EOG Resources Reports Fourth Quarter and Full-Year 2024 Results; Announces 2025 Capital Plan

EOG Resources, Inc. (EOG) today reported fourth quarter and full-year 2024 results. The attached supplemental financial tables and schedules for the reconciliation of non-GAAP measures to GAAP measures and related definitions, along with a related presentation, are also available on EOG's website at http://investors.eogresources.com/investors.

Key Financial ResultsIn millions of USD, except per-share,per-Boeand ratio dataGAAP 4Q 2024 3Q 2024 2Q 2024 1Q 2024 4Q 2023 FY 2024 FY 2023Total Revenue 5,585 5,965 6,025 6,123 6,357 23,698 24,186Net Income 1,251 1,673 1,690 1,789 1,988 6,403 7,594Net Income Per Share 2.23 2.95 2.95 3.10 3.42 11.25 13.00Net Cash Provided by Operating Activities 2,763 3,588 2,889 2,903 3,104 12,143 11,340Total Expenditures 1,446 1,573 1,682 1,952 1,634 6,653 6,818Current and Long-Term Debt 4,752 3,776 3,784 3,791 3,799 4,752 3,799Cash and Cash Equivalents 7,092 6,122 5,431 5,292 5,278 7,092 5,278Debt-to-Total Capitalization 13.9% 11.3% 11.5% 11.7% 11.9% 13.9% 11.9%Cash Operating Costs ($/Boe) 10.15 10.15 10.11 10.37 10.52 10.19 10.33Non – GAAPAdjusted Net Income 1,535 1,644 1,807 1,626 1,783 6,612 6,825Adjusted Net Income Per Share 2.74 2.89 3.16 2.82 3.07 11.62 11.69CFO before Changes in Working Capital 2,635 2,988 3,042 2,928 2,989 11,593 11,149Capital Expenditures 1,358 1,497 1,668 1,703 1,512 6,226 6,041Free Cash Flow 1,277 1,491 1,374 1,225 1,477 5,367 5,108Net Debt (2,340) (2,346) (1,647) (1,501) (1,479) (2,340) (1,479)Net Debt-to-Total Capitalization (8.7%) (8.6%) (6.0%) (5.5%) (5.6%) (8.7%) (5.6%)Cash Operating Costs ($/Boe)1 10.15 10.05 10.11 10.37 10.52 10.17 10.33

Fourth Quarter Highlights

Earned adjusted net income of $1.5 billion, or $2.74 per share – Generated $1.3 billion of free cash flow – Declared regular quarterly dividend of $0.975 per share and repurchased $981 million of shares – Oil and gas volumes, and total per-unit operating costs better than guidance midpoints

Full-Year 2024 Highlights and 2025 Capital Plan

Generated $5.4 billion of free cash flow and returned $5.3 billion to shareholders – Replaced 201% of 2024 production at a finding and development cost, excluding price revisions, of $7.03 per Boe (GAAP) and $6.68 per Boe(Non-GAAP) – Reduced average well costs 6% across multi-basin portfolio – Announced $6.2 billion 2025 capital plan to grow oil production 3% and total production 6% – EOG and Bapco Energies entered into a strategic participation agreement in Bahrain

Volumes and Capital Expenditures

Volumes 4Q 2024 4Q 2024 3Q 2024 2Q 2024 1Q 2024 4Q 2023 FY 2024 FY 2023 Guidance MidpointCrude Oil and Condensate (MBod) 494.6 493.0 493.0 490.7 487.4 485.2 491.4 475.8Natural Gas Liquids (MBbld) 252.5 260.0 254.3 244.8 231.7 235.8 245.9 223.8Natural Gas (MMcfd) 2,092 2,075 1,970 1,872 1,858 1,831 1,948 1,711Total Crude Oil Equivalent (MBoed) 1,095.7 1,098.9 1,075.7 1,047.5 1,028.8 1,026.2 1,062.1 984.8Capital Expenditures ($MM) 1,358 1,330 1,497 1,668 1,703 1,512 6,226 6,041

From Ezra Yacob, Chairman and Chief Executive Officer “2024 was another year of strong execution for EOG. Oil and total volumes were higher than our original plan, capital expenditures were on target, and we continued to lower cash operating costs. We improved productivity and base production performance through innovations in completion design and artificial lift automation. Along with better productivity, sustainable efficiency improvements from extended laterals and EOG's in-house drilling motor program helped lower well costs 6%. Our comprehensive marketing strategy continued to deliver peer-leading U.S. price realizations, further maximizing margins across our portfolio.2024 also marked another year of progress in the Utica and Dorado plays that resulted in consistent, strong results helping to support higher activity going forward.

“EOG's operational execution supported the company's exceptional financial performance and record cash return to shareholders in 2024. We generated $5.4 billion in free cash flow and returned $5.3 billion, or 98%, to shareholders. This robust cash return was anchored by our sustainable, growing regular dividend, which we increased by 7%, and included $3.2 billion in share repurchases. Since we initiated share repurchases in 2023, we have reduced our share count by approximately 5%. As we continue to optimize our capital structure, our strong cash flow generation and industry-leading balance sheet better position us to deliver shareholder value through the cycles.

“We are excited about 2025 where we have detailed a disciplined plan that builds on last year's success and lays a foundation for the future. Our comprehensive investment approach, focused on returns and optimizing value from our diverse portfolio of multi-basin assets, coupled with our industry-leading exploration expertise, provide long-term visibility for high returns and strong free cash flow generation. EOG has never been better positioned to deliver long-term shareholder value and we remain 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.”

Fourth Quarter 2024 Financial Performance

Prices

Crude oil prices decreased in 4Q compared with 3Q, partially offset by an increase in NGL and natural gas prices from 3Q

Volumes

Oil production of 494,600 Bopd was above the midpoint of the guidance range and up from 3Q – NGL production was below the midpoint of the guidance range and down from 3Q – Natural gas production was above the midpoint of the guidance range and up 6% from 3Q – Total company equivalent production was below the midpoint of the guidance range but increased 2% from 3Q

Per-Unit Costs

LOE, GP&T, and DD&A expenses decreased in 4Q compared with 3Q, while G&A costs increased

Hedges

Mark-to-market hedge losses decreased GAAP earnings per share in 4Q compared with 3Q – Cash received to settle hedges decreased from 3Q, lowering adjusted non-GAAP earnings per share

Free Cash Flow

Cash flow from operations before changes in working capital was $2.64 billion – Incurred $1.36 billion of capital expenditures – This resulted in $1.28 billion of free cash flow

Cash Return and Working Capital

Paid $509 million in regular dividends – Repurchased $981 million of stock – Completed a $1.0 billion bond offering

Full-Year 2024 Financial Performance

Prices

Crude oil prices decreased 2% – NGL prices increased 1% – Natural gas prices decreased 22%

Volumes

Oil production increased 3% to 491,400 Bopd – NGL production increased 10% – Natural gas production increased 14% – Total company equivalent production increased 8%

Per-Unit Costs

Lower LOE, GP&T, and G&A costs were offset by higher DD&A expenses in 2024

Hedges

Lower mark-to-market hedge gains contributed to lower GAAP earnings per share in 2024 compared with 2023 – Higher net cash received to settle hedges partially offset lower commodity prices in 2024

Free Cash Flow

Cash flow from operations before changes in working capital was $11.6 billion – Incurred $6.2 billion of capital expenditures – This resulted in $5.4 billion of free cash flow

Cash Return and Working Capital

Paid $2.1 billion in regular dividends – Repurchased $3.2 billion of stock – Completed a $1.0 billion bond offering – Postponement of tax payments associated with severe weather tax relief accounted for approximately $700 million of the increase from working capital and other items

Fourth Quarter 2024 Operating Performance and Cash Return

Lease and Well

QoQ: Decreased primarily due to lower well service and labor costs

Guidance Midpoint: Lower primarily due to lower workover expenses, labor and fuel costs

Gathering, Processing and Transportation Costs

QoQ: Decreased primarily due to lower oil transportation expenses

Guidance Midpoint: Lower primarily due to lower compression-related fuel cost

General and Administrative

QoQ: Higher due to higher employee-related expenses and professional fees

Guidance Midpoint: Lower due to lower employee-related expenses

Depreciation, Depletion and Amortization

QoQ: Lower primarily due to the addition of lower cost reserves and positive reserve revisions

Guidance Midpoint: Lower primarily due to the addition of lower cost reserves and positive reserve revisions

Regular Dividend and Fourth Quarter Share Repurchases

The Board of Directors today declared a dividend of $0.975 per share on EOG's common stock. The dividend will be payable April 30, 2025, to stockholders of record as of April 16, 2025. The indicated annual rate is $3.90 per share, reflecting a 7% increase compared with 2024.

During the fourth quarter, the company repurchased 7.8 million shares for $981 million under its share repurchase authorization, at an average purchase price of $126 per share.

For full-year 2024, the company repurchased 25.8 million shares for $3.2 billion under its share repurchase authorization, at an average purchase price of $123 per share. EOG has $5.8 billion remaining on its current repurchase authorization.

2024 Reserves

Finding and Development Cost

Finding and development cost, excluding price revisions, decreased in 2024 to $6.68 per Boe, due to higher year-over-year well performance and cost reductions. Proved developed finding cost, excluding price revisions, was $8.71 per Boe (GAAP) and $8.04 per Boe (Non-GAAP) in 2024.

Reserve Replacement

Total proved reserves increased 6% in 2024. Extensions and discoveries added 580 MMBoe of proved reserves in 2024. Revisions other than price increased proved reserves by 215 MMBoe. Net proved reserve additions from all sources, excluding price revisions, replaced 201% of 2024 total production.

2025 Capital Program

Total expenditures for 2025 are expected to range from $6.0 to $6.4 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 and non-cash exchanges and transactions. The capital program also excludes certain exploration costs incurred as operating expenses.

The disciplined capital program is anchored by steady year-over-year activity levels in the Delaware Basin, with a step up in activity in the Utica and Dorado plays. The plan delivers 3% oil volume growth and 6% total volume growth through the drilling and completion of 605 net wells across EOG's multi-basin portfolio of high return inventory.

The capital program also funds the completion of strategic infrastructure projects and international investment opportunities, including exploration projects in Trinidad and Bahrain.

EOG and Bapco Energies Entered Into a Strategic Participation Agreement in Bahrain

The companies will evaluate a natural gas exploration prospect with planned drilling activity in 2025. The transaction is subject to further government approvals.

Fourth Quarter 2024 Results vs Guidance(Unaudited)See “Endnotes” below for related discussion and definitions. 4Q 2024 4Q 2024 Variance 3Q 2024 2Q 2024 1Q 2024 4Q 2023 Guidance MidpointCrude Oil and Condensate Volumes (MBod)United States 493.5 491.9 1.6 491.8 490.1 486.8 484.6Trinidad 1.1 1.1 0.0 1.2 0.6 0.6 0.6Total 494.6 493.0 1.6 493.0 490.7 487.4 485.2Natural Gas Liquids Volumes (MBbld)Total 252.5 260.0 (7.5) 254.3 244.8 231.7 235.8Natural Gas Volumes (MMcfd)United States 1,840 1,825 15 1,745 1,668 1,658 1,653Trinidad 252 250 2 225 204 200 178Total 2,092 2,075 17 1,970 1,872 1,858 1,831Total Crude Oil Equivalent Volumes (MBoed) 1,095.7 1,098.9 (3.2) 1,075.7 1,047.5 1,028.8 1,026.2Total MMBoe 100.8 101.1 (0.3) 99.0 95.3 93.6 94.4Benchmark PriceOil (WTI) ($/Bbl) 70.28 75.16 80.55 76.97 78.33Natural Gas (HH) ($/Mcf) 2.79 2.16 1.89 2.24 2.87Crude Oil and Condensate – above (below) WTI4 ($/Bbl)United States 1.40 1.75 (0.35) 1.79 2.16 1.49 2.28Trinidad (9.81) (10.35) 0.54 (12.01) (9.80) (9.47) (9.12)Natural Gas Liquids – Realizations as % of WTITotal 33.9% 32.0% 1.9% 29.8% 28.7% 31.6% 28.5%Natural Gas – above (below) NYMEX Henry Hub5 ($/Mcf)United States (0.40) (0.35) (0.05) (0.32) (0.32) (0.14) (0.15)Natural Gas Realizations ($/Mcf)Trinidad 3.86 3.65 0.21 3.68 3.48 3.54 3.81Total Expenditures (GAAP) ($MM) 1,446 1,573 1,682 1,952 1,634Capital Expenditures (non-GAAP) ($MM) 1,358 1,330 28 1,497 1,668 1,703 1,512Operating Unit Costs ($/Boe)Lease and Well 3.91 4.20 (0.29) 3.96 4.09 4.23 4.00Gathering, Processing and Transportation Costs3 4.37 4.45 (0.08) 4.50 4.44 4.41 4.49General and Administrative (GAAP) 1.87 1.69 1.58 1.73 2.03General and Administrative (non-GAAP)1 1.87 1.90 (0.03) 1.59 1.58 1.73 2.03Cash Operating Costs (GAAP) 10.15 10.15 10.11 10.37 10.52Cash Operating Costs (non-GAAP)1 10.15 10.55 (0.40) 10.05 10.11 10.37 10.52Depreciation, Depletion and Amortization 10.11 10.35 (0.24) 10.42 10.32 11.47 9.85Expenses ($MM)Exploration and Dry Hole 60 60 0 43 39 46 41Impairment (GAAP) 276 15 81 19 79Impairment (excluding certain impairments (non-GAAP))6 23 120 (97) 15 46 17 60Capitalized Interest 13 11 2 12 10 10 9Net Interest 38 33 5 31 36 33 35TOTI (% of Wellhead Revenue) (GAAP) 6.8% 6.5% 7.5% 7.7% 6.6%TOTI (% of Wellhead Revenue) (non-GAAP)1 6.8% 7.5% (0.7%) 7.2% 7.5% 7.7% 6.6%Income TaxesEffective Rate 23.0% 21.5% 1.5% 21.6% 21.7% 22.2% 21.6%Current Tax Expense ($MM) 454 495 (41) 240 341 312 352First Quarter and Full-Year 2025 Guidance7(Unaudited)See “Endnotes” below for related discussion and definitions 1Q 2025 1Q 2025 Midpoint FY 2025 FY 2025 Midpoint 2024 Actual 2023 Actual 2022 Guidance Range Guidance Range ActualCrude Oil and Condensate Volumes (MBod)United States 495.0 – 503.0 499.0 499.5 – 507.5 503.5 490.6 475.2 460.7Trinidad 0.8 – 1.2 1.0 0.9 – 1.3 1.1 0.8 0.6 0.6Total 495.8 – 504.2 500.0 500.4 – 508.8 504.6 491.4 475.8 461.3Natural Gas Liquids Volumes (MBbld)Total 233.0 – 245.0 239.0 249.0 – 261.0 255.0 245.9 223.8 197.7Natural Gas Volumes (MMcfd)United States 1,740 – 1,840 1,790 1,900 – 2,000 1,950 1,728 1,551 1,315Trinidad 225 – 245 235 215 – 235 225 220 160 180Total 1,965 – 2,085 2,025 2,115 – 2,235 2,175 1,948 1,711 1,495Crude Oil Equivalent Volumes (MBoed)United States 1,018.0 – 1,054.7 1,036.4 1,065.2 – 1,101.8 1,083.5 1,024.5 957.5 877.5Trinidad 38.3 – 42.0 40.2 36.7 – 40.5 38.6 37.6 27.3 30.7Total 1,056.3 – 1,096.7 1,076.5 1,101.9 – 1,142.3 1,122.1 1,062.1 984.8 908.2Benchmark PriceOil (WTI) ($/Bbl) 75.72 77.61 94.23Natural Gas (HH) ($/Mcf) 2.27 2.74 6.64Crude Oil and Condensate – above (below) WTI4 ($/Bbl)United States 0.65 – 2.15 1.40 0.20 – 2.20 1.20 1.70 1.57 2.99Trinidad (12.95) – (11.45) (12.20) (8.10) – (6.10) (7.10) (11.29) (9.03) (8.07)Natural Gas Liquids – Realizations as % of WTITotal 30.0% – 40.0% 35.0% 29.0% – 39.0% 34.0% 30.9% 29.7% 39.0%Natural Gas – above (below)NYMEX Henry Hub5 ($/Mcf)United States (0.70) – 0.00 (0.35) (1.35) – 0.65 (0.35) (0.28) (0.04) 0.63Natural Gas Realizations8 ($/Mcf)Trinidad 3.25 – 3.95 3.60 3.00 – 4.00 3.50 3.65 3.65 4.43Total Expenditures (GAAP) ($MM) 6,653 6,818 5,610Capital Expenditures9 (non-GAAP) ($MM) 1,475 – 1,575 1,525 6,000 – 6,400 6,200 6,226 6,041 4,607Operating Unit Costs ($/Boe)Lease and Well 4.00 – 4.50 4.25 3.90 – 4.40 4.15 4.04 4.05 4.02Gathering, Processing and Transportation Costs3 4.30 – 4.80 4.55 4.30 – 4.80 4.55 4.43 4.50 4.78General and Administrative (GAAP) 1.75 – 2.05 1.90 1.65 – 1.95 1.80 1.72 1.78 1.72General and Administrative (non-GAAP)1 1.70 1.78 1.67Cash Operating Costs (GAAP) 10.05 – 11.35 10.70 9.85 – 11.15 10.50 10.19 10.33 10.52Cash Operating Costs (non-GAAP)1 10.17 10.33 10.47Depreciation, Depletion and Amortization 10.00 – 11.00 10.50 9.90 – 10.90 10.40 10.57 9.72 10.69Expenses ($MM)Exploration and Dry Hole 40 – 80 60 210 – 250 230 188 182 204Impairment (GAAP) 391 202 382Impairment (excluding certain impairments (non-GAAP))630 – 110 70 240 – 320 280 100 160 269Capitalized Interest 10 – 14 12 46 – 50 48 45 33 36Net Interest 46 – 50 48 173 – 177 175 138 148 179TOTI (% of Wellhead Revenue) (GAAP) 7.0% – 9.0% 8.0% 7.0% – 9.0% 8.0% 7.1% 7.4% 7.0%TOTI (% of Wellhead Revenue) (non-GAAP)1 7.3% 7.4% 7.5%Income TaxesEffective Rate 20.0% – 25.0% 22.5% 20.0% – 25.0% 22.5% 22.1% 21.6% 21.7%Current Tax Expense ($MM) 340 – 440 390 1,350 – 1,750 1,550 1,348 1,415 2,208

Fourth Quarter and Full-Year 2024 Results Webcast

Friday, February 28, 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 visitwww.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 Operating Costs consist of LOE, GP&T and G&A. TOTI (% of Wellhead Revenue) (non-GAAP) and G&A (non-GAAP) for each of 3Q 2024, fiscal year 2024 and fiscal year 2022 exclude a state severance tax refund and related consulting fees, respectively, 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, fiscal year 2024 and fiscal year 2022 was $(0.10), $(0.02) and $(0.05), respectively, as set forth in “Fourth Quarter 2024 Results vs Guidance” and “First Quarter and Full-Year 2025 Guidance” above.2) Includes gathering, processing and marketing revenue, gains (losses) on asset dispositions (for GAAP earnings per share only), other revenue, exploration, dry hole, impairments and marketing costs, taxes other than income, other income, interest expense and the impact of changes in the effective income tax rate.3) 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.4) EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing,Oklahoma,usingthesimpleaverage oftheNYMEXsettlementprices foreachtrading daywithintheapplicablecalendar month.5) EOGbases UnitedStatesnatural gaspricedifferentialsuponthenatural gaspriceatHenryHub,Louisiana,using theNYMEXLastDaySettle price for each of the applicablemonths.6) 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'soilandgaspropertiesorotherassets). 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 originallyestimated).7) The forecast items for the first 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'srelated CurrentReportonForm8-Kfiling,replaces and supersedes any previously issued guidance orforecast.8) The full-year 2022 realized natural gas price for Trinidad includes a one-time pricing adjustment of $0.76/Mcf for prior-period production following a contract amendment with the National Gas Company of Trinidad and Tobago Limited.9) The forecast includes expenditures for Exploration and Development Drilling, Facilities, Leasehold Acquisitions, Capitalized Interest, Dry Hole Costs and Other Property, Plant and Equipment. The forecast excludes Property Acquisitions, Asset Retirement Costs, Non-Cash Exchanges and Transactions and exploration costs incurred as operating expenses.GlossaryAcq AcquisitionsATROR After-tax rate of returnBbl BarrelBn BillionBoe Barrels of oil equivalentBopd Barrels of oil per dayCAGR Compound annual growth rateCapex Capital expendituresCFO Cash flow provided by operating activities before changes in working capitalCO2e Carbon dioxide equivalentDD&A Depreciation, Depletion and AmortizationDisc DiscoveriesDivest DivestituresEPS Earnings per shareExt ExtensionsGAAP Generally accepted accounting principlesG&A General and administrative expenseG&P Gathering and processingGHG Greenhouse gasGP&T Gathering, processing & transportation expenseHH Henry HubLOE Lease operating expense, or lease and well expenseMBbld Thousand barrels of liquids per dayMBod Thousand barrels of oil per dayMBoe Thousand barrels of oil equivalentMBoed Thousand barrels of oil equivalent per dayMcf Thousand cubic feet of natural gasMMBoe Million barrels of oil equivalentMMcfd Million cubic feet of natural gas per dayNGLs Natural gas liquidsNYMEX U.S. New York Mercantile ExchangeOTP Other than priceQoQ Quarter over quarterTOTI Taxes other than incomeUSD United States dollarWTI West Texas IntermediateYoY Year over year$MM Million United States dollars$/Bbl U.S. Dollars per barrel$/Boe U.S. Dollars per barrel of oil equivalent$/Mcf U.S. Dollars per thousand cubic feet

This press release and any accompanying disclosures may include 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 and statements regarding the plans and objectives of EOG's management for future operations, 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 EOG's future financial or operating results and returns or 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 are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that such assumptions are accurate or will prove to have been correct or that any of such expectations will be achieved (in full or at all) or will be achieved on the expected or anticipated timelines. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:

— the timing, magnitude and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids (NGLs), natural gas and related commodities;

— the extent to which EOG is successful in its efforts to acquire or discover additional reserves;

— the extent to which EOG is successful in its efforts to (i) economically develop its acreage in, (ii) produce reserves and achieve anticipated production levels and rates of return from, (iii) decrease or otherwise control its drilling, completion and operating costs and capital expenditures related to, and (iv) maximize reserve recoveries from, its existing and future crude oil and natural gas exploration and development projects and associated potential and existing drilling locations;

— the success of EOG's cost-mitigation initiatives and actions in offsetting the impact of any inflationary or other pressures on EOG's operating costs and capital expenditures;

— the extent to which EOG is successful in its efforts to market its production of crude oil and condensate, NGLs and natural gas;

— security threats, including cybersecurity threats and disruptions to our business and operations from breaches of our information technology systems, physical breaches of our facilities and other infrastructure or breaches of the information technology systems, facilities and infrastructure of third parties with which we transact business, and enhanced regulatory focus on the prevention of, and disclosure requirements relating to, cyber incidents;

— the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, storage, transportation, refining, liquefaction and export facilities and equipment;

— the availability, cost, terms and timing of issuance or execution of mineral licenses, concessions and leases and governmental and other permits and rights-of-way, and EOG's ability to retain mineral licenses, concessions and leases;

— the impact of, and changes in, government policies, laws and regulations, including climate change-related regulations, policies and initiatives (for example, with respect to air emissions); tax laws and regulations (including, but not limited to, carbon tax or other emissions-related legislation); environmental, health and safety laws and regulations relating to disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations affecting the leasing of acreage and permitting for oil and gas drilling and the calculation of royalty payments in respect of oil and gas production; laws and regulations imposing additional permitting and disclosure requirements, additional operating restrictions and conditions or restrictions on drilling and completion operations and on the transportation of crude oil, NGLs and natural gas; laws and regulations with respect to financial and other derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;

— 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 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, 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;

— the economic and financial impact of epidemics, pandemics or other public health issues;

— 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 whichEOG 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 fiscal year ended December 31, 2024 and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.

In light of these risks, uncertainties and assumptions, the events anticipated byEOG'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 ofEOG'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.

Historical Non-GAAP Financial Measures: Reconciliation schedules and definitions for the historical non-GAAP financial measures included or referenced herein as well as related discussion can be found on the EOG website at www.eogresources.com.

Cautionary Notice Regarding Forward-Looking Non-GAAP Financial Measures: In addition, this press release and any accompanying disclosures may include or reference certain forward-looking, non-GAAP financial measures, such as free cash flow, cash flow provided by operating activities before changes in working capital and return on capital employed, and certain related estimates regarding future performance, commodity prices and operating and financial results. Because we provide these measures on a forward-looking basis, we cannot reliably or reasonably predict certain of the necessary components of the most directly comparable forward-looking GAAP measures, such as future changes in working capital and future impairments. Accordingly, we are unable to present a quantitative reconciliation of such forward-looking, non-GAAP financial measures to the respective most directly comparable forward-looking GAAP financial measures without unreasonable efforts. The unavailable information could have a significant impact on our ultimate results. However, management believes these forward-looking, non-GAAP measures may be a useful tool for the investment community in comparing EOG's forecasted financial performance to the forecasted financial performance of other companies in the industry. Any such forward-looking measures and estimates are intended to be illustrative only and are not intended to reflect the results that EOG will necessarily achieve for the period(s) presented; EOG's actual results may differ materially from such measures and estimates.

Oil and Gas Reserves: The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only “proved” reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also “probable” reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as “possible” reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve or resource estimates provided in this press release or any accompanying disclosures that are not specifically designated as being estimates of proved reserves may include “potential” reserves, “resource potential” and/or other estimated reserves or estimated resources not necessarily calculated in accordance with, or contemplated by, the SEC's latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2024 (and any updates to such disclosure set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K), available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC's website at www.sec.gov.

Table of ContentsFourth Quarter 2024Supplemental Financial and Operating Data PageIncome Statements 15Volumes and Prices 17Balance Sheets 18Cash Flow Statements 19Non-GAAP Financial Measures 20Adjusted Net Income 21Net Income Per Share 28Adjusted Net Income Per Share 32Cash Flow from Operations and Free Cash Flow 36Net Debt-to-Total Capitalization Ratio 37Proved Reserves and Reserve Replacement Data 38Reserve Replacement Cost Data 39Revenues, Costs and Margins Per Barrel of Oil Equivalent 44Income StatementsIn millions of USD, except share data (in millions) and per share data (Unaudited) 2023 2024 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr YearOperating Revenues and OtherCrude Oil and Condensate 3,182 3,252 3,717 3,597 13,748 3,480 3,692 3,488 3,261 13,921Natural Gas Liquids 490 409 501 484 1,884 513 515 524 554 2,106Natural Gas 517 334 417 476 1,744 382 303 372 494 1,551Gains (Losses) on Mark-to-Market 376 101 43 298 818 237 (47) 79 (65) 204Financial Commodity and OtherDerivative Contracts, NetGathering, Processing and Marketing 1,390 1,465 1,478 1,473 5,806 1,459 1,519 1,481 1,341 5,800Gains (Losses) on Asset Dispositions, 69 (9) 35 – 95 26 20 (7) (23) 16NetOther, Net 20 21 21 29 91 26 23 28 23 100Total 6,044 5,573 6,212 6,357 24,186 6,123 6,025 5,965 5,585 23,698Operating ExpensesLease and Well 359 348 369 378 1,454 396 390 392 394 1,572Gathering, Processing and 395 396 406 423 1,620 413 423 445 441 1,722Transportation Costs (A)Exploration Costs 50 47 43 41 181 45 34 43 52 174Dry Hole Costs 1 – – – 1 1 5 – 8 14Impairments 34 35 54 79 202 19 81 15 276 391Marketing Costs 1,361 1,456 1,383 1,509 5,709 1,404 1,490 1,500 1,323 5,717Depreciation, Depletion and 798 866 898 930 3,492 1,074 984 1,031 1,019 4,108AmortizationGeneral and Administrative 145 142 161 192 640 162 151 167 189 669Taxes Other Than Income 329 313 341 301 1,284 338 337 283 291 1,249Total 3,472 3,603 3,655 3,853 14,583 3,852 3,895 3,876 3,993 15,616Operating Income 2,572 1,970 2,557 2,504 9,603 2,271 2,130 2,089 1,592 8,082Other Income, Net 65 51 52 66 234 62 66 76 70 274Income Before Interest Expense and 2,637 2,021 2,609 2,570 9,837 2,333 2,196 2,165 1,662 8,356Income TaxesInterest Expense, Net 42 35 36 35 148 33 36 31 38 138Income Before Income Taxes 2,595 1,986 2,573 2,535 9,689 2,300 2,160 2,134 1,624 8,218Income Tax Provision 572 433 543 547 2,095 511 470 461 373 1,815Net Income 2,023 1,553 2,030 1,988 7,594 1,789 1,690 1,673 1,251 6,403Dividends Declared per Common Share 1.8250 0.8250 0.8250 2.4100 5.8850 0.9100 0.9100 0.9100 0.9750 3.7050Net Income Per ShareBasic 3.46 2.68 3.51 3.43 13.07 3.11 2.97 2.97 2.25 11.31Diluted 3.45 2.66 3.48 3.42 13.00 3.10 2.95 2.95 2.23 11.25Average Number of Common SharesBasic 584 580 579 579 581 575 569 564 557 566Diluted 587 584 583 581 584 577 572 568 561 569(A) 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.Volumes and Prices(Unaudited) 2023 2024 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr YearCrude Oil and Condensate Volumes (MBbld) (A)United States 457.1 476.0 482.8 484.6 475.2 486.8 490.1 491.8 493.5 490.6Trinidad 0.6 0.6 0.5 0.6 0.6 0.6 0.6 1.2 1.1 0.8Total 457.7 476.6 483.3 485.2 475.8 487.4 490.7 493.0 494.6 491.4Average Crude Oil and Condensate Prices($/Bbl) (B)United States $ 77.27 $ 74.98 $ 83.61 $ 80.61 $ 79.18 $ 78.46 $ 82.71 $ 76.95 $ 71.68 $ 77.42Trinidad 68.98 64.88 71.38 69.21 65.58 67.50 70.75 63.15 60.47 64.43Composite 77.26 74.97 83.60 80.60 79.17 78.45 82.69 76.92 71.66 77.40Natural Gas Liquids Volumes (MBbld) (A)United States 212.2 215.7 231.1 235.8 223.8 231.7 244.8 254.3 252.5 245.9Total 212.2 215.7 231.1 235.8 223.8 231.7 244.8 254.3 252.5 245.9Average Natural Gas Liquids Prices ($/Bbl) (B)United States $ 25.67 $ 20.85 $ 23.56 $ 22.29 $ 23.07 $ 24.32 $ 23.11 $ 22.42 $ 23.85 $ 23.40Composite 25.67 20.85 23.56 22.29 23.07 24.32 23.11 22.42 23.85 23.40Natural Gas Volumes (MMcfd) (A)United States 1,475 1,513 1,562 1,653 1,551 1,658 1,668 1,745 1,840 1,728Trinidad 164 155 142 178 160 200 204 225 252 220Total 1,639 1,668 1,704 1,831 1,711 1,858 1,872 1,970 2,092 1,948Average Natural Gas Prices ($/Mcf) (B)United States $ 3.47 $ 2.07 $ 2.59 $ 2.72 $ 2.70 $ 2.10 $ 1.57 $ 1.84 $ 2.39 $ 1.99Trinidad 3.87 3.45 3.41 3.81 3.65 3.54 3.48 3.68 3.86 3.65Composite 3.51 2.20 2.66 2.82 2.79 2.26 1.78 2.05 2.57 2.17Crude Oil Equivalent Volumes (MBoed) (C)United States 915.0 943.8 974.2 995.8 957.5 994.7 1,013.0 1,037.1 1,052.7 1,024.5Trinidad 28.0 26.5 24.3 30.4 27.3 34.1 34.5 38.6 43.0 37.6Total 943.0 970.3 998.5 1,026.2 984.8 1,028.8 1,047.5 1,075.7 1,095.7 1,062.1Total MMBoe (C) 84.9 88.3 91.9 94.4 359.4 93.6 95.3 99.0 100.8 388.7(A) Thousand barrels per day or million cubic feet per day, as applicable.(B) Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity and other derivative instruments (see Note 12 to the Consolidated Financial Statements in EOG's Annual Report on Form 10-K for the year ended December 31, 2024).(C) 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.Balance SheetsIn millions of USD (Unaudited) 2023 2024 MAR JUN SEP DEC MAR JUN SEP DECCurrent AssetsCash and Cash Equivalents 5,018 4,764 5,326 5,278 5,292 5,431 6,122 7,092Accounts Receivable, Net 2,455 2,263 2,927 2,716 2,688 2,657 2,545 2,650Inventories 1,131 1,355 1,379 1,275 1,154 1,069 1,038 985Assets from Price Risk Management Activities – – – 106 110 4 – -Other (A) 580 524 626 560 684 642 460 503Total 9,184 8,906 10,258 9,935 9,928 9,803 10,165 11,230Property, Plant and EquipmentOil and Gas Properties (Successful Efforts Method) 67,907 69,178 70,730 72,090 73,356 74,615 75,887 77,091Other Property, Plant and Equipment 5,101 5,282 5,355 5,497 5,768 6,078 6,314 6,418Total Property, Plant and Equipment 73,008 74,460 76,085 77,587 79,124 80,693 82,201 83,509Less: Accumulated Depreciation, Depletion and (42,785) (43,550) (44,362) (45,290) (46,047) (47,049) (48,075) (49,297)AmortizationTotal Property, Plant and Equipment, Net 30,223 30,910 31,723 32,297 33,077 33,644 34,126 34,212Deferred Income Taxes 31 33 33 42 38 44 42 39Other Assets 1,587 1,638 1,633 1,583 1,753 1,733 1,818 1,705Total Assets 41,025 41,487 43,647 43,857 44,796 45,224 46,151 47,186Current LiabilitiesAccounts Payable 2,438 2,205 2,464 2,437 2,389 2,436 2,290 2,464Accrued Taxes Payable 637 425 605 466 786 600 855 1,007Dividends Payable 482 478 478 526 523 516 513 539Liabilities from Price Risk Management Activities 31 22 22 – – 8 32 116Current Portion of Long-Term Debt 33 34 34 34 34 534 34 532Current Portion of Operating Lease Liabilities 354 335 337 325 318 303 338 315Other 253 232 285 286 223 231 344 381Total 4,228 3,731 4,225 4,074 4,273 4,628 4,406 5,354Long-Term Debt 3,787 3,780 3,772 3,765 3,757 3,250 3,742 4,220Other Liabilities 2,620 2,581 2,698 2,526 2,533 2,456 2,480 2,395Deferred Income Taxes 4,943 5,138 5,194 5,402 5,597 5,731 5,949 5,866Commitments and ContingenciesStockholders' EquityCommon Stock, $0.01 Par 206 206 206 206 206 206 206 206Additional Paid in Capital 6,219 6,257 6,133 6,166 6,188 6,219 6,058 6,090Accumulated Other Comprehensive Loss (8) (9) (7) (9) (8) (8) (9) (4)Retained Earnings 19,423 20,497 22,047 22,634 23,897 25,071 26,231 26,941Common Stock Held in Treasury (393) (694) (621) (907) (1,647) (2,329) (2,912) (3,882)Total Stockholders' Equity 25,447 26,257 27,758 28,090 28,636 29,159 29,574 29,351Total Liabilities and Stockholders' Equity 41,025 41,487 43,647 43,857 44,796 45,224 46,151 47,186(A) Effective October 1, 2024, EOG combined Income Taxes Receivable into the Other line item. This presentation has been conformed for all periods presented and had no impact on previously reported Total Assets.Cash Flow StatementsIn millions of USD (Unaudited) 2023 2024 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr YearCash Flows from Operating ActivitiesReconciliation of Net Income to Net CashProvided by Operating Activities:Net Income 2,023 1,553 2,030 1,988 7,594 1,789 1,690 1,673 1,251 6,403Items Not Requiring (Providing) CashDepreciation, Depletion and Amortization 798 866 898 930 3,492 1,074 984 1,031 1,019 4,108Impairments 34 35 54 79 202 19 81 15 276 391Stock-Based Compensation Expenses 34 35 57 51 177 45 45 58 51 199Deferred Income Taxes 234 194 56 199 683 199 128 220 (80) 467(Gains) Losses on Asset Dispositions, Net (69) 9 (35) – (95) (26) (20) 7 23 (16)Other, Net 4 2 (1) 22 27 9 3 2 3 17Dry Hole Costs 1 – – – 1 1 5 – 8 14Mark-to-Market Financial Commodity and Other (376) (101) (43) (298) (818) (237) 47 (79) 65 (204)Derivative Contracts (Gains) Losses, NetNet Cash Received from (Payments for) (123) (30) 23 18 (112) 55 79 61 19 214Settlements of Financial CommodityDerivative ContractsOther, Net (1) – (1) – (2) – – – – -Changes in Components of Working Capital andOther Assets and LiabilitiesAccounts Receivable 338 137 (714) 201 (38) 58 33 109 (99) 101Inventories (77) (226) (28) 100 (231) 117 75 30 37 259Accounts Payable (77) (231) 238 (49) (119) (58) 29 (159) 152 (36)Accrued Taxes Payable 232 (212) 180 (139) 61 319 (185) 256 151 541Other Assets 52 43 (92) 36 39 (161) 42 197 (34) 44Other Liabilities 193 (47) 54 (16) 184 (71) (20) 108 6 23Changes in Components of Working Capital 35 250 28 (18) 295 (229) (127) 59 (85) (382)Associated with Investing ActivitiesNet Cash Provided by Operating Activities 3,255 2,277 2,704 3,104 11,340 2,903 2,889 3,588 2,763 12,143Investing Cash FlowsAdditions to Oil and Gas Properties (1,305) (1,341) (1,379) (1,360) (5,385) (1,485) (1,357) (1,263) (1,248) (5,353)Additions to Other Property, Plant and Equipment (319) (180) (139) (162) (800) (350) (313) (239) (117) (1,019)Proceeds from Sales of Assets 92 29 14 5 140 9 10 – 4 23Changes in Components of Working Capital (35) (250) (28) 18 (295) 229 127 (59) 85 382Associated with Investing ActivitiesNet Cash Used in Investing Activities (1,567) (1,742) (1,532) (1,499) (6,340) (1,597) (1,533) (1,561) (1,276) (5,967)Financing Cash FlowsLong-Term Debt Borrowings – – – – – – – – 985 985Long-Term Debt Repayments (1,250) – – – (1,250) – – – – -Dividends Paid (1,067) (480) (494) (1,345) (3,386) (525) (520) (533) (509) (2,087)Treasury Stock Purchased (317) (302) (109) (310) (1,038) (759) (699) (795) (993) (3,246)Proceeds from Stock Options Exercised and – 9 1 10 20 – 11 – 11 22Employee Stock Purchase PlanDebt Issuance Costs – (8) – – (8) – – – (2) (2)Repayment of Finance Lease Liabilities (8) (8) (8) (8) (32) (8) (9) (8) (8) (33)Net Cash Used in Financing Activities (2,642) (789) (610) (1,653) (5,694) (1,292) (1,217) (1,336) (516) (4,361)Effect of Exchange Rate Changes on Cash – – – – – – – – (1) (1)Increase (Decrease) in Cash and Cash Equivalents (954) (254) 562 (48) (694) 14 139 691 970 1,814Cash and Cash Equivalents at Beginning of Period 5,972 5,018 4,764 5,326 5,972 5,278 5,292 5,431 6,122 5,278Cash and Cash Equivalents at End of Period 5,018 4,764 5,326 5,278 5,278 5,292 5,431 6,122 7,092 7,092 Non-GAAP Financial Measures To supplement the presentation of its financial results prepared in accordance with generally accepted accounting principles in the United States of America (GAAP), EOG's quarterly earnings releases and related conference calls, accompanying investor presentation slides and presentation slides for investor conferences contain certain financial measures that are not prepared or presented in accordance with GAAP. These non-GAAP financial measures may include, but are not limited to, Adjusted Net Income (Loss), Cash Flow from Operations Before Changes in Working Capital, Free Cash Flow, Net Debt and related statistics. A reconciliation of each of these measures to their most directly comparable GAAP financial measure and related discussion is included in the tables on the following pages and can also be found in the “Reconciliations & Guidance” section of the “Investors” page of the EOG website at www.eogresources.com. As further discussed in the tables on the following pages, EOG believes these measures may be useful to investors who follow the practice of some industry analysts who make certain adjustments to GAAP measures (for example, to exclude non-recurring items) to facilitate comparisons to others in EOG's industry, and who utilize non-GAAP measures in their calculations of certain statistics (for example, return on capital employed and return on equity) used to evaluate EOG's performance. EOG believes that the non-GAAP measures presented, when viewed in combination with its financial results prepared in accordance with GAAP, provide a more complete understanding of the factors and trends affecting the company's performance. As is discussed in the tables on the following pages, EOG uses these non-GAAP measures for purposes of (i) comparing EOG's financial performance with the financial performance of other companies in the industry and (ii) analyzing EOG's financial performance across periods. The non-GAAP measures presented should not be considered in isolation, and should not be considered as a substitute for, or as an alternative to, EOG's reported Net Income (Loss), Long-Term Debt (including Current Portion of Long-Term Debt), Net Cash Provided by Operating Activities and other financial results calculated in accordance with GAAP. The non-GAAP measures presented should be read in conjunction with EOG's consolidated financial statements prepared in accordance with GAAP. In addition, because not all companies use identical calculations, EOG's presentation of non-GAAP measures may not be comparable to, and may be calculated differently from, similarly titled measures disclosed by other companies, including its peer companies. EOG may also change the calculation of one or more of its non-GAAP measures from time to time – for example, to account for changes in its business and operations or to more closely conform to peer company or industry analysts' practices. Direct ATROR The calculation of EOG's direct after-tax rate of return (ATROR) is based on EOG's net estimated recoverable reserves for a particular well(s) or play, the estimated net present value of the future net cash flows from such reserves (for which EOG utilizes certain assumptions regarding future commodity prices and operating costs) and EOG's direct net costs incurred in drilling or acquiring such well(s). As such, EOG's direct ATROR for a particular well(s) or play cannot be calculated from EOG's consolidated financial statements.Adjusted Net IncomeIn millions of USD, except share data (in millions) and per share data (Unaudited)The following tables adjust reported Net Income (Loss) (GAAP) to reflect actual net cash received from (payments for) settlements of financial commodity derivative contracts by eliminating the net unrealized mark-to-market (gains) losses from these and other derivative transactions, to eliminate the net (gains) losses on asset dispositions, to add back impairment charges related to certain of EOG's assets (which are generally (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)), and to make certain other adjustments to exclude non-recurring and certain other items as further described below. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. 4Q 2024 Before Income Tax After Diluted Tax Impact Tax Earnings per ShareReported Net Income (GAAP) 1,624 (373) 1,251 2.23Adjustments:Losses on Mark-to-Market Financial Commodity and Other Derivative 65 (14) 51 0.10Contracts, NetNet Cash Received from Settlements of Financial Commodity Derivative 19 (4) 15 0.03Contracts (1)Add: Losses on Asset Dispositions, Net 23 (4) 19 0.03Add: Certain Impairments 254 (55) 199 0.35Adjustments to Net Income 361 (77) 284 0.51Adjusted Net Income (Non-GAAP) 1,985 (450) 1,535 2.74Average Number of Common SharesBasic 557Diluted 561(1) Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG adds to reported Net Income (GAAP) the total net cash received from settlements of financial commodity derivative contracts during such period. For the three months ended December 31, 2024, such amount was $19 million.Adjusted Net Income(Continued)In millions of USD, except share data (in millions) and per share data (Unaudited) 3Q 2024 Before Income Tax After Diluted Tax Impact Tax Earnings per ShareReported Net Income (GAAP) 2,134 (461) 1,673 2.95Adjustments:Gains on Mark-to-Market Financial Commodity and Other Derivative (79) 17 (62) (0.11)Contracts, NetNet Cash Received from Settlements of Financial Commodity Derivative 61 (13) 48 0.08Contracts (1)Add: Losses on Asset Dispositions, Net 7 (2) 5 0.01Less: Severance Tax Refund (31) 7 (24) (0.04)Add: Severance Tax Consulting Fees 10 (2) 8 0.01Less: Interest on Severance Tax Refund (5) 1 (4) (0.01)Adjustments to Net Income (37) 8 (29) (0.06)Adjusted Net Income (Non-GAAP) 2,097 (453) 1,644 2.89Average Number of Common SharesBasic 564Diluted 568(1) Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG adds to reported Net Income (GAAP) the total net cash received from settlements of financial commodity derivative contracts during such period. For the three months ended September 30, 2024, such amount was $61 million.Adjusted Net Income(Continued)In millions of USD, except share data (in millions) and per share data (Unaudited) 2Q 2024 Before Income Tax After Diluted Tax Impact Tax Earnings per ShareReported Net Income (GAAP) 2,160 (470) 1,690 2.95Adjustments:Losses on Mark-to-Market Financial Commodity and Other Derivative 47 (10) 37 0.07Contracts, NetNet Cash Received from Settlements of Financial Commodity Derivative 79 (17) 62 0.11Contracts (1)Less: Gains on Asset Dispositions, Net (20) 5 (15) (0.03)Add: Certain Impairments 35 (2) 33 0.06Adjustments to Net Income 141 (24) 117 0.21Adjusted Net Income (Non-GAAP) 2,301 (494) 1,807 3.16Average Number of Common SharesBasic 569Diluted 572(1) Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG adds to reported Net Income (GAAP) the total net cash received from settlements of financial commodity derivative contracts during such period. For the three months ended June 30, 2024, such amount was $79 million.Adjusted Net Income(Continued)In millions of USD, except share data (in millions) and per share data (Unaudited) 1Q 2024 Before Income Tax After Diluted Tax Impact Tax Earnings per ShareReported Net Income (GAAP) 2,300 (511) 1,789 3.10Adjustments:Gains on Mark-to-Market Financial Commodity and Other Derivative (237) 51 (186) (0.31)Contracts, NetNet Cash Received from Settlements of Financial Commodity Derivative 55 (12) 43 0.07Contracts (1)Less: Gains on Asset Dispositions, Net (26) 4 (22) (0.04)Add: Certain Impairments 2 – 2 -Adjustments to Net Income (206) 43 (163) (0.28)Adjusted Net Income (Non-GAAP) 2,094 (468) 1,626 2.82Average Number of Common SharesBasic 575Diluted 577(1) Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG adds to reported Net Income (GAAP) the total net cash received from settlements of financial commodity derivative contracts during such period. For the three months ended March 31, 2024, such amount was $55 million.Adjusted Net Income(Continued)In millions of USD, except share data (in millions) and per share data (Unaudited) 4Q 2023 Before Income Tax After Diluted Tax Impact Tax Earnings per ShareReported Net Income (GAAP) 2,535 (547) 1,988 3.42Adjustments:Gains on Mark-to-Market Financial Commodity Derivative (298) 64 (234) (0.40)Contracts, NetNet Cash Received from Settlements of Financial Commodity Derivative 18 (4) 14 0.02Contracts (1)Add: Certain Impairments 19 (4) 15 0.03Adjustments to Net Income (261) 56 (205) (0.35)Adjusted Net Income (Non-GAAP) 2,274 (491) 1,783 3.07Average Number of Common SharesBasic 579Diluted 581(1) Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG adds to reported Net Income (GAAP) the total net cash received from settlements of financial commodity derivative contracts during such period. For the three months ended December 31, 2023, such amount was $18 million.Adjusted Net Income(Continued)In millions of USD, except share data (in millions) and per share data (Unaudited) FY 2024 Before Income Tax After Diluted Tax Impact Tax Earnings per ShareReported Net Income (GAAP) 8,218 (1,815) 6,403 11.25Adjustments:Gains on Mark-to-Market Financial Commodity and Other Derivative (204) 44 (160) (0.28)Contracts, NetNet Cash Received from Settlements of Financial Commodity Derivative 214 (46) 168 0.30Contracts (1)Less: Gains on Asset Dispositions, Net (16) 3 (13) (0.02)Add: Certain Impairments 291 (57) 234 0.41Less: Severance Tax Refund (31) 7 (24) (0.04)Add: Severance Tax Consulting Fees 10 (2) 8 0.01Less: Interest on Severance Tax Refund (5) 1 (4) (0.01)Adjustments to Net Income 259 (50) 209 0.37Adjusted Net Income (Non-GAAP) 8,477 (1,865) 6,612 11.62Average Number of Common SharesBasic 566Diluted 569(1) Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG adds to reported Net Income (GAAP) the total net cash received from settlements of financial commodity derivative contracts during such period. For the twelve months ended December 31, 2024, such amount was $214 million.Adjusted Net Income(Continued)In millions of USD, except share data (in millions) and per share data (Unaudited) FY 2023 Before Income Tax After Diluted Tax Impact Tax Earnings per ShareReported Net Income (GAAP) 9,689 (2,095) 7,594 13.00Adjustments:Gains on Mark-to-Market Financial Commodity Derivative (818) 176 (642) (1.09)Contracts, NetNet Cash Payments for Settlements of Financial Commodity Derivative (112) 24 (88) (0.15)Contracts (1)Less: Gains on Asset Dispositions, Net (95) 20 (75) (0.13)Add: Certain Impairments 42 (6) 36 0.06Adjustments to Net Income (983) 214 (769) (1.31)Adjusted Net Income (Non-GAAP) 8,706 (1,881) 6,825 11.69Average Number of Common SharesBasic 581Diluted 584(1) Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG subtracts from reported Net Income (GAAP) the total net cash paid for settlements of financial commodity derivative contracts during such period. For the twelve months ended December 31, 2023, such amount was $112 million.Net Income per ShareIn millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited)3Q 2024 Net Income per Share (GAAP) – Diluted 2.95Realized Price4Q 2024 Composite Average Wellhead Revenue per Boe 42.74Less: 3Q 2024 Composite Average Wellhead Revenue per Boe (44.31)Subtotal (1.57)Multiplied by: 4Q 2024 Crude Oil Equivalent Volumes (MMBoe) 100.8Total Change in Revenue (158)Add: Income Tax Benefit (Provision) Imputed (based on 22%) 35Change in Net Income (123)Change in Diluted Earnings per Share (0.22)Volumes4Q 2024 Crude Oil Equivalent Volumes (MMBoe) 100.8Less: 3Q 2024 Crude Oil Equivalent Volumes (MMBoe) (99.0)Subtotal 1.8Multiplied by: 4Q 2024 Composite Average Margin per Boe (GAAP) (Including Total 15.88Exploration Costs) (refer to “Revenues, Costs and Margins Per Barrel of Oil Equivalent”schedule below)Change in Margin 29Less: Income Tax Benefit (Provision) Imputed (based on 22%) (6)Change in Net Income 23Change in Diluted Earnings per Share 0.04Certain Operating Costs per Boe3Q 2024 Total Cash Operating Costs (GAAP) and Total DD&A per Boe 20.57Less: 4Q 2024 Total Cash Operating Costs (GAAP) and Total DD&A per Boe (20.26)Subtotal 0.31Multiplied by: 4Q 2024 Crude Oil Equivalent Volumes (MMBoe) 100.8Change in Before-Tax Net Income 31Less: Income Tax Benefit (Provision) Imputed (based on 22%) (7)Change in Net Income 24Change in Diluted Earnings per Share 0.04Net Income Per Share(Continued)In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited)Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net4Q 2024 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts (65)Less: Income Tax Benefit (Provision) 14After Tax – (a) (51)Less: 3Q 2024 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts 79Less: Income Tax Benefit (Provision) (17)After Tax – (b) 62Change in Net Income – (a) – (b) (113)Change in Diluted Earnings per Share (0.20)Other (1) (0.38)4Q 2024 Net Income per Share (GAAP) – Diluted 2.234Q 2024 Average Number of Common Shares – Diluted 561(1) Includes gathering, processing and marketing revenue, gains (losses) on asset dispositions, other revenue, exploration, dry hole, impairments and marketing costs, taxes other than income, other income (expense), interest expense and the impact of changes in the effective income tax rate.Net Income per ShareIn millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited)FY 2023 Net Income per Share (GAAP) 13.00Realized PriceFY 2024 Composite Average Wellhead Revenue per Boe 45.22Less: FY 2023 Composite Average Wellhead Revenue per Boe (48.34)Subtotal (3.12)Multiplied by: FY 2024 Crude Oil Equivalent Volumes (MMBoe) 388.7Total Change in Revenue (1,213)Add: Income Tax Benefit (Provision) Imputed (based on 22%) 267Change in Net Income (946)Change in Diluted Earnings per Share (1.66)VolumesFY 2024 Crude Oil Equivalent Volumes (MMBoe) 388.7Less: FY 2023 Crude Oil Equivalent Volumes (MMBoe) (359.4)Subtotal 29.3Multiplied by: FY 2024 Composite Average Margin per Boe (GAAP) (Including Total 19.40Exploration Costs) (refer to “Revenues, Costs and Margins Per Barrel of Oil Equivalent”schedule below)Change in Margin 568Add: Income Tax Benefit (Provision) Imputed (based on 22%) (125)Change in Net Income 443Change in Diluted Earnings per Share 0.78Certain Operating Costs per BoeFY 2023 Total Cash Operating Costs (GAAP) and Total DD&A per Boe 20.05Less: FY 2024 Total Cash Operating Costs (GAAP) and Total DD&A per Boe (20.76)Subtotal (0.71)Multiplied by: FY 2024 Crude Oil Equivalent Volumes (MMBoe) 388.7Change in Before-Tax Net Income (276)Add: Income Tax Benefit (Provision) Imputed (based on 22%) 61Change in Net Income (215)Change in Diluted Earnings per Share (0.38)Net Income Per Share(Continued)In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited)Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts, NetFY 2024 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative 204ContractsLess: Income Tax Benefit (Provision) (44)After Tax – (a) 160Less: FY 2023 Net Gains (Losses) on Mark-to-Market Commodity and Other Derivative Contracts 818Less: Income Tax Benefit (Provision) (176)After Tax – (b) 642Change in Net Income – (a) – (b) (482)Change in Diluted Earnings per Share (0.85)Other (1) 0.36FY 2024 Net Income per Share (GAAP) – Diluted 11.25FY 2024 Average Number of Common Shares – Diluted 569(1) Includes gathering, processing and marketing revenue, gains (losses) on asset dispositions, other revenue, exploration, dry hole, impairments and marketing costs, taxes other than income, other income (expense), interest expense and the impact of changes in the effective income tax rate.Adjusted Net Income Per ShareIn millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited)3Q 2024 Adjusted Net Income per Share (Non-GAAP) – Diluted 2.89Realized Price4Q 2024 Composite Average Wellhead Revenue per Boe 42.74Less: 3Q 2024 Composite Average Wellhead Revenue per Boe (44.31)Subtotal (1.57)Multiplied by: 4Q 2024 Crude Oil Equivalent Volumes (MMBoe) 100.8Total Change in Revenue (158)Add: Income Tax Benefit (Provision) Imputed (based on 22%) 35Change in Net Income (123)Change in Diluted Earnings per Share (0.22)Volumes4Q 2024 Crude Oil Equivalent Volumes (MMBoe) 100.8Less: 3Q 2024 Crude Oil Equivalent Volumes (MMBoe) (99.0)Subtotal 1.8Multiplied by: 4Q 2024 Composite Average Margin per Boe (Non-GAAP) (Including Total 18.40Exploration Costs) (refer to “Revenues, Costs and Margins Per Barrel of Oil Equivalent”schedule below)Change in Margin 33Add: Income Tax Benefit (Provision) Imputed (based on 22%) (7)Change in Net Income 26Change in Diluted Earnings per Share 0.05Certain Operating Costs per Boe3Q 2024 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe 20.47Less: 4Q 2024 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe (20.26)Subtotal 0.21Multiplied by: 4Q 2024 Crude Oil Equivalent Volumes (MMBoe) 100.8Change in Before-Tax Net Income 21Add: Income Tax Benefit (Provision) Imputed (based on 22%) (5)Change in Net Income 16Change in Diluted Earnings per Share 0.03Adjusted Net Income Per Share(Continued)In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited)Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts4Q 2024 Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative 19ContractsLess: Income Tax Benefit (Provision) (4)After Tax – (a) 153Q 2024 Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative 61ContractsLess: Income Tax Benefit (Provision) (13)After Tax – (b) 48Change in Net Income – (a) – (b) (33)Change in Diluted Earnings per Share (0.06)Other (1) 0.054Q 2024 Adjusted Net Income per Share (Non-GAAP) 2.744Q 2024 Average Number of Common Shares – Diluted 561(1) Includes gathering, processing and marketing revenue, other revenue, exploration, dry hole, impairments and marketing costs, taxes other than income, other income (expense), interest expense and the impact of changes in the effective income tax rate.Adjusted Net Income per ShareIn millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited)FY 2023 Adjusted Net Income per Share (Non-GAAP) 11.69Realized PriceFY 2024 Composite Average Wellhead Revenue per Boe 45.22Less: FY 2023 Composite Average Wellhead Revenue per Boe (48.34)Subtotal (3.12)Multiplied by: FY 2024 Crude Oil Equivalent Volumes (MMBoe) 388.7Total Change in Revenue (1,213)Add: Income Tax Benefit (Provision) Imputed (based on 22%) 267Change in Net Income (946)Change in Diluted Earnings per Share (1.66)VolumesFY 2024 Crude Oil Equivalent Volumes (MMBoe) 388.7Less: FY 2023 Crude Oil Equivalent Volumes (MMBoe) (359.4)Subtotal 29.3Multiplied by: FY 2024 Composite Average Margin per Boe (Non-GAAP) 20.09(Including Total Exploration Costs) (refer to “Revenues, Costs and Margins Per Barrel of Oil Equivalent”schedule below)Change in Margin 589Less: Income Tax Benefit (Provision) Imputed (based on 22%) (130)Change in Net Income 459Change in Diluted Earnings per Share 0.81Certain Operating Costs per BoeFY 2023 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe 20.05Less: FY 2024 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe (20.74)Subtotal (0.69)Multiplied by: FY 2024 Crude Oil Equivalent Volumes (MMBoe) 388.7Change in Before-Tax Net Income (268)Add: Income Tax Benefit (Provision) Imputed (based on 22%) 59Change in Net Income (209)Change in Diluted Earnings per Share (0.37)Adjusted Net Income Per Share(Continued)In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited)Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative ContractsFY 2024 Net Cash Received from (Payments for) Settlement of Financial Commodity Derivative Contracts 214Less: Income Tax Benefit (Provision) (46)After Tax – (a) 168FY 2023 Net Cash Received from (Payments for) Settlement of Financial Commodity Derivative Contracts (112)Less: Income Tax Benefit (Provision) 24After Tax – (b) (88)Change in Net Income – (a) – (b) 256Change in Diluted Earnings per Share 0.45Other (1) 0.70FY 2024 Adjusted Net Income per Share (Non-GAAP) 11.62FY 2024 Average Number of Common Shares (Non-GAAP) – Diluted 569(1) Includes gathering, processing and marketing revenue, other revenue, exploration, dry hole, impairments and marketing costs, taxes other than income, other income (expense), interest expense and the impact of changes in the effective income tax rate.Cash Flow from Operations and Free Cash FlowIn millions of USD (Unaudited)The following tables reconcile Net Cash Provided by Operating Activities (GAAP) to Cash Flow from Operations Before Changes in Working Capital (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Changes in Components of Working Capital and Other Assets and Liabilities, Changes in Components of Working Capital Associated with Investing Activities and certain other adjustments to exclude non-recurring and certain other items as further described below. EOG defines Free Cash Flow (Non-GAAP) for a given period as Cash Flow from Operations Before Changes in Working Capital (Non-GAAP) (see below reconciliation) for such period less the Total Capital Expenditures (Non-GAAP) during such period, as is illustrated below. EOG management uses this information for comparative purposes within the industry. 2023 2024 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr YearNet Cash Provided by Operating Activities (GAAP) 3,255 2,277 2,704 3,104 11,340 2,903 2,889 3,588 2,763 12,143Adjustments:Changes in Components of Working Capital and Other Assets and LiabilitiesAccounts Receivable (338) (137) 714 (201) 38 (58) (33) (109) 99 (101)Inventories 77 226 28 (100) 231 (117) (75) (30) (37) (259)Accounts Payable 77 231 (238) 49 119 58 (29) 159 (152) 36Accrued Taxes Payable (232) 212 (180) 139 (61) (319) 185 (256) (151) (541)Other Assets (52) (43) 92 (36) (39) 161 (42) (197) 34 (44)Other Liabilities (193) 47 (54) 16 (184) 71 20 (108) (6) (23)Changes in Components of Working Capital Associated with Investing Activities (35) (250) (28) 18 (295) 229 127 (59) 85 382Cash Flow from Operations Before Changes in Working Capital (Non-GAAP) 2,559 2,563 3,038 2,989 11,149 2,928 3,042 2,988 2,635 11,593Less:Total Capital Expenditures (Non-GAAP) (a) (1,489) (1,521) (1,519) (1,512) (6,041) (1,703) (1,668) (1,497) (1,358) (6,226)Free Cash Flow (Non-GAAP) 1,070 1,042 1,519 1,477 5,108 1,225 1,374 1,491 1,277 5,367(a) See below reconciliation of Total Expenditures (GAAP) to Total Capital Expenditures (Non-GAAP): 2023 2024 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr YearTotal Expenditures (GAAP) 1,717 1,664 1,803 1,634 6,818 1,952 1,682 1,573 1,446 6,653Less:Asset Retirement Costs (10) (26) (191) (30) (257) (21) 60 (11) (26) 2Non-Cash Development Drilling – (35) (50) (5) (90) – – – – -Non-Cash Acquisition Costs of (31) (28) (1) (39) (99) (31) (34) (17) (3) (85)Unproved PropertiesAcquisition Costs of Proved Properties (4) (6) 1 (7) (16) (21) (5) – (7) (33)Acquisition Costs of Other Property, (133) (1) – – (134) (131) (1) (5) – (137)Plant and EquipmentExploration Costs (50) (47) (43) (41) (181) (45) (34) (43) (52) (174)Total Capital Expenditures (Non-GAAP) 1,489 1,521 1,519 1,512 6,041 1,703 1,668 1,497 1,358 6,226Net Debt-to-Total Capitalization RatioIn millions of USD, except ratio data (Unaudited)The following tables reconcile Current and Long-Term Debt (GAAP) to Net Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization (Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio calculation. A portion of the cash is associated with international subsidiaries; tax considerations may impact debt paydown. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who utilize Net Debt and Total Capitalization (Non-GAAP) in their Net Debt-to-Total Capitalization ratio calculation. EOG management uses this information for comparative purposes within the industry. December 31, September 30, June 30, March 31, December 31, 2024 2024 2024 2024 2023Total Stockholders' Equity – (a) 29,351 29,574 29,159 28,636 28,090Current and Long-Term Debt (GAAP) – (b) 4,752 3,776 3,784 3,791 3,799Less: Cash (7,092) (6,122) (5,431) (5,292) (5,278)Net Debt (Non-GAAP) – (c) (2,340) (2,346) (1,647) (1,501) (1,479)Total Capitalization (GAAP) – (a) + (b) 34,103 33,350 32,943 32,427 31,889Total Capitalization (Non-GAAP) – (a) + (c) 27,011 27,228 27,512 27,135 26,611Debt-to-Total Capitalization (GAAP) – (b) / [(a) + (b)] 13.9% 11.3% 11.5% 11.7% 11.9%Net Debt-to-Total Capitalization (Non-GAAP) – (c) / [(a) + (c)] -8.7% -8.6% -6.0% -5.5% -5.6%Proved Reserves and Reserve Replacement Data(Unaudited)2024 Net Proved Reserves Reconciliation Summary United Trinidad Other Total States InternationalCrude Oil and Condensate (MMBbl)Beginning Reserves 1,754 2 – 1,756Revisions 71 – – 71Purchases in Place 3 – – 3Extensions, Discoveries and Other Additions 228 – – 228Sales in Place (8) – – (8)Production (180) – – (180)Ending Reserves 1,868 2 – 1,870Natural Gas Liquids (MMBbl)Beginning Reserves 1,254 – – 1,254Revisions 31 – – 31Purchases in Place 2 – – 2Extensions, Discoveries and Other Additions 164 – – 164Sales in Place (3) – – (3)Production (90) – – (90)Ending Reserves 1,358 – – 1,358Natural Gas (Bcf)Beginning Reserves 8,630 300 – 8,930Revisions (202) 2 – (200)Purchases in Place 10 – – 10Extensions, Discoveries and Other Additions 1,098 23 – 1,121Sales in Place (14) – – (14)Production (644) (81) – (725)Ending Reserves 8,878 244 – 9,122Oil Equivalents (MMBoe)Beginning Reserves 4,447 51 – 4,498Revisions 68 1 – 69Purchases in Place 6 – – 6Extensions, Discoveries and Other Additions 576 4 – 580Sales in Place (14) – – (14)Production (377) (14) – (391)Ending Reserves 4,706 42 – 4,748Net Proved Developed Reserves (MMBoe)At December 31, 2023 2,322 27 – 2,349At December 31, 2024 2,542 24 – 2,5662024 Exploration and Development Expenditures ($ Millions)Acquisition Cost of Unproved Properties 229 – 1 230Exploration Costs 286 115 28 429Development Costs 4,820 124 – 4,944Total Drilling 5,335 239 29 5,603Acquisition Cost of Proved Properties 33 – – 33Asset Retirement Costs (37) 8 27 (2)Total Exploration and Development Expenditures 5,331 247 56 5,634Gathering, Processing and Other 1,017 2 – 1,019Total Expenditures 6,348 249 56 6,653Proceeds from Sales in Place (23) – – (23)Net Expenditures 6,325 249 56 6,630Reserve Replacement Costs ($ / Boe) *All-in Total, Net of Revisions 7.85 47.00 – 8.17All-in Total, Excluding Revisions Due to Price 6.41 47.00 – 6.68Reserve Replacement *Drilling Only 153% 29% 0% 148%All-in Total, Net of Revisions and Dispositions 169% 36% 0% 164%All-in Total, Excluding Revisions Due to Price 207% 36% 0% 201%All-in Total, Liquids 181% 0% 0% 181%* See following reconciliation schedule for calculation methodologyReserve Replacement Cost Data(Unaudited; in millions, except ratio data)For the Twelve Months Ended December 31, 2024 United Trinidad Other Total States InternationalTotal Costs Incurred in Exploration and Development Activities (GAAP) 5,331 247 56 5,634Less: Asset Retirement Costs 37 (8) (27) 2Non-Cash Acquisition Costs of Unproved Properties (85) – – (85)Total Acquisition Costs of Proved Properties (33) – – (33)Exploration Expenses (154) (4) (16) (174)Total Exploration and Development Expenditures for Drilling Only (Non- 5,096 235 13 5,344GAAP) – (a)Total Costs Incurred in Exploration and Development Activities (GAAP) 5,331 247 56 5,634Less: Asset Retirement Costs 37 (8) (27) 2Non-Cash Acquisition Costs of Unproved Properties (85) – – (85)Non-Cash Acquisition Costs of Proved Properties (24) – – (24)Exploration Expenses (154) (4) (16) (174)Total Exploration and Development Expenditures (Non-GAAP) – (b) 5,105 235 13 5,353Total Expenditures (GAAP) 6,348 249 56 6,653Less: Asset Retirement Costs 37 (8) (27) 2Non-Cash Acquisition Costs of Unproved Properties (85) – – (85)Non-Cash Acquisition Costs of Proved Properties (24) – – (24)Exploration Expenses (154) (4) (16) (174)Total Cash Expenditures (Non-GAAP) 6,122 237 13 6,372Net Proved Reserve Additions From All Sources – Oil Equivalents (MMBoe)Revisions Due to Price – (c) (146) – – (146)Revisions Other Than Price 214 1 – 215Purchases in Place 6 – – 6Extensions, Discoveries and Other Additions – (d) 576 4 – 580Total Proved Reserve Additions – (e) 650 5 – 655Sales in Place (14) – – (14)Net Proved Reserve Additions From All Sources – (f) 636 5 – 641Production – (g) 377 14 – 391Reserve Replacement Costs ($ / Boe)Total Drilling, Before Revisions – (a / d) 8.85 58.75 – 9.21All-in Total, Net of Revisions – (b / e) 7.85 47.00 – 8.17All-in Total, Excluding Revisions Due to Price – (b / (e – c)) 6.41 47.00 – 6.68Reserve ReplacementDrilling Only – (d / g) 153% 29% 0% 148%All-in Total, Net of Revisions and Dispositions – (f / g) 169% 36% 0% 164%All-in Total, Excluding Revisions Due to Price – ((f – c) / g) 207% 36% 0% 201%Reserve Replacement Cost Data(Continued)(Unaudited; in millions, except ratio data)For the Twelve Months Ended December 31, 2024 United Trinidad Other Total States InternationalNet Proved Reserve Additions From All Sources – Liquids (MMBbl)Revisions 102 – – 102Purchases in Place 5 – – 5Extensions, Discoveries and Other Additions – (h) 392 – – 392Total Proved Reserve Additions 499 – – 499Sales in Place (11) – – (11)Net Proved Reserve Additions From All Sources – (i) 488 – – 488Production – (j) 270 – – 270Reserve Replacement – LiquidsDrilling Only – (h / j) 145% 0% 0% 145%All-in Total, Net of Revisions and Dispositions – (i / j) 181% 0% 0% 181%Reserve Replacement Cost Data(Continued)(Unaudited; in millions, except ratio data)For the Twelve Months Ended December 31, 2024Proved Developed Reserve Replacement Costs ($ / Boe) TotalTotal Costs Incurred in Exploration and Development Activities (GAAP) – (k) 5,634Less: Asset Retirement Costs 2Acquisition Costs of Unproved Properties (230)Acquisition Costs of Proved Properties (33)Exploration Expenses (174)Drillbit Exploration and Development Expenditures (Non-GAAP) – (l) 5,199Total Proved Reserves – Extensions, Discoveries and Other Additions (MMBoe) 580Add: Conversion of Proved Undeveloped Reserves to Proved Developed 370Less: Proved Undeveloped Extensions and Discoveries (479)Proved Developed Reserves – Extensions and Discoveries (MMBoe) 471Total Proved Reserves – Revisions (MMBoe) 69Less: Proved Undeveloped Reserves – Revisions 66Proved Developed – Revisions Due to Price 41Proved Developed Reserves – Revisions Other Than Price (MMBoe) 176Proved Developed Reserves – Extensions and Discoveries Plus Revisions Other Than Price (MMBoe) – (m) 647Proved Developed Reserve Replacement Costs Excluding Revisions Due to Price ($ / Boe) (GAAP) – (k / m) 8.71Proved Developed Reserve Replacement Costs Excluding Revisions Due to Price ($ / Boe) (Non-GAAP) – (l / m) 8.04Reserve Replacement Cost DataIn millions of USD, except reserves and ratio data (Unaudited)The following table reconciles Total Costs Incurred in Exploration and Development Activities (GAAP) to Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) and Total Exploration and Development Expenditures (Non-GAAP), as used in the calculation of Reserve Replacement Costs per Boe. There are numerous ways that industry participants present Reserve Replacement Costs, including “Drilling Only” and “All-In”, which reflect total exploration and development expenditures divided by total net proved reserve additions from extensions and discoveries only, or from all sources. Combined with Reserve Replacement, these statistics (and the non-GAAP measures used in calculating such statistics) provide management and investors with an indication of the results of the current year capital investment program. Reserve Replacement Cost statistics (and the non-GAAP measures used in calculating such statistics) are widely recognized and reported by industry participants and are used by EOG management and other third parties for comparative purposes within the industry. Please note that the actual cost of adding reserves will vary from the reported statistics due to timing differences in reserve bookings and capital expenditures. Accordingly, some analysts use three or five year averages of reported statistics, while others prefer to estimate future costs. EOG has not included future capital costs to develop proved undeveloped reserves in exploration and development expenditures. 2024 2023 2022 2021Total Costs Incurred in Exploration and Development Activities (GAAP) 5,634 6,018 5,229 3,969Less: Asset Retirement Costs 2 (257) (298) (127)Non-Cash Acquisition Costs of Unproved Properties (85) (99) (127) (45)Total Acquisition Costs of Proved Properties (33) (16) (419) (100)Non-Cash Development Drilling – (90) – -Exploration Expenses (174) (181) (159) (154)Total Exploration and Development Expenditures for Drilling Only (Non- 5,344 5,375 4,226 3,543GAAP) – (a)Total Costs Incurred in Exploration and Development Activities (GAAP) – (b) 5,634 6,018 5,229 3,969Less: Asset Retirement Costs 2 (257) (298) (127)Non-Cash Acquisition Costs of Unproved Properties (85) (99) (127) (45)Non-Cash Acquisition Costs of Proved Properties (24) (6) (26) (5)Non-Cash Development Drilling – (90) – -Exploration Expenses (174) (181) (159) (154)Total Exploration and Development Expenditures (Non-GAAP) – (c) 5,353 5,385 4,619 3,638Net Proved Reserve Additions From All Sources – Oil Equivalents (MMBoe)Revisions Due to Price – (d) (146) (110) 11 194Revisions Other Than Price 215 139 325 (308)Purchases in Place 6 2 16 9Extensions, Discoveries and Other Additions – (e) 580 607 560 952Total Proved Reserve Additions – (f) 655 638 912 847Sales in Place (14) (17) (88) (11)Net Proved Reserve Additions From All Sources 641 621 824 836Production 391 361 333 309Reserve Replacement Costs ($ / Boe)Total Drilling, Before Revisions – (a / e) 9.21 8.86 7.55 3.72All-in Total, Net of Revisions – (c / f) 8.17 8.44 5.06 4.30All-in Total, Excluding Revisions Due to Price (GAAP) – (b / ( f – d)) 7.03 8.05 5.80 6.08All-in Total, Excluding Revisions Due to Price (Non-GAAP) – (c / ( f – d)) 6.68 7.20 5.13 5.57Reserve Replacement Cost Data(Continued)In millions of USD, except reserves and ratio data (Unaudited) 2020 2019 2018Total Costs Incurred in Exploration and Development Activities (GAAP) 3,718 6,628 6,420Less: Asset Retirement Costs (117) (186) (70)Non-Cash Acquisition Costs of Unproved Properties (197) (98) (291)Total Acquisition Costs of Proved Properties (135) (380) (124)Exploration Expenses (146) (140) (149)Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) – (a) 3,123 5,824 5,786Total Costs Incurred in Exploration and Development Activities (GAAP) – (b) 3,718 6,628 6,420Less: Asset Retirement Costs (117) (186) (70)Non-Cash Acquisition Costs of Unproved Properties (197) (98) (291)Non-Cash Acquisition Costs of Proved Properties (15) (52) (71)Exploration Expenses (146) (140) (149)Total Exploration and Development Expenditures (Non-GAAP) – (c) 3,243 6,152 5,839Net Proved Reserve Additions From All Sources – Oil Equivalents (MMBoe)Revisions Due to Price – (d) (278) (60) 35Revisions Other Than Price (89) – (40)Purchases in Place 10 17 12Extensions, Discoveries and Other Additions – (e) 564 750 670Total Proved Reserve Additions – (f) 207 707 677Sales in Place (31) (5) (11)Net Proved Reserve Additions From All Sources 176 702 666Production 285 301 265Reserve Replacement Costs ($ / Boe)Total Drilling, Before Revisions – (a / e) 5.54 7.77 8.64All-in Total, Net of Revisions – (c / f) 15.67 8.70 8.62All-in Total, Excluding Revisions Due to Price (GAAP) – (b / ( f – d)) 7.67 8.64 10.00All-in Total, Excluding Revisions Due to Price (Non-GAAP) – (c / ( f – d)) 6.69 8.02 9.10Definitions$/Boe U.S. Dollars per barrel of oil equivalentMMBoe Million barrels of oil equivalentRevenues, Costs and Margins Per Barrel of Oil EquivalentIn millions of USD, except Boe and per Boe amounts (Unaudited)EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who review certain components and/or groups of components of revenues, costs and/or margins per barrel of oil equivalent (Boe). Certain of these components are adjusted for non-recurring and certain other items, as further discussed below. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. 4Q 2024 3Q 2024 2Q 2024 1Q 2024 4Q 2023Volume – Million Barrels of Oil Equivalent – (a) 100.8 99.0 95.3 93.6 94.4Total Operating Revenues and Other (b) 5,585 5,965 6,025 6,123 6,357Total Operating Expenses (c) 3,993 3,876 3,895 3,852 3,853Operating Income (d) 1,592 2,089 2,130 2,271 2,504Wellhead RevenuesCrude Oil and Condensate 3,261 3,488 3,692 3,480 3,597Natural Gas Liquids 554 524 515 513 484Natural Gas 494 372 303 382 476Total Wellhead Revenues – (e) 4,309 4,384 4,510 4,375 4,557Operating CostsLease and Well 394 392 390 396 378Gathering, Processing and Transportation Costs (1) 441 445 423 413 423General and Administrative (GAAP) 189 167 151 162 192Less: Severance Tax Consulting Fees – (10) – – -General and Administrative (Non-GAAP) (3) 189 157 151 162 192Taxes Other Than Income (GAAP) 291 283 337 338 301Add: Severance Tax Refund – 31 – – -Taxes Other Than Income (Non-GAAP) (4) 291 314 337 338 301Interest Expense, Net 38 31 36 33 35Total Operating Cost (GAAP) (excluding DD&A and Total Exploration 1,353 1,318 1,337 1,342 1,329Costs) (f)Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration 1,353 1,339 1,337 1,342 1,329Costs) (g)Depreciation, Depletion and Amortization (DD&A) 1,019 1,031 984 1,074 930Total Operating Cost (GAAP) (excluding Total Exploration Costs) – (h) 2,372 2,349 2,321 2,416 2,259Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) – (i) 2,372 2,370 2,321 2,416 2,259Exploration Costs 52 43 34 45 41Dry Hole Costs 8 – 5 1 -Impairments 276 15 81 19 79Total Exploration Costs (GAAP) 336 58 120 65 120Less: Certain Impairments (2) (254) – (35) (2) (19)Total Exploration Costs (Non-GAAP) 82 58 85 63 101Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) – 2,708 2,407 2,441 2,481 2,379(j)Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non- 2,454 2,428 2,406 2,479 2,360GAAP)) – (k)Total Wellhead Revenues less Total Operating Cost (GAAP) (including Total 1,601 1,977 2,069 1,894 2,178Exploration Costs (GAAP))Total Wellhead Revenues less Total Operating Cost (Non-GAAP) (including Total 1,855 1,956 2,104 1,896 2,197Exploration Costs (Non-GAAP))Revenues, Costs and Margins Per Barrel of Oil Equivalent(Continued)In millions of USD, except Boe and per Boe amounts (Unaudited) 4Q 2024 3Q 2024 2Q 2024 1Q 2024 4Q 2023Per Barrel of Oil Equivalent (Boe) Calculations (GAAP)Composite Average Operating Revenues and Other per Boe – (b) / (a) 55.41 60.25 63.22 65.42 67.34Composite Average Operating Expenses per Boe – (c) / (a) 39.62 39.15 40.87 41.16 40.81Composite Average Operating Income per Boe – (d) / (a) 15.79 21.10 22.35 24.26 26.53Composite Average Wellhead Revenue per Boe – (e) / (a) 42.74 44.31 47.31 46.73 48.27Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) – (f) / (a) 13.42 13.32 14.03 14.33 14.08Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) – [(e) / (a) – (f) / (a)] 29.32 30.99 33.28 32.40 34.19Total Operating Cost per Boe (excluding Total Exploration Costs) – (h) / (a) 23.53 23.74 24.35 25.80 23.93Composite Average Margin per Boe (excluding Total Exploration Costs) – [(e) / (a) – (h) / (a)] 19.21 20.57 22.96 20.93 24.34Total Operating Cost per Boe (including Total Exploration Costs) – (j) / (a) 26.86 24.33 25.61 26.49 25.20Composite Average Margin per Boe (including Total Exploration Costs) – [(e) / (a) – (j) / (a)] 15.88 19.98 21.70 20.24 23.07Per Barrel of Oil Equivalent (Boe) Calculations (Non-GAAP)Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) – (g) / (a) 13.42 13.53 14.03 14.33 14.08Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) – [(e) / (a) – (g) / (a)] 29.32 30.78 33.28 32.40 34.19Total Operating Cost per Boe (excluding Total Exploration Costs) – (i) / (a) 23.53 23.95 24.35 25.80 23.93Composite Average Margin per Boe (excluding Total Exploration Costs) – [(e) / (a) – (i) / (a)] 19.21 20.36 22.96 20.93 24.34Total Operating Cost per Boe (including Total Exploration Costs) – (k) / (a) 24.34 24.54 25.24 26.47 25.00Composite Average Margin per Boe (including Total Exploration Costs) – [(e) / (a) – (k) / (a)] 18.40 19.77 22.07 20.26 23.27Revenues, Costs and Margins Per Barrel of Oil Equivalent(Continued)In millions of USD, except Boe and per Boe amounts (Unaudited) 2024 2023 2022 2021Volume – Million Barrels of Oil Equivalent – (a) 388.7 359.4 331.5 302.5Total Operating Revenues and Other (b) 23,698 24,186 25,702 18,642Total Operating Expenses (c) 15,616 14,583 15,736 12,540Operating Income (Loss) (d) 8,082 9,603 9,966 6,102Wellhead RevenuesCrude Oil and Condensate 13,921 13,748 16,367 11,125Natural Gas Liquids 2,106 1,884 2,648 1,812Natural Gas 1,551 1,744 3,781 2,444Total Wellhead Revenues – (e) 17,578 17,376 22,796 15,381Operating CostsLease and Well 1,572 1,454 1,331 1,135Gathering, Processing and Transportation Costs (1) 1,722 1,620 1,587 1,422General and Administrative (GAAP) 669 640 570 511Less: Severance Tax Consulting Fees (10) – (16) -General and Administrative (Non-GAAP) (3) 659 640 554 511Taxes Other Than Income (GAAP) 1,249 1,284 1,585 1,047Add: Severance Tax Refund 31 – 115 -Taxes Other Than Income (Non-GAAP) (4) 1,280 1,284 1,700 1,047Interest Expense, Net 138 148 179 178Total Operating Cost (GAAP) (excluding DD&A and Total Exploration Costs) – (f) 5,350 5,146 5,252 4,293Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration Costs) – (g) 5,371 5,146 5,351 4,293Depreciation, Depletion and Amortization (DD&A) 4,108 3,492 3,542 3,651Total Operating Cost (GAAP) (excluding Total Exploration Costs) – (h) 9,458 8,638 8,794 7,944Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) – (i) 9,479 8,638 8,893 7,944Exploration Costs 174 181 159 154Dry Hole Costs 14 1 45 71Impairments 391 202 382 376Total Exploration Costs (GAAP) 579 384 586 601Less: Certain Impairments (2) (291) (42) (113) (15)Total Exploration Costs (Non-GAAP) 288 342 473 586Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) – (j) 10,037 9,022 9,380 8,545Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non-GAAP)) – (k) 9,767 8,980 9,366 8,530Total Wellhead Revenues less Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) 7,541 8,354 13,416 6,836Total Wellhead Revenues less Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non-GAAP)) 7,811 8,396 13,430 6,851Revenues, Costs and Margins Per Barrel of Oil Equivalent(Continued)In millions of USD, except Boe and per Boe amounts (Unaudited) 2024 2023 2022 2021Per Barrel of Oil Equivalent (Boe) Calculations (GAAP)Composite Average Operating Revenues and Other per Boe – (b) / (a) 60.97 67.30 77.53 61.63Composite Average Operating Expenses per Boe – (c) / (a) 40.18 40.58 47.47 41.46Composite Average Operating Income (Loss) per Boe – (d) / (a) 20.79 26.72 30.06 20.17Composite Average Wellhead Revenue per Boe – (e) / (a) 45.22 48.34 68.77 50.84Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) – (f) / (a) 13.76 14.31 15.84 14.19Composite Average Margin per Boe (excluding DD&A and Total Exploration 31.46 34.03 52.93 36.65Costs) – [(e) / (a) – (f) / (a)]Total Operating Cost per Boe (excluding Total Exploration Costs) – (h) / (a) 24.33 24.03 26.53 26.26Composite Average Margin per Boe (excluding Total Exploration Costs) – 20.89 24.31 42.24 24.58[(e) / (a) – (h) / (a)]Total Operating Cost per Boe (including Total Exploration Costs) – (j) / (a) 25.82 25.10 28.30 28.25Composite Average Margin per Boe (including Total Exploration Costs) – [(e) / 19.40 23.24 40.47 22.59(a) – (j) / (a)]Per Barrel of Oil Equivalent (Boe) Calculations (Non-GAAP)Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) – (g) / (a) 13.82 14.31 16.14 14.19Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) – [(e) / (a) – 31.40 34.03 52.63 36.65(g) / (a)]Total Operating Cost per Boe (excluding Total Exploration Costs) – (i) / (a) 24.39 24.03 26.83 26.26Composite Average Margin per Boe (excluding Total ExplorationCosts) – 20.83 24.31 41.94 24.58[(e) / (a) – (i) / (a)]Total Operating Cost per Boe (including Total Exploration Costs) – (k) / (a) 25.13 24.98 28.26 28.20Composite Average Margin per Boe (including Total Exploration Costs) – [(e) / 20.09 23.36 40.51 22.64(a) – (k) / (a)](1) 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.(2) 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 exploration 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).(3) EOG believes excluding the above-referenced items from General and Administrative Costs is appropriate and provides useful information to investors, as EOG views such items as non-recurring.(4) EOG believes excluding the above-referenced items from Taxes Other Than Income is appropriate and provides useful information to investors, as EOG views such items as non-recurring.

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