas Liquids (MBbld) | 309.3 | | 305.0 | | 258.4 | | 241.7 | | 252.5 | | 254.3 | | Natural Gas (MMcfd) | 2,745 | | 2,735 | | 2,229 | | 2,080 | | 2,092 | | 1,970 | | Total Crude Oil Equivalent (MBoed) | 1,301.2 | | 1,293.3 | | 1,134.1 | | 1,090.4 | | 1,095.7 | | 1,075.7 | | | | | | | | | | | | | | | Capital Expenditures ($MM) | 1,648 | | 1,650 | | 1,523 | | 1,484 | | 1,358 | | 1,497 |

From Ezra Yacob, Chairman and Chief Executive Officer "EOG delivered another quarter of strong operational performance. Third quarter oil, gas, and NGL volumes exceeded the midpoints of our guidance. Higher volumes, combined with lower–than–expected per–unit cash operating costs and DD&A, helped drive outstanding financial results.

We generated substantial free cash flow of $1.4 billion, which helped support nearly $1.0 billionof cash return to shareholders, including $440 millionof opportunistic share repurchases. As of quarter–end, we have committed to return 89% of our estimated annual free cash flow to shareholders, with the potential to return additional cash over the balance of the year.

Our ability to deliver operational excellence quarter after quarter is the result of EOG's unique culture and the quality of our multi–basin portfolio. EOG's foundational assets, the DelawareBasin, Eagle Ford, and Utica, are delivering strong returns, exceeding our expectations. In the Utica, the integration of the Encinoassets is proceeding exceptionally well, with continued incremental efficiency gains. Our emerging and international assets are also performing well, with strong well results in Dorado, the Powder River Basin, and Trinidad, along with continued progress in our exploration prospects in Bahrainand the UAE.

Our business has never been stronger. Our pristine balance sheet provides unmatched flexibility to continue to improve our high–return, long–duration asset base while delivering significant cash returns through commodity price cycles. EOG has never been better positioned to create long–term value for our shareholders."

Regular Dividend and Third Quarter Share Repurchases The Board of Directors today declared a dividend of $1.02per share on EOG's common stock. The dividend will be payable January 30, 2026, to shareholders of record as of January 16, 2026. This dividend represents an indicated annual rate of $4.08per share. EOG has never suspended or reduced its regular dividend.

During the third quarter, the company repurchased 3.8 million shares for $440 millionunder its share repurchase authorization. EOG has $4.0 billionremaining on its current share buyback authorization.

Third Quarter 2025 Financial Performance

Prices

NGL and natural gas prices decreased in 3Q compared with 2Q, partially offset by higher crude oil & condensate prices

Volumes

Oil production of 534.5 MBod was above the midpoint of the guidance range NGL production of 309.3 MBbld was above the midpoint of the guidance range Natural gas production of 2,745 MMcfd was above the midpoint of the guidance range Total company equivalent production of 1,301.2 MBoed was above the midpoint of the guidance range

Per–Unit Costs

LOE, non–GAAP G&A and DD&A costs decreased in 3Q compared to 2Q, while GP&T costs increased. Encinoacquisition–related costs increased GAAP G&A costs in 3Q compared to 2Q

Hedges

Mark–to–market hedge gains increased GAAP earnings per share in 3Q compared with 2Q Cash received to settle hedges increased adjusted non–GAAP earnings per share in 3Q compared with 2Q

Free Cash Flow

Adjusted cash flow from operations was $3.0 billion Incurred $1.6 billionof capital expenditures Generated $1.4 billionof free cash flow

Cash Return and Working Capital

Paid $545 millionin regular dividends Repurchased $440 millionof stock Closed on the acquisition of Encino for $5.7 billion, subject to post–closing adjustments Issued $3.5 billionof senior notes in conjunction with the Encino acquisition

Third Quarter 2025 Operating Performance

Lease and Well

QoQ: Decreased primarily due to the impact of higher production, primarily in the Utica from the integration of Encinooperations, and lower workover expenses Guidance Midpoint: Lower primarily due to lower workover expenses and operating and maintenance costs

General and Administrative (Non–GAAP)

QoQ: Decreased primarily due to the impact of higher production, primarily in the Utica from the integration of Encinooperations, and lower employee–related expenses Guidance Midpoint: Lower primarily due to lower employee–related expenses

Gathering, Processing and Transportation Costs

QoQ: Increased primarily due to the impact of higher Utica production from the integration of Encinooperations Guidance Midpoint: Lower primarily due to lower natural gas gathering and processing fees

Depreciation, Depletion and Amortization

QoQ: Decreased primarily due to the impact of higher Utica production and well mix Guidance Midpoint: Lower primarily due to the addition of lower–cost reserves

| Third Quarter 2025 Results vs Guidance | | | | | | | | | | | | | | | | (Unaudited) | | | | | | | | | | | | | | | | See "Endnotes" below for related discussion and definitions. | | | 3Q 2025 | | | | | | | | | | | | | | 3Q 2025 | | Guidance

Midpoint6 | | Variance | | 2Q 2025 | | 1Q 2025 | | 4Q 2024 | | 3Q 2024 | | | Crude Oil and Condensate Volumes (MBod) | | | | | | | | | | | | | | | | United States | 532.9 | | 531.0 | | 1.9 | | 503.1 | | 500.9 | | 493.5 | | 491.8 | | | Trinidad | 1.6 | | 1.4 | | 0.2 | | 1.1 | | 1.2 | | 1.1 | | 1.2 | | | Total | 534.5 | | 532.4 | | 2.1 | | 504.2 | | 502.1 | | 494.6 | | 493.0 | | | Natural Gas Liquids Volumes (MBbld) | | | | | | | | | | | | | | | | Total | 309.3 | | 305.0 | | 4.3 | | 258.4 | | 241.7 | | 252.5 | | 254.3 | | | Natural Gas Volumes (MMcfd) | | | | | | | | | | | | | | | | United States | 2,511 | | 2,525 | | (14) | | 1,977 | | 1,834 | | 1,840 | | 1,745 | | | Trinidad | 230 | | 210 | | 20 | | 252 | | 246 | | 252 | | 225 | | | Other International7 | 4 | | 0 | | 4 | | 0 | | 0 | | 0 | | 0 | | | Total | 2,745 | | 2,735 | | 10 | | 2,229 | | 2,080 | | 2,092 | | 1,970 | | | | | | | | | | | | | | | | | | | Total Crude Oil Equivalent Volumes (MBoed) | 1,301.2 | | 1,293.3 | | 7.9 | | 1,134.1 | | 1,090.4 | | 1,095.7 | | 1,075.7 | | | Total MMBoe | 119.7 | | 119.0 | | 0.7 | | 103.2 | | 98.1 | | 100.8 | | 99.0 | | | | | | | | | | | | | | | | | | | Benchmark Price | | | | | | | | | | | | | | | | Oil (WTI) ($/Bbl) | 64.95 | | | | | | 63.71 | | 71.42 | | 70.28 | | 75.16 | | | Natural Gas (HH) ($/Mcf) | 3.07 | | | | | | 3.44 | | 3.66 | | 2.79 | | 2.16 | | | | | | | | | | | | | | | | | | | Crude Oil and Condensate – above (below) WTI8($/Bbl) | | | | | | | | | | | | | | | | United States | 1.02 | | 0.80 | | 0.22 | | 1.13 | | 1.48 | | 1.40 | | 1.79 | | | Trinidad | (7.21) | | (5.00) | | (2.21) | | (9.21) | | (10.30) | | (9.81) | | (12.01) | | | Natural Gas Liquids – Realizations as % of WTI | | | | | | | | | | | | | | | | Total | 32.7 % | | 34.0 % | | (1.3 %) | | 35.6 % | | 36.8 % | | 33.9 % | | 29.8 % | | | Natural Gas – above (below) NYMEX Henry Hub9($/Mcf) | | | | | | | | | | | | | | | | United States | (0.36) | | (0.40) | | 0.04 | | (0.57) | | (0.30) | | (0.40) | | (0.32) | | | Natural Gas Realizations ($/Mcf) | | | | | | | | | | | | | | | | Trinidad | 3.80 | | 3.60 | | 0.20 | | 3.65 | | 3.78 | | 3.86 | | 3.68 | | | Other International7 | 3.27 | | 0.00 | | 3.27 | | 0.00 | | 0.00 | | 0.00 | | 0.00 | | | | | | | | | | | | | | | | | | | Total Expenditures (GAAP) ($MM) | 8,544 | | | | | | 1,883 | | 1,546 | | 1,446 | | 1,573 | | | Capital Expenditures (non–GAAP) ($MM) | 1,648 | | 1,650 | | (2) | | 1,523 | | 1,484 | | 1,358 | | 1,497 | | | | | | | | | | | | | | | | | | | Operating Unit Costs ($/Boe) | | | | | | | | | | | | | | | | Lease and Well | 3.60 | | 3.70 | | (0.10) | | 3.84 | | 4.09 | | 3.91 | | 3.96 | | | Gathering, Processing and Transportation Costs5 | 4.90 | | 5.10 | | (0.20) | | 4.41 | | 4.48 | | 4.37 | | 4.50 | | | General and Administrative (GAAP) | 2.00 | | 1.50 | | 0.50 | | 1.80 | | 1.74 | | 1.87 | | 1.69 | | | General and Administrative (non–GAAP)2,3 | 1.43 | | 1.50 | | (0.07) | | 1.69 | | 1.74 | | 1.87 | | 1.59 | | | Cash Operating Costs (GAAP) | 10.50 | | 10.30 | | 0.20 | | 10.05 | | 10.31 | | 10.15 | | 10.15 | | | Cash Operating Costs (non–GAAP)2,3 | 9.93 | | 10.30 | | (0.37) | | 9.94 | | 10.31 | | 10.15 | | 10.05 | | | Depreciation, Depletion and Amortization | 9.77 | | 9.85 | | (0.08) | | 10.20 | | 10.32 | | 10.11 | | 10.42 | | | | | | | | | | | | | | | | | | | Expenses ($MM) | | | | | | | | | | | | | | | | Exploration and Dry Hole | 71 | | 75 | | (4) | | 85 | | 75 | | 60 | | 43 | | | Impairment (GAAP) | 71 | | | | | | 39 | | 44 | | 276 | | 15 | | | Impairment (excluding certain impairments (non–GAAP))10 | 71 | | 70 | | 1 | | 28 | | 44 | | 23 | | 15 | | | Capitalized Interest | 27 | | 21 | | 6 | | 11 | | 12 | | 13 | | 12 | | | Net Interest (GAAP) | 71 | | 83 | | (12) | | 51 | | 47 | | 38 | | 31 | | | Net Interest (non–GAAP)11 | 71 | | 83 | | (12) | | 45 | | 47 | | 38 | | 31 | | | | | | | | | | | | | | | | | | | TOTI (% of revenues from sales of crude oil and condensate, NGLs and natural gas) | | | | | | | | | | | | | | | | (GAAP) | 6.8 % | | 7.5 % | | (0.7 %) | | 7.3 % | | 7.6 % | | 6.8 % | | 6.5 % | | | (non–GAAP)3 | 6.8 % | | 7.5 % | | (0.7 %) | | 7.3 % | | 7.6 % | | 6.8 % | | 7.2 % | | | Income Taxes | | | | | | | | | | | | | | | | Effective Rate | 19.4 % | | 20.5 % | | (1.1 %) | | 23.2 % | | 22.1 % | | 23.0 % | | 21.6 % | | | Current Tax Expense ($MM) | 75 | | 180 | | (105) | | 301 | | 370 | | 454 | | 240 | |

| Fourth Quarter and Full‐Year 2025 Guidance12 | | | | | | | | | | | | | | (Unaudited) | | | | | | | | | | | | | | _See "Endnotes" below for related discussion and definitions ._ | 4Q 2025 Guidance Range | | 4Q 2025 Midpoint | | FY 2025 Guidance Range | | FY 2025 Midpoint | | | | | | | Crude Oil and Condensate Volumes (MBod) | | | | | | | | | | | | | | United States | 541.4 | – | 546.0 | | 543.7 | | 518.7 | – | 521.9 | | 520.3 | | | Trinidad | 1.1 | – | 1.5 | | 1.3 | | 1.1 | – | 1.5 | | 1.3 | | | Total | 542.5 | – | 547.5 | | 545.0 | | 519.8 | – | 523.4 | | 521.6 | | | Natural Gas Liquids Volumes (MBbld) | | | | | | | | | | | | | | Total | 315.5 | – | 330.5 | | 323.0 | | 280.0 | – | 286.0 | | 283.0 | | | Natural Gas Volumes (MMcfd) | | | | | | | | | | | | | | United States | 2,740 | – | 2,840 | | 2,790 | | 2,250 | – | 2,310 | | 2,280 | | | Trinidad | 190 | – | 210 | | 200 | | 220 | – | 240 | | 230 | | | Total | 2,930 | – | 3,050 | | 2,990 | | 2,470 | – | 2,550 | | 2,510 | | | Crude Oil Equivalent Volumes (MBoed) | | | | | | | | | | | | | | United States | 1,313.6 | – | 1,349.8 | | 1,331.7 | | 1,173.7 | – | 1,192.9 | | 1,183.3 | | | Trinidad | 32.8 | – | 36.5 | | 34.7 | | 37.8 | – | 41.5 | | 39.7 | | | Total | 1,346.4 | – | 1,386.3 | | 1,366.4 | | 1,211.5 | – | 1,234.4 | | 1,223.0 | | | Crude Oil and Condensate – above (below) WTI8 ($/Bbl) | | | | | | | | | | | | | | United States | (0.50) | – | 1.00 | | 0.25 | | 0.35 | – | 1.35 | | 0.85 | | | Trinidad | (5.25) | – | (2.75) | | (4.00) | | (8.40) | – | (6.90) | | (7.65) | | | Natural Gas Liquids – Realizations as % of WTI | | | | | | | | | | | | | | Total | 28.0 % | – | 38.0 % | | 33.0 % | | 31.5 % | – | 36.5 % | | 34.0 % | | | Natural Gas – above (below) NYMEX Henry Hub9($/Mcf) | | | | | | | | | | | | | | United States | (0.80) | – | (0.10) | | (0.45) | | (0.95) | – | 0.05 | | (0.45) | | | Natural Gas Realizations ($/Mcf) | | | | | | | | | | | | | | Trinidad | 3.00 | – | 4.20 | | 3.60 | | 3.40 | – | 3.90 | | 3.65 | | | | | | | | | | | | | | | | | Capital Expenditures13 ($MM) | 1,600 | – | 1,700 | | 1,650 | | 6,200 | – | 6,400 | | 6,300 | | | | | | | | | | | | | | | | | Operating Unit Costs ($/Boe) | | | | | | | | | | | | | | Lease and Well | 3.50 | – | 4.00 | | 3.75 | | 3.70 | – | 3.90 | | 3.80 | | | Gathering, Processing and Transportation Costs5 | 4.75 | – | 5.25 | | 5.00 | | 4.65 | – | 4.85 | | 4.75 | | | General and Administrative | 1.40 | – | 1.70 | | 1.55 | | 1.45 | – | 1.65 | | 1.55 | | | Cash Operating Costs | 9.65 | – | 10.95 | | 10.30 | | 9.80 | – | 10.40 | | 10.10 | | | Depreciation, Depletion and Amortization | 9.25 | – | 10.25 | | 9.75 | | 9.70 | – | 10.30 | | 10.00 | | | Expenses ($MM) | | | | | | | | | | | | | | Exploration and Dry Hole | 40 | – | 80 | | 60 | | 270 | – | 310 | | 290 | | | Impairment (excluding certain impairments)10 | 30 | – | 110 | | 70 | | 180 | – | 260 | | 220 | | | Capitalized Interest | 34 | – | 38 | | 36 | | 85 | – | 89 | | 87 | | | Net Interest | 64 | – | 68 | | 66 | | 228 | – | 232 | | 230 | | | | | | | | | | | | | | | | | TOTI (% of revenues from sales of crude oil and | | | | | | | | | | | | | | condensate, NGLs and natural gas) | 6.0 % | – | 8.0 % | | 7.0 % | | 6.5 % | – | 8.5 % | | 7.5 % | | | Income Taxes | | | | | | | | | | | | | | Effective Rate | 20.0 % | – | 25.0 % | | 22.5 % | | 19.0 % | – | 24.0 % | | 21.5 % | | | Current Tax Expense ($MM) | 220 | – | 320 | | 270 | | 970 | – | 1,070 | | 1,020 | |

Third Quarter 2025 Results Webcast Friday, November 7, 2025, 9:00 a.m. Central time(10:00 a.m. Eastern time) Webcast will be available on EOG's website for one year. http://investors.eogresources.com/investors

About EOG EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United Stateswith proved reserves in the United Statesand Trinidad. To learn more visitwww.eogresources.com.

Investor Contacts Pearce Hammond713–571–4684 Neel Panchal 713–571–4884 Shelby O'Connor713–571–4560

Media Contact Kimberly Ehmer713–571–4676

| Endnotes | | | 1) | Cash flow from operations before changes in working capital and certain acquisition–related costs. | | 2) | Cash Operating Costs consist of LOE, GP&T and G&A. Excludes Encino acquisition–related G&A costs of $68 million for 3Q 2025 and $12 million for 2Q 2025, as reflected in the accompanying reconciliation schedules (see "Revenues, Costs and Margins Per Barrel of Oil Equivalent"). The per–Boe impact of such Encino acquisition–related costs on G&A and total Cash Operating Costs for 3Q 2025 was ($0.57) and for 2Q 2025 was ($0.11) as set forth in "Third Quarter 2025 Results vs Guidance" above. G&A per Boe (GAAP) for 3Q 2025 was $2.00 and for 2Q 2025 was $1.80. | | 3) | Cash Operating Costs consist of LOE, GP&T and G&A. TOTI (% of revenues from sales of crude oil and condensate, NGLs and natural gas) (non–GAAP) and G&A (non–GAAP) for 3Q 2024 exclude a state severance tax refund and related consulting fees, as reflected in the accompanying reconciliation schedules (see "Revenues, Costs and Margins Per Barrel of Oil Equivalent"). The per–Boe impact of such consulting fees on G&A and total Cash Operating Costs for 3Q 2024 was $(0.10) as set forth in "Third Quarter 2025 Results vs Guidance" above. | | 4) | Includes gathering, processing and marketing revenue, gains (losses) on asset dispositions (for GAAP earnings per share only), other revenue, exploration costs, dry hole costs, impairments, marketing costs, taxes other than income, other income (expense), interest expense, the impact of changes in the effective income tax rate and the impact of share repurchases on diluted shares. | | 5) | Effective January 1, 2024, EOG combined Transportation Costs and Gathering and Processing Costs into one line–item titled Gathering, Processing and Transportation Costs. This presentation has been conformed for all periods presented and had no impact on previously reported Net Income. | | 6) | GAAP and non–GAAP distinctions apply solely to actual results and do not pertain to EOG's third quarter 2025 guidance midpoint disclosures. | | 7) | Other International represents EOG's Kingdom of Bahrain operations. Realized price represents contract price less Bapco's processing and distribution costs. | | 8) | EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month. | | 9) | EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the NYMEX Last Day Settle price for each of the applicable months. | | 10) | In general, EOG excludes impairments which are (i) attributable to declines in commodity prices, (ii) related to sales of certain oil and gas properties or (iii) the result of certain other events or decisions (e.g., a periodic review of EOG's oil and gas properties or other assets). EOG believes excluding these impairments from total impairment costs is appropriate and provides useful information to investors, as such impairments were caused by factors outside of EOG's control (versus, for example, impairments that are due to EOG's proved oil and gas properties not being as productive as it originally estimated). | | 11) | Net interest expense (non–GAAP) excludes Encino acquisition–related financing commitment costs of $6 million in 2Q 2025. | | 12) | The forecast items for the fourth quarter and full year 2025 set forth above for EOG are based on currently available information and expectations as of the date of this press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with this press release and EOG's related Current Report on Form 8–K filing, replaces and supersedes any previously issued guidance or forecast. | | 13) | The forecast includes expenditures for Exploration and Development Drilling, Facilities, Leasehold Acquisitions, Capitalized Interest, Dry Hole Costs and Other Property, Plant and Equipment. The forecast excludes Property Acquisitions, Asset Retirement Costs, Non–Cash Exchanges and Transactions and exploration costs incurred as operating expenses. |