EOG Resources, Inc. press release

EOG Resources Reports Second Quarter 2025 Results and Updates 2025 Guidance

2025-08-07

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

PR Newswire

HOUSTON , Aug. 7, 2025 /PRNewswire/ -- EOG Resources, Inc. (EOG) today reported second quarter 2025 results and updated its 2025 guidance. 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 | 2Q 2025 | | 1Q 2025 | | 4Q 2024 | | 3Q 2024 | | 2Q 2024 | | | Total Revenue | 5,478 | | 5,669 | | 5,585 | | 5,965 | | 6,025 | | | Net Income | 1,345 | | 1,463 | | 1,251 | | 1,673 | | 1,690 | | | Net Income Per Share | 2.46 | | 2.65 | | 2.23 | | 2.95 | | 2.95 | | | Net Cash Provided by Operating Activities | 2,032 | | 2,289 | | 2,763 | | 3,588 | | 2,889 | | | Total Expenditures | 1,883 | | 1,546 | | 1,446 | | 1,573 | | 1,682 | | | Current and Long-Term Debt | 4,236 | | 4,744 | | 4,752 | | 3,776 | | 3,784 | | | Cash and Cash Equivalents | 5,216 | | 6,599 | | 7,092 | | 6,122 | | 5,431 | | | Debt-to-Total Capitalization | 12.7 % | | 13.8 % | | 13.9 % | | 11.3 % | | 11.5 % | | | Cash Operating Costs ($/Boe) | 10.05 | | 10.31 | | 10.15 | | 10.15 | | 10.11 | | | | | | | | | | | | | | | Non-GAAP | | | | | | | | | | | | Adjusted Net Income | 1,268 | | 1,586 | | 1,535 | | 1,644 | | 1,807 | | | Adjusted Net Income Per Share | 2.32 | | 2.87 | | 2.74 | | 2.89 | | 3.16 | | | Adjusted CFO 1 | 2,496 | | 2,813 | | 2,635 | | 2,988 | | 3,042 | | | Capital Expenditures | 1,523 | | 1,484 | | 1,358 | | 1,497 | | 1,668 | | | Free Cash Flow | 973 | | 1,329 | | 1,277 | | 1,491 | | 1,374 | | | Net Debt | (980) | | (1,855) | | (2,340) | | (2,346) | | (1,647) | | | Net Debt-to-Total Capitalization | (3.5 %) | | (6.7 %) | | (8.7 %) | | (8.6 %) | | (6.0 %) | | | Cash Operating Costs ($/Boe) 2,3 | 9.94 | | 10.31 | | 10.15 | | 10.05 | | 10.11 | |

Second Quarter Highlights

Earned adjusted net income of $1.3 billion , or $2.32 per share Generated $1.0 billion of free cash flow Paid $528 million in regular dividends and repurchased $600 million of shares Oil, NGLs and natural gas production above guidance midpoints Capital expenditures and per-unit operating costs better than guidance midpoints Completed $3.5 billion debt offering to fund the acquisition of Encino Acquisition Partners ( Encino )

2025 Guidance Update

Updated 2025 guidance after close of Encino acquisition

Volumes and Capital Expenditures

| | | | 2Q 2025 | | | | | | | | | | | Volumes | 2Q 2025 | | Guidance Midpoint | | 1Q 2025 | | 4Q 2024 | | 3Q 2024 | | 2Q 2024 | | | Crude Oil and Condensate (MBod) | 504.2 | | 502.1 | | 502.1 | | 494.6 | | 493.0 | | 490.7 | | | Natural Gas Liquids (MBbld) | 258.4 | | 251.0 | | 241.7 | | 252.5 | | 254.3 | | 244.8 | | | Natural Gas (MMcfd) | 2,229 | | 2,170 | | 2,080 | | 2,092 | | 1,970 | | 1,872 | | | Total Crude Oil Equivalent (MBoed) | 1,134.1 | | 1,114.8 | | 1,090.4 | | 1,095.7 | | 1,075.7 | | 1,047.5 | | | | | | | | | | | | | | | | | Capital Expenditures ($MM) | 1,523 | | 1,550 | | 1,484 | | 1,358 | | 1,497 | | 1,668 | |

From Ezra Yacob , Chairman and Chief Executive Officer "EOG delivered excellent second quarter results, with oil, gas, and NGL volumes exceeding the midpoints of our guidance. At the same time, we maintained our focus on cost discipline, with capital expenditures, cash operating costs, and DD&A all coming in below guidance. Strong operational execution across our multi-basin portfolio continues to be the foundation of our success.

"Our operational excellence translated into strong financial performance. EOG generated $973 million in free cash flow during the quarter. We continued to deliver on our cash return commitment by returning $1.1 billion to shareholders, including $600 million of share repurchases. The regular dividend remains our top cash return priority. The 5% increase in our regular quarterly dividend, announced in tandem with the Encino acquisition, reflects both our continued confidence in our business and the positive impact we expect from the transaction.

"With the close of the Encino acquisition, the Utica is now positioned as a foundational asset for EOG. We have updated our full year 2025 guidance, which reflects both capital discipline and our high conviction in the quality and potential of this asset. Our focus is on optimizing the development of the play as we integrate Encino with our operations.

"EOG has never been better positioned to create long-term value for shareholders. The expansion of our portfolio through the Encino acquisition, our entry into Bahrain and the UAE, as well as strong exploration progress across our domestic portfolio and in Trinidad , has significantly enhanced our industry-leading asset base. We continue to improve our resource base while also maintaining one of the strongest balance sheets in the industry. Our multi- basin portfolio, operational excellence, and financial strength provide us unmatched flexibility to deliver high returns and significant cash return to shareholders through commodity price cycles."

Previously Announced Regular Dividend and Second Quarter Share Repurchases On May 30, 2025 , the Board of Directors declared a dividend of $1.02 per share on EOG's common stock. The dividend will be payable on October 31, 2025 , to shareholders of record as of October 17, 2025 . The indicated annual rate is $4.08 per share.

During the second quarter, the company repurchased 5.4 million shares for $600 million under its share repurchase authorization. EOG has $4.5 billion remaining on its current share buyback authorization.

2025 Guidance

2025 Guidance Update

Full year guidance has been updated after the close of the Encino acquisition. The revised outlook also incorporates strong year-to-date operational performance and the impact of recently enacted U.S. tax legislation.

Total capital expenditures for 2025 are now expected to range from $6.2 to $6.4 billion delivering full year average oil production of 521 MBod and average total production of 1,224 MBoed.

Second Quarter 2025 Financial Performance

Prices

Crude oil, NGL and natural gas prices decreased in 2Q compared with 1Q

Volumes

Oil production of 504,200 Bopd was above the midpoint of the guidance range and up from 1Q NGL production was above the midpoint of the guidance range and up 7% from 1Q Natural gas production was above the midpoint of the guidance range and up 7% from 1Q Total company equivalent production was above the midpoint of the guidance range and increased 4% from 1Q

Per-Unit Costs

LOE, GP&T, DD&A and non-GAAP G&A costs decreased in 2Q compared to 1Q. Encino acquisition-related costs increased GAAP G&A costs in 2Q compared to 1Q

Hedges

Mark-to-market hedge gains increased GAAP earnings per share in 2Q compared with 1Q Decreased cash paid to settle hedges increased adjusted non-GAAP earnings per share in 2Q compared with 1Q

Free Cash Flow

Adjusted cash flow from operations was $2.5 billion Incurred $1.5 billion of capital expenditures This resulted in $1.0 billion of free cash flow

Cash Return and Working Capital

Paid $528 million in regular dividends Repurchased $600 million of stock Repaid $500 million of Senior Notes upon maturity Acquired Eagle Ford bolt-on acreage for approximately $270 million

Second Quarter 2025 Operating Performance

Lease and Well

QoQ : Decreased primarily due to lower maintenance costs and water handling expenses Guidance Midpoint : Lower primarily due to lower maintenance costs, water handling expenses and workover expenses

General and Administrative

QoQ : Decreased primarily due to lower professional fees Guidance Midpoint : Lower primarily due to lower professional fees

Gathering, Processing and Transportation Costs

QoQ : Decreased primarily due to lower natural gas gathering and processing fees and operating expenses Guidance Midpoint : Lower primarily due to lower natural gas gathering and processing fees and compression fuel-related costs

Depreciation, Depletion and Amortization

QoQ : Decreased primarily due to well mix Guidance Midpoint : Lower primarily due to well mix

| Second Quarter 2025 Results vs Guidance | | | | | | | | | | | | | | | | | (Unaudited) | | | | | | | | | | | | | | | | | See "Endnotes" below for related discussion and definitions. | | | 2Q 2025 | | | | | | | | | | | | | | | 2Q 2025 | | Guidance

Midpoint 7 | | Variance | | 1Q 2025 | | 4Q 2024 | | 3Q 2024 | | 2Q 2024 | | | | Crude Oil and Condensate Volumes (MBod) | | | | | | | | | | | | | | | | | United States | 503.1 | | 501.3 | | 1.8 | | 500.9 | | 493.5 | | 491.8 | | 490.1 | | | | Trinidad | 1.1 | | 0.8 | | 0.3 | | 1.2 | | 1.1 | | 1.2 | | 0.6 | | | | Total | 504.2 | | 502.1 | | 2.1 | | 502.1 | | 494.6 | | 493.0 | | 490.7 | | | | Natural Gas Liquids Volumes (MBbld) | | | | | | | | | | | | | | | | | Total | 258.4 | | 251.0 | | 7.4 | | 241.7 | | 252.5 | | 254.3 | | 244.8 | | | | Natural Gas Volumes (MMcfd) | | | | | | | | | | | | | | | | | United States | 1,977 | | 1,930 | | 47 | | 1,834 | | 1,840 | | 1,745 | | 1,668 | | | | Trinidad | 252 | | 240 | | 12 | | 246 | | 252 | | 225 | | 204 | | | | Total | 2,229 | | 2,170 | | 59 | | 2,080 | | 2,092 | | 1,970 | | 1,872 | | | | | | | | | | | | | | | | | | | | | Total Crude Oil Equivalent Volumes (MBoed) | 1,134.1 | | 1,114.8 | | 19.3 | | 1,090.4 | | 1,095.7 | | 1,075.7 | | 1,047.5 | | | | Total MMBoe | 103.2 | | 101.4 | | 1.8 | | 98.1 | | 100.8 | | 99.0 | | 95.3 | | | | | | | | | | | | | | | | | | | | | Benchmark Price | | | | | | | | | | | | | | | | | Oil (WTI) ($/Bbl) | 63.71 | | | | | | 71.42 | | 70.28 | | 75.16 | | 80.55 | | | | Natural Gas (HH) ($/Mcf) | 3.44 | | | | | | 3.66 | | 2.79 | | 2.16 | | 1.89 | | | | | | | | | | | | | | | | | | | | | Crude Oil and Condensate - above (below) WTI 8 ($/Bbl) | | | | | | | | | | | | | | | | | United States | 1.13 | | 1.30 | | (0.17) | | 1.48 | | 1.40 | | 1.79 | | 2.16 | | | | Trinidad | (9.21) | | (9.50) | | 0.29 | | (10.30) | | (9.81) | | (12.01) | | (9.80) | | | | Natural Gas Liquids - Realizations as % of WTI | | | | | | | | | | | | | | | | | Total | 35.6 % | | 34.0 % | | 1.6 % | | 36.8 % | | 33.9 % | | 29.8 % | | 28.7 % | | | | Natural Gas - above (below) NYMEX Henry Hub 9 ($/Mcf) | | | | | | | | | | | | | | | | | United States | (0.57) | | (0.45) | | (0.12) | | (0.30) | | (0.40) | | (0.32) | | (0.32) | | | | Natural Gas Realizations ($/Mcf) | | | | | | | | | | | | | | | | | Trinidad | 3.65 | | 3.60 | | 0.05 | | 3.78 | | 3.86 | | 3.68 | | 3.48 | | | | | | | | | | | | | | | | | | | | | Total Expenditures (GAAP) ($MM) | 1,883 | | | | | | 1,546 | | 1,446 | | 1,573 | | 1,682 | | | | Capital Expenditures (non-GAAP) ($MM) | 1,523 | | 1,550 | | (27) | | 1,484 | | 1,358 | | 1,497 | | 1,668 | | | | | | | | | | | | | | | | | | | | | Operating Unit Costs ($/Boe) | | | | | | | | | | | | | | | | | Lease and Well | 3.84 | | 4.15 | | (0.31) | | 4.09 | | 3.91 | | 3.96 | | 4.09 | | | | Gathering, Processing and Transportation Costs 6 | 4.41 | | 4.55 | | (0.14) | | 4.48 | | 4.37 | | 4.50 | | 4.44 | | | | General and Administrative (GAAP) | 1.80 | | 1.75 | | 0.05 | | 1.74 | | 1.87 | | 1.69 | | 1.58 | | | | General and Administrative (non-GAAP) 2,3 | 1.69 | | 1.75 | | (0.06) | | 1.74 | | 1.87 | | 1.59 | | 1.58 | | | | Cash Operating Costs (GAAP) | 10.05 | | 10.45 | | (0.40) | | 10.31 | | 10.15 | | 10.15 | | 10.11 | | | | Cash Operating Costs (non-GAAP) 2,3 | 9.94 | | 10.45 | | (0.51) | | 10.31 | | 10.15 | | 10.05 | | 10.11 | | | | Depreciation, Depletion and Amortization | 10.20 | | 10.30 | | (0.10) | | 10.32 | | 10.11 | | 10.42 | | 10.32 | | | | | | | | | | | | | | | | | | | | | Expenses ($MM) | | | | | | | | | | | | | | | | | Exploration and Dry Hole | 85 | | 70 | | 15 | | 75 | | 60 | | 43 | | 39 | | | | Impairment (GAAP) | 39 | | | | | | 44 | | 276 | | 15 | | 81 | | | | Impairment (excluding certain impairments (non-GAAP) 10 | 28 | | 70 | | (42) | | 44 | | 23 | | 15 | | 46 | | | | Capitalized Interest | 11 | | 12 | | (1) | | 12 | | 13 | | 12 | | 10 | | | | Net Interest (GAAP) | 51 | | 43 | | 8 | | 47 | | 38 | | 31 | | 36 | | | | Net Interest (non-GAAP) 5 | 45 | | 43 | | 2 | | 47 | | 38 | | 31 | | 36 | | | | ‌ | | | | | | | | | | | | | | | | | TOTI (% of revenues from sales of crude oil and condensate, NGLs and natural gas) | | | | | | | | | | | | | | | | | (GAAP) | 7.3 % | | 8.0 % | | (0.7 %) | | 7.6 % | | 6.8 % | | 6.5 % | | 7.5 % | | | | (non-GAAP) 3 | 7.3 % | | 8.0 % | | (0.7 %) | | 7.6 % | | 6.8 % | | 7.2 % | | 7.5 % | | | | Income Taxes | | | | | | | | | | | | | | | | | Effective Rate | 23.2 % | | 22.5 % | | 0.7 % | | 22.1 % | | 23.0 % | | 21.6 % | | 21.7 % | | | | Current Tax Expense ($MM) | 301 | | 260 | | 41 | | 370 | | 454 | | 240 | | 341 | | |

| Third Quarter and Full-Year 2025 Guidance 11 | | | | | | | | | | | | | | (Unaudited) | | | | | | | | | | | | | | See "Endnotes" below for related discussion and definitions. | 3Q 2025 | | 3Q 2025 | | FY 2025 | | FY 2025 | | | | | | | | Guidance Range | | Midpoint | | Guidance Range | | Midpoint | | | | | | | Crude Oil and Condensate Volumes (MBod) | | | | | | | | | | | | | | United States | 528.7 | - | 533.3 | | 531.0 | | 517.6 | - | 521.4 | | 519.5 | | | Trinidad | 1.2 | - | 1.6 | | 1.4 | | 1.1 | - | 1.5 | | 1.3 | | | Total | 529.9 | - | 534.9 | | 532.4 | | 518.7 | - | 522.9 | | 520.8 | | | Natural Gas Liquids Volumes (MBbld) | | | | | | | | | | | | | | Total | 297.5 | - | 312.5 | | 305.0 | | 279.0 | - | 289.0 | | 284.0 | | | Natural Gas Volumes (MMcfd) | | | | | | | | | | | | | | United States | 2,475 | - | 2,575 | | 2,525 | | 2,240 | - | 2,340 | | 2,290 | | | Trinidad | 200 | - | 220 | | 210 | | 215 | - | 235 | | 225 | | | Total | 2,675 | - | 2,795 | | 2,735 | | 2,455 | - | 2,575 | | 2,515 | | | Crude Oil Equivalent Volumes (MBoed) | | | | | | | | | | | | | | United States | 1,238.7 | - | 1,275.0 | | 1,256.9 | | 1,169.9 | - | 1,200.4 | | 1,185.2 | | | Trinidad | 34.5 | - | 38.3 | | 36.4 | | 36.9 | - | 40.7 | | 38.8 | | | Total | 1,273.2 | - | 1,313.3 | | 1,293.3 | | 1,206.8 | - | 1,241.1 | | 1,224.0 | | | Crude Oil and Condensate - above (below) WTI 8 ($/Bbl) | | | | | | | | | | | | | | United States | 0.05 | - | 1.55 | | 0.80 | | (0.15) | - | 1.85 | | 0.85 | | | Trinidad | (5.75) | - | (4.25) | | (5.00) | | (8.00) | - | (6.00) | | (7.00) | | | Natural Gas Liquids - Realizations as % of WTI | | | | | | | | | | | | | | Total | 29.0 % | - | 39.0 % | | 34.0 % | | 30.0 % | - | 40.0 % | | 35.0 % | | | Natural Gas - above (below) NYMEX Henry Hub 9 ($/Mcf) | | | | | | | | | | | | | | United States | (0.75) | - | (0.05) | | (0.40) | | (1.40) | - | 0.60 | | (0.40) | | | Natural Gas Realizations ($/Mcf) | | | | | | | | | | | | | | Trinidad | 3.25 | - | 3.95 | | 3.60 | | 3.10 | - | 4.10 | | 3.60 | | | | | | | | | | | | | | | | | Capital Expenditures 12 ($MM) | 1,600 | - | 1,700 | | 1,650 | | 6,200 | - | 6,400 | | 6,300 | | | | | | | | | | | | | | | | | Operating Unit Costs ($/Boe) | | | | | | | | | | | | | | Lease and Well | 3.45 | - | 3.95 | | 3.70 | | 3.55 | - | 4.05 | | 3.80 | | | Gathering, Processing and Transportation Costs 6 | 4.85 | - | 5.35 | | 5.10 | | 4.65 | - | 5.15 | | 4.90 | | | General and Administrative | 1.35 | - | 1.65 | | 1.50 | | 1.50 | - | 1.80 | | 1.65 | | | Cash Operating Costs | 9.65 | - | 10.95 | | 10.30 | | 9.70 | - | 11.00 | | 10.35 | | | Depreciation, Depletion and Amortization | 9.35 | - | 10.35 | | 9.85 | | 9.55 | - | 10.55 | | 10.05 | | | Expenses ($MM) | | | | | | | | | | | | | | Exploration and Dry Hole | 55 | - | 95 | | 75 | | 270 | - | 310 | | 290 | | | Impairment (excluding certain impairments) 10 | 30 | - | 110 | | 70 | | 180 | - | 260 | | 220 | | | Capitalized Interest | 19 | - | 23 | | 21 | | 68 | - | 72 | | 70 | | | Net Interest | 81 | - | 85 | | 83 | | 248 | - | 252 | | 250 | | | | | | | | | | | | | | | | | TOTI (% of revenues from sales of crude oil and | | | | | | | | | | | | | | condensate, NGLs and natural gas) | 6.5 % | - | 8.5 % | | 7.5 % | | 6.5 % | - | 8.5 % | | 7.5 % | | | Income Taxes | | | | | | | | | | | | | | Effective Rate | 18.0 % | - | 23.0 % | | 20.5 % | | 20.0 % | - | 25.0 % | | 22.5 % | | | Current Tax Expense ($MM) | 130 | - | 230 | | 180 | | 1,040 | - | 1,240 | | 1,140 | |

Second Quarter 2025 Results Webcast Friday, August 8, 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 States with proved reserves in the United States and Trinidad . To learn more visit www.eogresources.com .

Investor Contacts Pearce Hammond 713-571-4684 Neel Panchal 713-571-4884 Shelby O'Connor 713-571-4560

Media Contact Kimberly Ehmer 713-571-4676

| 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 $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 2Q 2025 was ($0.11) as set forth in "Second Quarter 2025 Results vs Guidance" above. G&A per Boe (GAAP) 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 "Second 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 and 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) | Net interest expense (non-GAAP) excludes Encino acquisition-related financing commitment costs of $6 million for 2Q 2025. | | 6) | 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. | | 7) | GAAP and non-GAAP distinctions apply solely to actual results and do not pertain to EOG's second quarter 2025 guidance midpoint disclosure. | | 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) | The forecast items for the third 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. | | 12) | 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. |