EOG Resources Reports Second Quarter 2026 Results

HOUSTON, Aug. 4, 2026 — EOG Resources, Inc. (EOG) today reported second quarter 2026 results. The attached schedules for the reconciliation of non-GAAP measures to GAAP measures, along with a related presentation, are also available on EOG's website at http://investors.eogresources.com/investors.

Second Quarter Highlights

• Earned net income of $2.72 billion, or $5.15 per share, and adjusted net income of $2.68 billion, or $5.07 per share
• Delivered net cash provided by operating activities of $4.7 billion and adjusted CFO1 of $4.4 billion
• Generated $2.8 billion of free cash flow
• Declared regular quarterly dividend of $1.02 per share
• Paid $540 million in regular dividends and repurchased $1.3 billion of shares
• Quarterly oil volumes of 548.8 MBod and total volumes of 1,410.4 MBoed
• Delivered lease & well and gathering, processing & transportation costs better than guidance midpoints
• Established UAE oil production with successful initial test

CEO Commentary "EOG delivered outstanding second quarter results, including record financial performance. Strong operational execution highlighted by LOE and GP&T costs below guidance midpoints coupled with higher oil prices drove this robust financial performance. In the second quarter, we generated $2.8 billion of free cash flow and returned $1.8 billion to shareholders through our regular dividend and share repurchases. Our cash return reflects the significant cash generation capacity of our business, the strength of our balance sheet, and confidence in our ability to drive further value creation.

We are well positioned to capture opportunities across commodity cycles. Our diversified asset portfolio spans oil, NGLs, and natural gas across unconventional and conventional resources, which we continue to strengthen through organic exploration. On that front, during the quarter, we established UAE oil production with successful test results from two one-mile lateral wells that averaged over 25,000 barrels of cumulative oil production per well for the first 30 days.

Our operating model maximizes the value of our low-cost, high-return inventory across multiple basins. Vertical integration and in-house technology support repeatable cost discipline, and our pricing exposure to premium markets drives strong realizations. Most importantly, our core competitive advantage, the unique EOG culture, allows our employees to innovate and operate at a high level, supporting efficient operations and long-term returns.

We executed strongly in the first half of 2026 and enter the second half with positive momentum. Based on current guidance, we expect to deliver 5% oil production growth and 14% total production growth this year. At the current forward strip, this performance is expected to drive substantial free cash flow for the full-year 2026, supporting opportunistic and disciplined cash returns to shareholders. We remain focused on sustainable value creation through industry cycles by being among the highest return and lowest cost producers."

Return of Capital The Board of Directors today declared a regular dividend of $1.02 per share on EOG's common stock. The regular dividend will be payable October 30, 2026, to stockholders of record as of October 16, 2026. The indicated annual rate is $4.08 per share.

During the second quarter, the company repurchased 9.6 million shares for $1,294 million under its share repurchase authorization, at an average purchase price of $135 per share. As of June 30, 2026, EOG had $11.7 billion remaining on its current repurchase authorization.

Key Financial Results

In millions of USD, except per-share, per-Boe and ratio data

GAAP

2Q 2026

1Q 2026

4Q 2025

3Q 2025

2Q 2025

Total Revenue

8,620

6,921

5,638

5,847

5,478

Net Income

2,724

1,980

701

1,471

1,345

Net Income Per Share

5.15

3.70

1.30

2.70

2.46

Net Cash Provided by Operating Activities

4,669

2,966

2,612

3,111

2,032

Total Expenditures

1,919

1,768

1,730

8,544

1,883

Current and Long-Term Debt

7,926

7,931

7,936

7,694

4,236

Cash and Cash Equivalents

4,907

3,849

3,396

3,530

5,216

Debt-to-Total Capitalization

19.9 %

20.4 %

21.0 %

20.3 %

12.7 %

Cash Operating Costs ($/Boe)

10.57

10.45

10.28

10.50

10.05

Non–GAAP

Adjusted Net Income

2,683

1,825

1,222

1,472

1,268

Adjusted Net Income Per Share

5.07

3.41

2.27

2.71

2.32

Adjusted CFO1

4,386

3,129

2,617

3,031

2,496

Capital Expenditures

1,587

1,636

1,639

1,648

1,523

Free Cash Flow

2,799

1,493

978

1,383

973

Net Debt

3,019

4,082

4,540

4,164

(980)

Net Debt-to-Total Capitalization

8.7 %

11.7 %

13.2 %

12.1 %

(3.5 %)

Cash Operating Costs ($/Boe)2

10.57

10.45

10.22

9.93

9.94

Key Operational Results

Volumes

2Q 2026

1Q 2026

4Q 2025

3Q 2025

2Q 2025

Crude Oil and Condensate (MBod)

548.8

548.5

546.1

534.5

504.2

Natural Gas Liquids (MBbld)

346.8

332.1

342.1

309.3

258.4

Natural Gas (MMcfd)

3,089

3,020

3,065

2,745

2,229

Total Crude Oil Equivalent (MBoed)

1,410.4

1,383.8

1,399.0

1,301.2

1,134.1

Cash Operating Costs ($/Boe)

Lease & Well

3.64

3.71

3.47

3.60

3.84

Gathering, Processing & Transportation Costs

5.27

5.25

5.07

4.90

4.41

General & Administrative (GAAP)

1.66

1.49

1.74

2.00

1.80

General & Administrative (Non-GAAP)2

1.66

1.49

1.68

1.43

1.69

Cash Operating Costs (GAAP)

10.57

10.45

10.28

10.50

10.05

Cash Operating Costs (Non-GAAP)2

10.57

10.45

10.22

9.93

9.94

Depreciation, Depletion & Amortization ($/Boe)

9.81

9.58

9.53

9.77

10.20

Second Quarter 2026 Results vs Guidance

(Unaudited)

2Q 2026

2Q 2026 Guidance Midpoint4

Variance

1Q 2026

4Q 2025

3Q 2025

2Q 2025

Crude Oil and Condensate Volumes (MBod)

United States

546.2

546.5

(0.3)

546.5

544.5

532.9

503.1

Trinidad

2.1

2.0

0.1

1.9

1.5

1.6

1.1

Other International5

0.5

0.1

0.1

0.0

0.0

Total

548.8

548.5

0.3

548.5

546.1

534.5

504.2

Natural Gas Liquids Volumes (MBbld)

Total

346.8

337.0

9.8

332.1

342.1

309.3

258.4

Natural Gas Volumes (MMcfd)

United States

2,784

2,785

(1)

2,769

2,859

2,511

1,977

Trinidad

293

250

43

239

195

230

252

Other International5

12

12

11

4

0

Total

3,089

3,035

54

3,020

3,065

2,745

2,229

Total Crude Oil Equivalent Volumes (MBoed)

1,410.4

1,391.4

19.0

1,383.8

1,399.0

1,301.2

1,134.1

Total MMBoe

128.3

126.6

1.7

124.5

128.7

119.7

103.2

Benchmark Price

Oil (WTI) ($/Bbl)

92.85

72.17

59.17

64.95

63.71

Natural Gas (HH) ($/Mcf)

2.89

4.96

3.55

3.07

3.44

Crude Oil and Condensate - above (below) WTI****6 ($/Bbl)

United States

5.33

5.75

(0.42)

0.31

0.37

1.02

1.13

Trinidad

(3.98)

(1.00)

(2.98)

(3.26)

(2.10)

(7.21)

(9.21)

Other International

10.55

16.95

4.81

0.00

0.00

Natural Gas Liquids - Realizations as % of WTI

Total

26.3 %

27.0 %

(0.7 %)

30.8 %

35.7 %

32.7 %

35.6 %

Natural Gas - above (below) NYMEX Henry Hub****7 ($/Mcf)

United States

(0.12)

(0.15)

0.03

(1.21)

(0.61)

(0.36)

(0.57)

Natural Gas Realizations ($/Mcf)

Trinidad

3.99

3.75

0.24

3.91

3.94

3.80

3.65

Other International5

3.27

3.26

3.29

3.27

0.00

Total Expenditures (GAAP) ($MM)

1,919

1,768

1,730

8,544

1,883

Capital Expenditures (Non-GAAP) ($MM)

1,587

1,625

(38)

1,636

1,639

1,648

1,523

Operating Unit Costs ($/Boe)

Lease and Well

3.64

3.70

(0.06)

3.71

3.47

3.60

3.84

Gathering, Processing and Transportation Costs

5.27

5.30

(0.03)

5.25

5.07

4.90

4.41

General & Administrative (GAAP)

1.66

1.49

1.74

2.00

1.80

General & Administrative (Non-GAAP)2

1.66

1.50

0.16

1.49

1.68

1.43

1.69

Cash Operating Costs (GAAP)

10.57

10.45

10.28

10.50

10.05

Cash Operating Costs (Non-GAAP)2

10.57

10.50

0.07

10.45

10.22

9.93

9.94

Depreciation, Depletion and Amortization

9.81

9.70

0.11

9.58

9.53

9.77

10.20

Expenses ($MM)

Exploration and Dry Hole

77

65

12

68

54

71

85

Impairment (GAAP)

19

39

689

71

39

Impairment (excluding certain impairments (Non-GAAP))8

19

80

(61)

39

43

71

28

Capitalized Interest

38

37

1

37

36

27

11

Net Interest (GAAP)

67

66

66

71

51

Net Interest (Non-GAAP)9

67

68

(1)

66

66

71

45

TOTI (% of revenues from sales of crude oil and condensate, NGLs and natural gas)

(GAAP)

6.6 %

6.4 %

6.3 %

6.8 %

7.3 %

(Non-GAAP)

6.6 %

7.0 %

(0.4 %)

6.4 %

6.3 %

6.8 %

7.3 %

Income Taxes

Effective Rate

22.1 %

22.5 %

(0.4 %)

22.5 %

22.8 %

19.4 %

23.2 %

Current Tax Expense ($MM)

429

575

(146)

557

293

75

301

Third Quarter and Full-Year 2026 Guidance****10

3Q 2026

3Q 2026

FY 2026

FY 2026

(Unaudited)

Guidance Range

Midpoint

Guidance Range

Midpoint

Crude Oil and Condensate Volumes (MBod)

United States

544.5

549.1

546.8

544.8

549.2

547.0

Trinidad

1.5

1.9

1.7

1.5

1.9

1.7

Total

546.0

551.0

548.5

546.3

551.1

548.7

Natural Gas Liquids Volumes (MBbld)

Total

337.0

357.0

347.0

332.0

352.0

342.0

Natural Gas Volumes (MMcfd)

United States

2,800

2,900

2,850

2,760

2,860

2,810

Trinidad

240

260

250

240

260

250

Total

3,040

3,160

3,100

3,000

3,120

3,060

Crude Oil Equivalent Volumes (MBoed)

United States

1,348.2

1,389.4

1,368.8

1,336.8

1,377.9

1,357.3

Trinidad

41.5

45.2

43.4

41.5

45.2

43.4

Total

1,389.7

1,434.7

1,412.2

1,378.3

1,423.1

1,400.7

Crude Oil and Condensate - above (below) WTI****6 ($/Bbl)

United States

0.90

2.40

1.65

1.25

3.25

2.25

Trinidad

(3.35)

(1.85)

(2.60)

(3.40)

(1.40)

(2.40)

Natural Gas Liquids - Realizations as % of WTI

Total

23.0 %

• 33.0%

28.0 %

23.0 %

• 33.0%

28.0 %

Natural Gas - above (below) NYMEX Henry Hub****7 ($/Mcf)

United States

0.15

0.85

0.50

(1.10)

0.90

(0.10)

Natural Gas Realizations ($/Mcf)

Trinidad

3.45

4.15

3.80

3.25

4.25

3.75

Capital Expenditures****11 ($MM)

1,600

1,700

1,650

6,300

6,700

6,500

Operating Unit Costs ($/Boe)

Lease and Well

3.55

4.05

3.80

3.55

4.05

3.80

Gathering, Processing and Transportation Costs

5.15

5.65

5.40

5.10

5.60

5.35

General & Administrative

1.35

1.65

1.50

1.40

1.70

1.55

Cash Operating Costs

10.05

11.35

10.70

10.05

11.35

10.70

Depreciation, Depletion and Amortization

9.50

10.50

10.00

9.40

10.40

9.90

Expenses ($MM)

Exploration and Dry Hole

45

85

65

235

275

255

Impairment (excluding certain impairments)8

70

150

110

190

370

280

Capitalized Interest

36

40

38

147

151

149

Net Interest

64

68

66

267

271

269

TOTI (% of revenues from sales of crude oil and condensate, NGLs and natural gas)

5.8 %

7.8 %

6.8 %

5.8 %

7.8 %

6.8 %

Income Taxes

Effective Rate

20.0 %

25.0 %

22.5 %

20.0 %

25.0 %

22.5 %

Current Tax Expense ($MM)

545

645

595

2,015

2,215

2,115

Second Quarter 2026 Results Webcast Wednesday, August 5, 2026, 9:00 a.m. Central time (10:00 a.m. Eastern time) Webcast will be available on EOG's website for one year. https://investors.eogresources.com/Investors

About EOG EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States and Trinidad. To learn more visit https://www.eogresources.com/

Investor Contacts Pearce Hammond 713-571-4684 Neel Panchal 713-571-4884 Shelby O'Connor 713-571-4560 Cameron Hughes 713-571-3724

Media Contact Kimberly Ehmer 713-571-4676

Endnotes

Cash flow from operations before changes in working capital and certain acquisition-related costs.

Cash Operating Costs consist of LOE, GP&T and G&A. Non-GAAP G&A excludes Encino acquisition-related G&A costs of $8 million for 4Q 2025, $68 million for 3Q 2025 and $12 million for 2Q 2025, as reflected in the accompanying reconciliation schedules (see "Revenues, Costs and Margins Per Barrel of Oil Equivalent"). The per-Boe impact of such Encino acquisition-related costs on G&A and total Cash Operating Costs for 4Q 2025 was ($0.06), for 3Q 2025 was ($0.57) and for 2Q 2025 was ($0.11) as set forth in "Second Quarter 2026 Results vs Guidance" above.

Other includes gathering, processing and marketing revenue, gains (losses) on asset dispositions (for GAAP earnings per share only), other revenue, exploration costs, dry hole costs, impairments, marketing costs, taxes other than income, other income (expense), interest expense, the impact of changes in the effective income tax rate and the impact of share repurchases on diluted shares.

GAAP and non-GAAP distinctions apply solely to actual results and do not pertain to EOG's second quarter 2026 guidance midpoint disclosures.

Crude oil and condensate volumes are from UAE and Bahrain operations. Natural gas volumes are from Bahrain operations; natural gas realized price represents contract price less partner's processing and distribution costs.

EOG bases United States, Trinidad, and Other International crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the daily settlement prices for the prompt-month NYMEX futures contract for each of the applicable calendar months.

EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the NYMEX Last Day Settle price for each of the applicable months.

In general, EOG excludes impairments which are (i) attributable to declines in commodity prices, (ii) related to sales of certain oil and gas properties or (iii) the result of certain other events or decisions (e.g., a periodic review of EOG's oil and gas properties or other assets). EOG believes excluding these impairments from total impairment costs is appropriate and provides useful information to investors, as such impairments were caused by factors outside of EOG's control (versus, for example, impairments that are due to EOG's proved oil and gas properties not being as productive as it originally estimated). Impairments (Non-GAAP) for 4Q 2025 are adjusted from Impairments (GAAP) for 4Q 2025 by excluding $646 million of impairments, primarily associated with the write-down to fair value of natural gas and crude oil assets in the Barnett Shale and Woodford Oil Window (mainly driven by play-specific economics and resource allocation).

Net interest expense (Non-GAAP) excludes Encino acquisition-related financing commitment costs of $6 million in 2Q 2025.

The forecast items for the third quarter and full year 2026 set forth above for EOG are based on currently available information and expectations as of the date of this press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with this press release and EOG's related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast.

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.

Cautionary Notice 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, statements regarding the plans and objectives of EOG's management for future operations and statements and projections regarding the strategic rationale for, and anticipated benefits of, EOG's acquisition of Encino Acquisition Partners, LLC (Encino) are forward-looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," "aims," "ambition," "initiative," "goal," "may," "will," "focused on," "should" and "believe" or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning (i) EOG's future financial or operating results and returns, (ii) EOG's ability to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control drilling, completion and operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, other environmental matters or safety matters, pay and/or increase regular and/or special dividends or repurchase shares or (iii) the successful integration of Encino's assets and operations or the strategic rationale for, or anticipated benefits of, EOG's acquisition of Encino, in each case are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that such assumptions are accurate or will prove to have been correct or that any of such expectations will be achieved (in full or at all) or will be achieved on the expected or anticipated timelines. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:

• the timing, magnitude and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids (NGLs), natural gas and related commodities;
• the extent to which EOG is successful in its efforts to acquire or discover additional reserves;
• the extent to which EOG is successful in its efforts to (i) economically develop its acreage in, (ii) produce reserves and achieve anticipated production levels and rates of return from, (iii) decrease or otherwise control its drilling, completion and operating costs and capital expenditures related to, and (iv) maximize reserve recoveries from, its existing and future crude oil and natural gas exploration and development projects and associated potential and existing drilling locations;
• the success of EOG's cost-mitigation initiatives and actions in offsetting the impact of any inflationary or other pressures on EOG's operating costs and capital expenditures;
• the extent to which EOG is successful in its efforts to market its production of crude oil and condensate, NGLs and natural gas;
• security threats, including cybersecurity threats and disruptions to our business and operations from breaches of our information technology systems, physical breaches of our facilities and other infrastructure or breaches of the information technology systems, facilities and infrastructure of third parties with which we transact business, and enhanced regulatory focus on the prevention of, and disclosure requirements relating to, cyber incidents;
• the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, storage, transportation, refining, liquefaction and export facilities and equipment;
• the availability, cost, terms and timing of issuance or execution of mineral licenses, concessions and leases and governmental and other permits and rights-of-way, and EOG's ability to retain mineral licenses, concessions and leases;
• the impact of, and changes in, government policies, laws and regulations, including climate change-related regulations, policies and initiatives (for example, with respect to air emissions); tax laws and regulations (including, but not limited to, carbon tax or other emissions-related legislation); environmental, health and safety laws and regulations relating to disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations affecting the leasing of acreage and permitting for oil and gas drilling and the calculation of royalty payments in respect of oil and gas production; laws and regulations imposing additional permitting and disclosure requirements, additional operating restrictions and conditions or restrictions on drilling and completion operations and on the transportation of crude oil, NGLs and natural gas; laws and regulations with respect to financial commodity and other derivative instruments and hedging activities; laws and regulations with respect to the import and export of crude oil, natural gas and related commodities; and trade policies, tariffs, trade agreements and other trade restrictions;
• the impact of climate change-related legislation, policies and initiatives; climate change-related political, social and shareholder activism; and physical, transition and reputational risks and other potential developments related to climate change;
• the extent to which EOG is able to successfully and economically develop, implement and carry out its emissions and other environmental or safety-related initiatives and achieve its related targets, goals, ambitions and initiatives;
• EOG's failure to realize, in full or at all, the anticipated benefits of its acquisition of Encino and/or business disruptions resulting from the acquisition (e.g., relating to the integration of Encino's assets and operations into EOG's operations) that could harm EOG's business operations (including current plans and operations and the diversion of management's attention from EOG's ongoing business operations);
• EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, identify and resolve existing and potential issues with respect to such properties and accurately estimate reserves, production, drilling, completion and operating costs and capital expenditures with respect to such properties;
• the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully, economically and in compliance with applicable laws and regulations;
• competition in the oil and gas exploration and production industry for the acquisition of licenses, concessions, leases and properties;
• the availability and cost of, EOG's ability to retain, and competition in the oil and gas exploration and production industry for, employees, labor and other personnel, facilities, equipment, materials (such as water, sand, fuel and tubulars) and services;
• the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;
• weather and natural disasters, including its impact on crude oil and natural gas demand, and related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, liquefaction, compression, storage, transportation, and export facilities;
• the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;
• EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;
• the extent to which EOG is successful in its completion of planned asset dispositions;
• the extent and effect of any hedging activities engaged in by EOG;
• the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;
• geopolitical factors and political conditions and developments around the world (such as the imposition of tariffs or trade or other economic sanctions, political instability and armed conflicts), including in the areas in which EOG operates;
• the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage; and
• the other factors described under ITEM 1A, Risk Factors of EOG's Annual Report on Form 10-K for the fiscal year ended December 31, 2025 and any updates to those factors set forth in EOG's subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.

In light of these risks, uncertainties and assumptions, the events anticipated by EOG's forward-looking statements may not occur and, if any of such events do, we may not have anticipated the timing of their occurrence or the duration or extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of EOG's forward-looking statements. EOG's forward-looking statements speak only as of the date made, and EOG undertakes no obligation, other than as required by applicable law, to update or revise its forward-looking statements, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise.

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, adjusted cash flow from operations 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, 2025 (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.

Income Statements

In millions of USD, except share data (in millions) and per share data (Unaudited)

2025

2026

1st Qtr

2nd Qtr

3rd Qtr

4th Qtr

Year

1st Qtr

2nd Qtr

3rd Qtr

4th Qtr

Year

Operating Revenues and Other

Crude Oil and Condensate

3,293

2,974

3,243

2,991

12,501

3,577

4,901

8,478

Natural Gas Liquids

572

534

604

666

2,376

664

770

1,434

Natural Gas

637

600

707

847

2,791

1,021

812

1,833

Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net

(191)

107

116

(19)

13

113

40

153

Gathering, Processing and Marketing

1,340

1,247

1,178

1,149

4,914

1,496

2,011

3,507

Gains (Losses) on Asset Dispositions, Net

(1)

—

(18)

(16)

(35)

31

58

89

Other, Net

19

16

17

20

72

19

28

47

Total

5,669

5,478

5,847

5,638

22,632

6,921

8,620

15,541

Operating Expenses

Lease and Well

401

396

431

447

1,675

462

467

929

Gathering, Processing and Transportation Costs

440

455

587

652

2,134

654

676

1,330

Exploration Costs

41

74

71

50

236

45

47

92

Dry Hole Costs

34

11

—

4

49

23

30

53

Impairments

44

39

71

689

843

39

19

58

Marketing Costs

1,325

1,216

1,134

1,120

4,795

1,384

1,950

3,334

Depreciation, Depletion and Amortization

1,013

1,053

1,169

1,226

4,461

1,193

1,259

2,452

General and Administrative

171

186

239

224

820

185

213

398

Taxes Other Than Income

341

301

309

283

1,234

338

431

769

Total

3,810

3,731

4,011

4,695

16,247

4,323

5,092

9,415

Operating Income

1,859

1,747

1,836

943

6,385

2,598

3,528

6,126

Other Income, Net

65

55

59

33

212

23

38

61

Income Before Interest Expense and Income Taxes

1,924

1,802

1,895

976

6,597

2,621

3,566

6,187

Interest Expense, Net

47

51

71

66

235

66

67

133

Income Before Income Taxes

1,877

1,751

1,824

910

6,362

2,555

3,499

6,054

Income Tax Provision

414

406

353

209

1,382

575

775

1,350

Net Income

1,463

1,345

1,471

701

4,980

1,980

2,724

4,704

Dividends Declared per Common Share

0.9750

1.9950

—

1.0200

3.9900

1.0200

1.0200

2.0400

Net Income Per Share

Basic

2.66

2.48

2.72

1.31

9.17

3.72

5.18

8.89

Diluted

2.65

2.46

2.70

1.30

9.12

3.70

5.15

8.84

Average Number of Common Shares

Basic

550

543

541

537

543

532

526

529

Diluted

553

546

544

539

546

535

529

532

Volumes and Prices

(Unaudited)

2025

2026

1st Qtr

2nd Qtr

3rd Qtr

4th Qtr

Year

1st Qtr

2nd Qtr

3rd Qtr

4th Qtr

Year

Crude Oil and Condensate Volumes (MBbld) (A)

United States

500.9

503.1

532.9

544.5

520.5

546.5

546.2

546.3

Trinidad

1.2

1.1

1.6

1.5

1.4

1.9

2.1

2.0

Other International (B)

—

—

—

0.1

—

0.1

0.5

0.3

Total

502.1

504.2

534.5

546.1

521.9

548.5

548.8

548.6

Average Crude Oil and Condensate Prices ($/Bbl) (C)

United States

$ 72.90

$ 64.84

$ 65.97

$ 59.54

$ 65.65

$ 72.48

$ 98.18

$ 85.40

Trinidad

61.12

54.50

57.74

57.07

57.59

68.91

88.87

79.20

Other International

—

—

—

63.98

—

89.12

103.40

101.81

Composite

72.87

64.82

65.95

59.54

65.63

72.47

98.15

85.38

Natural Gas Liquids Volumes (MBbld) (A)

United States

241.7

258.4

309.3

342.1

288.2

332.1

346.8

339.5

Total

241.7

258.4

309.3

342.1

288.2

332.1

346.8

339.5

Average Natural Gas Liquids Prices ($/Bbl) (C)

United States

$ 26.29

$ 22.70

$ 21.25

$ 21.15

$ 22.58

$ 22.20

$ 24.41

$ 23.34

Composite

26.29

22.70

21.25

21.15

22.58

22.20

24.41

23.34

Natural Gas Volumes (MMcfd) (A)

United States

1,834

1,977

2,511

2,859

2,299

2,769

2,784

2,777

Trinidad

246

252

230

195

230

239

293

266

Other International (B)

—

—

4

11

4

12

12

12

Total

2,080

2,229

2,745

3,065

2,533

3,020

3,089

3,055

Average Natural Gas Prices ($/Mcf) (C)

United States

$ 3.36

$ 2.87

$ 2.71

$ 2.94

$ 2.94

$ 3.75

$ 2.77

$ 3.25

Trinidad

3.78

3.65

3.80

3.94

3.78

3.91

3.99

3.95

Other International (B)

—

—

3.27

3.29

3.28

3.26

3.27

3.27

Composite

3.41

2.96

2.80

3.00

3.02

3.76

2.89

3.32

Crude Oil Equivalent Volumes (MBoed) (D)

United States

1,048.3

1,090.9

1,260.7

1,363.0

1,191.8

1,340.1

1,357.1

1,348.6

Trinidad

42.1

43.2

39.8

34.2

39.8

41.7

50.9

46.4

Other International

—

—

0.7

1.8

0.6

2.0

2.4

2.2

Total

1,090.4

1,134.1

1,301.2

1,399.0

1,232.2

1,383.8

1,410.4

1,397.2

Total MMBoe (D)

98.1

103.2

119.7

128.7

449.8

124.5

128.3

252.9

(A)

Thousand barrels per day or million cubic feet per day, as applicable.

(B)

Crude oil and condensate volumes are from UAE and Bahrain operations. Natural gas volumes are from Bahrain operations; natural gas realized price represents contract price less partner's processing and distribution costs.

(C)

Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity and other derivative instruments (see Note 9 to the Condensed Consolidated Financial Statements in EOG's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2026).

(D)

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 Sheets

In millions of USD (Unaudited)

2025

2026

MAR

JUN

SEP

DEC

MAR

JUN

SEP

DEC

Current Assets

Cash and Cash Equivalents

6,599

5,216

3,530

3,396

3,849

4,907

Accounts Receivable, Net

2,621

2,504

2,680

2,681

3,597

3,529

Inventories

897

934

945

1,014

955

930

Other (A)

563

591

665

565

562

511

Total

10,680

9,245

7,820

7,656

8,963

9,877

Property, Plant and Equipment

Oil and Gas Properties (Successful Efforts Method)

78,432

80,139

88,301

89,857

90,786

92,454

Other Property, Plant and Equipment

6,510

6,616

6,772

6,832

6,942

7,064

Total Property, Plant and Equipment

84,942

86,755

95,073

96,689

97,728

99,518

Less: Accumulated Depreciation, Depletion and Amortization

(50,310)

(51,394)

(52,488)

(54,348)

(55,054)

(56,278)

Total Property, Plant and Equipment, Net

34,632

35,361

42,585

42,341

42,674

43,240

Deferred Income Taxes

44

39

37

39

30

35

Other Assets

1,626

1,639

1,757

1,763

1,711

1,631

Total Assets

46,982

46,284

52,199

51,799

53,378

54,783

Current Liabilities

Accounts Payable

2,353

2,266

2,944

2,904

3,186

3,374

Accrued Taxes Payable

668

348

392

299

766

697

Dividends Payable

534

1,081

550

544

541

531

Current Portion of Long-Term Debt

1,280

778

27

27

27

27

Current Portion of Operating Lease Liabilities

318

360

433

472

375

324

Other (A)

566

342

469

445

329

382

Total

5,719

5,175

4,815

4,691

5,224

5,335

Long-Term Debt

3,464

3,458

7,667

7,909

7,904

7,899

Other Liabilities

2,368

2,398

2,496

2,512

2,476

2,468

Deferred Income Taxes

5,915

6,015

6,936

6,854

6,866

7,217

Commitments and Contingencies (B)

Stockholders' Equity

Common Stock, $0.01 Par

206

206

206

206

206

206

Additional Paid in Capital

6,095

6,153

5,978

6,027

6,026

6,072

Accumulated Other Comprehensive Loss

(4)

(7)

(5)

(7)

(6)

(5)

Retained Earnings

27,869

28,131

29,603

29,765

31,200

33,390

Common Stock Held in Treasury

(4,650)

(5,245)

(5,497)

(6,158)

(6,518)

(7,799)

Total Stockholders' Equity

29,516

29,238

30,285

29,833

30,908

31,864

Total Liabilities and Stockholders' Equity

46,982

46,284

52,199

51,799

53,378

54,783

(A)

Effective January 1, 2026, EOG combined Price Risk Management Activities into the Other line item. This presentation has been conformed for all periods presented and had no impact on previously reported Total Assets and Total Liabilities and Stockholders's Equity.

(B)

See Note 5 to the Condensed Consolidated Financial Statements in EOG's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2026.

Cash Flow Statements

In millions of USD (Unaudited)

2025

2026

1st Qtr

2nd Qtr

3rd Qtr

4th Qtr

Year

1st Qtr

2nd Qtr

3rd Qtr

4th Qtr

Year

Cash Flows from Operating Activities

Reconciliation of Net Income to Net Cash Provided by Operating Activities:

Net Income

1,463

1,345

1,471

701

4,980

1,980

2,724

4,704

Items Not Requiring (Providing) Cash

Depreciation, Depletion and Amortization

1,013

1,053

1,169

1,226

4,461

1,193

1,259

2,452

Impairments

44

39

71

689

843

39

19

58

Stock-Based Compensation Expenses

50

53

53

60

216

58

60

118

Deferred Income Taxes

44

105

278

(84)

343

18

346

364

(Gains) Losses on Asset Dispositions, Net

1

—

18

16

35

(31)

(58)

(89)

Other, Net

11

11

2

3

27

15

2

17

Dry Hole Costs

34

11

—

4

49

23

30

53

Mark-to-Market Financial Commodity and Other Derivative Contracts (Gains) Losses, Net

191

(107)

(116)

19

(13)

(113)

(40)

(153)

Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts

(38)

(24)

27

(21)

(56)

(53)

45

(8)

Other, Net

—

—

—

(1)

(1)

—

(1)

(1)

Changes in Components of Working Capital and Other Assets and Liabilities

Accounts Receivable

48

122

133

(3)

300

(907)

60

(847)

Inventories

76

(45)

4

(84)

(49)

21

26

47

Accounts Payable

(129)

(107)

5

(40)

(271)

279

176

455

Accrued Taxes Payable

(339)

(321)

28

(103)

(735)

467

(69)

398

Other Assets

(43)

(43)

(28)

97

(17)

55

47

102

Other Liabilities

(96)

(52)

155

10

17

(123)

37

(86)

Changes in Components of Working Capital Associated with Investing Activities

(41)

(8)

(159)

123

(85)

45

6

51

Net Cash Provided by Operating Activities

2,289

2,032

3,111

2,612

10,044

2,966

4,669

7,635

Investing Cash Flows

Acquisition of Encino Acquisition Partners, LLC, Net of Cash Acquired

—

—

(4,464)

13

(4,451)

—

—

—

Additions to Oil and Gas Properties

(1,381)

(1,699)

(1,492)

(1,543)

(6,115)

(1,491)

(1,638)

(3,129)

Additions to Other Property, Plant and Equipment

(102)

(94)

(171)

(112)

(479)

(153)

(144)

(297)

Proceeds from Sales of Assets

12

4

5

3

24

144

7

151

Changes in Components of Working Capital Associated with Investing Activities

41

8

159

(123)

85

(45)

(6)

(51)

Net Cash Used in Investing Activities

(1,430)

(1,781)

(5,963)

(1,762)

(10,936)

(1,545)

(1,781)

(3,326)

Financing Cash Flows

Long-Term Debt Borrowings

—

—

3,472

999

4,471

—

—

—

Long-Term Debt Repayments

—

(500)

(1,266)

(750)

(2,516)

—

—

—

Dividends Paid

(538)

(528)

(545)

(550)

(2,161)

(544)

(540)

(1,084)

Treasury Stock Purchased

(806)

(602)

(479)

(677)

(2,564)

(418)

(1,299)

(1,717)

Proceeds from Stock Options Exercised and Employee Stock Purchase Plan

—

11

—

12

23

1

15

16

Debt Issuance and Other Financing Costs

—

(7)

(7)

(11)

(25)

—

—

—

Repayment of Finance Lease Liabilities

(8)

(9)

(8)

(7)

(32)

(7)

(6)

(13)

Net Cash Used in Financing Activities

(1,352)

(1,635)

1,167

(984)

(2,804)

(968)

(1,830)

(2,798)

Effect of Exchange Rate Changes on Cash

—

1

(1)

–

—

—

–

—

Increase (Decrease) in Cash and Cash Equivalents

(493)

(1,383)

(1,686)

(134)

(3,696)

453

1,058

1,511

Cash and Cash Equivalents at Beginning of Period

7,092

6,599

5,216

3,530

7,092

3,396

3,849

3,396

Cash and Cash Equivalents at End of Period

6,599

5,216

3,530

3,396

3,396

3,849

4,907

4,907

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 earnings 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), Adjusted Cash Flow from Operations, 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 Income

In 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)), to add back costs associated with the Encino acquisition 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.

2Q 2026

Before Tax

Income Tax Impact

After Tax

Diluted Earnings per Share

Reported Net Income (GAAP)

3,499

(775)

2,724

5.15

Adjustments:

Gains on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net

(40)

9

(31)

(0.06)

Net Cash Received from Settlements of Financial Commodity Derivative Contracts (1)

45

(9)

36

0.07

Less: Gains on Asset Dispositions, Net

(58)

12

(46)

(0.09)

Adjustments to Net Income

(53)

12

(41)

(0.08)

Adjusted Net Income (Non-GAAP)

3,446

(763)

2,683

5.07

Average Number of Common Shares

Basic

526

Diluted

529

(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, 2026, such amount was $45 million.

Adjusted Net Income (Continued)

In millions of USD, except share data (in millions) and per share data (Unaudited)

1Q 2026

Before Tax

Income Tax Impact

After Tax

Diluted Earnings per Share

Reported Net Income (GAAP)

2,555

(575)

1,980

3.70

Adjustments:

Gains on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net

(113)

24

(89)

(0.17)

Net Cash Payments for Settlements of Financial Commodity Derivative Contracts (1)

(53)

11

(42)

(0.08)

Less: Gains on Asset Dispositions, Net

(31)

7

(24)

(0.04)

Adjustments to Net Income

(197)

42

(155)

(0.29)

Adjusted Net Income (Non-GAAP)

2,358

(533)

1,825

3.41

Average Number of Common Shares

Basic

532

Diluted

535

(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 three months ended March 31, 2026, such amount was $53 million.

4Q 2025

Before Tax

Income Tax Impact

After Tax

Diluted Earnings per Share

Reported Net Income (GAAP)

910

(209)

701

1.30

Adjustments:

Losses on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net

19

(4)

15

0.03

Net Cash Payments for Settlements of Financial Commodity Derivative Contracts (1)

(21)

4

(17)

(0.03)

Add: Losses on Asset Dispositions, Net

16

(4)

12

0.02

Add: Certain Impairments (2)

646

(140)

506

0.94

Add: Acquisition-Related Costs (3)

8

(3)

5

0.01

Adjustments to Net Income

668

(147)

521

0.97

Adjusted Net Income (Non-GAAP)

1,578

(356)

1,222

2.27

Average Number of Common Shares

Basic

537

Diluted

539

(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 three months ended December 31, 2025, such amount was $21 million.

(2)

Impairments primarily associated with the write-down to fair value of natural gas and crude oil assets in the Barnett Shale and Woodford Oil Window (mainly driven by play-specific economics and resource allocation).

(3)

Consists of Encino acquisition-related G&A costs ($8 million).

Adjusted Net Income (Continued)

In millions of USD, except share data (in millions) and per share data (Unaudited)

3Q 2025

Before Tax

Income Tax Impact

After Tax

Diluted Earnings per Share

Reported Net Income (GAAP)

1,824

(353)

1,471

2.70

Adjustments:

Gains on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net

(116)

25

(91)

(0.16)

Net Cash Received from Settlements of Financial Commodity Derivative Contracts (1)

27

(5)

22

0.04

Add: Losses on Asset Dispositions, Net

18

(6)

12

0.02

Add: Acquisition-Related Costs (2)

68

(10)

58

0.11

Adjustments to Net Income

(3)

4

1

0.01

Adjusted Net Income (Non-GAAP)

1,821

(349)

1,472

2.71

Average Number of Common Shares

Basic

541

Diluted

544

(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, 2025, such amount was $27 million.

(2)

Consists of Encino acquisition-related G&A costs ($68 million).

2Q 2025

Before Tax

Income Tax Impact

After Tax

Diluted Earnings per Share

Reported Net Income (GAAP)

1,751

(406)

1,345

2.46

Adjustments:

Gains on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net

(107)

23

(84)

(0.16)

Net Cash Payments for Settlements of Financial Commodity Derivative Contracts (1)

(24)

5

(19)

(0.03)

Add: Certain Impairments

11

—

11

0.02

Add: Acquisition-Related Costs (2)

18

(3)

15

0.03

Adjustments to Net Income

(102)

25

(77)

(0.14)

Adjusted Net Income (Non-GAAP)

1,649

(381)

1,268

2.32

Average Number of Common Shares

Basic

543

Diluted

546

(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 three months ended June 30, 2025, such amount was $24 million.

(2)

Consists of Encino acquisition-related G&A costs ($12 million) and financing commitment costs ($6 million).

Adjusted Net Income (Continued)

In millions of USD, except share data (in millions) and per share data (Unaudited)

FY 2025

Before Tax

Income Tax Impact

After Tax

Diluted Earnings per Share

Reported Net Income (GAAP)

6,362

(1,382)

4,980

9.12

Adjustments:

Gains on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net

(13)

3

(10)

(0.02)

Net Cash Payments for Settlements of Financial Commodity Derivative Contracts (1)

(56)

12

(44)

(0.08)

Add: Losses on Asset Dispositions, Net

35

(8)

27

0.05

Add: Certain Impairments (2)

657

(140)

517

0.95

Add: Acquisition-Related Costs (3)

94

(16)

78

0.14

Adjustments to Net Income

717

(149)

568

1.04

Adjusted Net Income (Non-GAAP)

7,079

(1,531)

5,548

10.16

Average Number of Common Shares

Basic

543

Diluted

546

(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, 2025, such amount was $56 million.

(2)

Impairments primarily associated with the write-down to fair value of natural gas and crude oil assets in the Barnett Shale and Woodford Oil Window (mainly driven by play-specific economics and resource allocation).

(3)

Consists of Encino acquisition-related G&A costs ($88 million) and financing commitment costs ($6 million).

FY 2024

Before Tax

Income Tax Impact

After Tax

Diluted Earnings per Share

Reported Net Income (GAAP)

8,218

(1,815)

6,403

11.25

Adjustments:

Gains on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net

(204)

44

(160)

(0.28)

Net Cash Received from Settlements of Financial Commodity Derivative Contracts (1)

214

(46)

168

0.30

Less: Gains on Asset Dispositions, Net

(16)

3

(13)

(0.02)

Add: Certain Impairments (2)

291

(57)

234

0.41

Less: Severance Tax Refund

(31)

7

(24)

(0.04)

Add: Severance Tax Consulting Fees

10

(2)

8

0.01

Less: Interest on Severance Tax Refund

(5)

1

(4)

(0.01)

Adjustments to Net Income

259

(50)

209

0.37

Adjusted Net Income (Non-GAAP)

8,477

(1,865)

6,612

11.62

Average Number of Common Shares

Basic

566

Diluted

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.

(2)

Impairments primarily associated with the write-down to fair value of natural gas and crude oil assets in the Rocky Mountain area.

Net Income Per Share

In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited)

1Q 2026 Net Income per Share (GAAP) - Diluted

3.70

Realized Prices

2Q 2026 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe

50.52

Less: 1Q 2026 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe

(42.24)

Subtotal

8.28

Multiplied by: 2Q 2026 Crude Oil Equivalent Volumes (MMBoe)

128.3

Total Change in Revenue

1,062

Add: Income Tax Benefit (Provision) Imputed (based on 22%)

(234)

Change in Net Income

828

Change in Diluted Earnings per Share

1.57

Volumes

2Q 2026 Crude Oil Equivalent Volumes (MMBoe)

128.3

Less: 1Q 2026 Crude Oil Equivalent Volumes (MMBoe)

(124.5)

Subtotal

3.8

Multiplied by: 2Q 2026 Composite Average Margin per Boe (GAAP) (Including Total Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent" schedule below)

25.51

Change in Margin

97

Less: Income Tax Benefit (Provision) Imputed (based on 22%)

(21)

Change in Net Income

76

Change in Diluted Earnings per Share

0.14

Certain Operating Costs per Boe

1Q 2026 Total Cash Operating Costs (GAAP) and Total DD&A per Boe

20.03

Less: 2Q 2026 Total Cash Operating Costs (GAAP) and Total DD&A per Boe

(20.38)

Subtotal

(0.35)

Multiplied by: 2Q 2026 Crude Oil Equivalent Volumes (MMBoe)

128.3

Change in Before-Tax Net Income

(45)

Add: Income Tax Benefit (Provision) Imputed (based on 22%)

10

Change in Net Income

(35)

Change in Diluted Earnings per Share

(0.07)

Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net

2Q 2026 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts

40

Less: Income Tax Benefit (Provision)

(9)

After Tax - (a)

31

Less: 1Q 2026 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts

113

Less: Income Tax Benefit (Provision)

(24)

After Tax - (b)

89

Change in Net Income - (a) - (b)

(58)

Change in Diluted Earnings per Share

(0.11)

Other (1)

(0.08)

2Q 2026 Net Income per Share (GAAP) - Diluted

5.15

2Q 2026 Average Number of Common Shares - Diluted

529

(1)

Includes gathering, processing and marketing revenue, gains (losses) on asset dispositions (for GAAP earnings per share only), other revenue, exploration costs, dry hole costs, impairments, marketing costs, taxes other than income, other income (expense), interest expense, the impact of changes in the effective income tax rate and the impact of share repurchases on diluted shares.

Adjusted Net Income Per Share

In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited)

1Q 2026 Adjusted Net Income per Share (Non-GAAP) - Diluted

3.41

Realized Prices

2Q 2026 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe

50.52

Less: 1Q 2026 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe

(42.24)

Subtotal

8.28

Multiplied by: 2Q 2026 Crude Oil Equivalent Volumes (MMBoe)

128.3

Total Change in Revenue

1,062

Add: Income Tax Benefit (Provision) Imputed (based on 22%)

(234)

Change in Net Income

828

Change in Diluted Earnings per Share

1.57

Volumes

2Q 2026 Crude Oil Equivalent Volumes (MMBoe)

128.3

Less: 1Q 2026 Crude Oil Equivalent Volumes (MMBoe)

(124.5)

Subtotal

3.8

Multiplied by: 2Q 2026 Composite Average Margin per Boe (Non-GAAP) (Including Total Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent" schedule below)

25.51

Change in Margin

97

Less: Income Tax Benefit (Provision) Imputed (based on 22%)

(21)

Change in Net Income

76

Change in Diluted Earnings per Share

0.14

Certain Operating Costs per Boe

1Q 2026 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe

20.03

Less: 2Q 2026 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe

(20.38)

Subtotal

(0.35)

Multiplied by: 2Q 2026 Crude Oil Equivalent Volumes (MMBoe)

128.3

Change in Before-Tax Net Income

(45)

Add: Income Tax Benefit (Provision) Imputed (based on 22%)

10

Change in Net Income

(35)

Change in Diluted Earnings per Share

(0.07)

Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts

2Q 2026 Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts

45

Less: Income Tax Benefit (Provision)

(9)

After Tax - (a)

36

Less: 1Q 2026 Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts

(53)

Less: Income Tax Benefit (Provision)

11

After Tax - (b)

(42)

Change in Net Income - (a) - (b)

78

Change in Diluted Earnings per Share

0.15

Other (1)

(0.13)

2Q 2026 Adjusted Net Income per Share (Non-GAAP)

5.07

2Q 2026 Average Number of Common Shares - Diluted

529

(1)

Includes gathering, processing and marketing revenue, other revenue, exploration costs, dry hole costs, impairments, marketing costs, taxes other than income, other income (expense), interest expense, the impact of changes in the effective income tax rate and the impact of share repurchases on diluted shares.

Cash Flow from Operations and Free Cash Flow

In millions of USD (Unaudited)

The following tables reconcile Net Cash Provided by Operating Activities (GAAP) to Adjusted Cash Flow from Operations (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 (or Investing and Financing Activities, as applicable) and certain other adjustments to exclude certain non-recurring items and other items as further described below. EOG defines Free Cash Flow (Non-GAAP) for a given period as Adjusted Cash Flow from Operations (Non-GAAP) (see below reconciliation) for such period less the Total Capital Expenditures (Non-GAAP) (see below reconciliation) during such period, as is illustrated below. EOG management uses this information for comparative purposes within the industry. As indicated in the tables below, EOG is (1) in addition to its customary working capital-related adjustments, adjusting Net Cash Provided by Operating Activities (GAAP) to add back certain non-recurring acquisition-related costs incurred during the second, third and fourth quarters of 2025 and (2) now presenting such adjusted measure as "Adjusted Cash Flow from Operations (Non-GAAP)" (instead of "Cash Flow from Operations Before Changes in Working Capital (Non-GAAP)" as reported in prior periods); the presentation below with respect to the second, third and fourth quarters of 2025 and the prior periods shown has been conformed.

2025

2026

1st Qtr

2nd Qtr

3rd Qtr

4th Qtr

Year

1st Qtr

2nd Qtr

3rd Qtr

4th Qtr

Year

Net Cash Provided by Operating Activities (GAAP)

2,289

2,032

3,111

2,612

10,044

2,966

4,669

7,635

Adjustments:

Changes in Components of Working Capital and Other Assets and Liabilities

Accounts Receivable

(48)

(122)

(133)

3

(300)

907

(60)

847

Inventories

(76)

45

(4)

84

49

(21)

(26)

(47)

Accounts Payable

129

107

(5)

40

271

(279)

(176)

(455)

Accrued Taxes Payable

339

321

(28)

103

735

(467)

69

(398)

Other Assets

43

43

28

(97)

17

(55)

(47)

(102)

Other Liabilities

96

52

(155)

(10)

(17)

123

(37)

86

Changes in Components of Working Capital Associated with Investing Activities

41

8

159

(123)

85

(45)

(6)

(51)

Add:

Acquisition-Related Costs (1), Net of Tax

—

10

58

5

73

—

—

—

Adjusted Cash Flow from Operations (Non- GAAP)

2,813

2,496

3,031

2,617

10,957

3,129

4,386

7,515

Less:

Total Capital Expenditures (Non-GAAP) (2)

(1,484)

(1,523)

(1,648)

(1,639)

(6,294)

(1,636)

(1,587)

(3,223)

Free Cash Flow (Non-GAAP)

1,329

973

1,383

978

4,663

1,493

2,799

4,292

(1) Consists of Encino acquisition-related G&A costs of $12 million, $68 million and $8 million (each before tax) for the three months ended June 30, 2025, three months ended September 30, 2025 and three months ended December 31, 2025, respectively.

(2) See below reconciliation of Total Expenditures (GAAP) to Total Capital Expenditures (Non-GAAP):

2025

2026

1st Qtr

2nd Qtr

3rd Qtr

4th Qtr

Year

1st Qtr

2nd Qtr

3rd Qtr

4th Qtr

Year

Total Expenditures (GAAP)

1,546

1,883

8,544

1,730

13,703

1,768

1,919

3,687

Less:

Asset Retirement Costs

(13)

(14)

(86)

(33)

(146)

(12)

(37)

(49)

Non-Cash Leasehold Acquisition Costs (3)

(9)

(2)

(3)

(10)

(24)

(52)

(53)

(105)

Non-Cash Property Acquisition Costs

—

—

—

—

—

—

(2)

(2)

Acquisition Costs of Properties (3)

1

(270)

(6,736)

2

(7,003)

(23)

(193)

(216)

Exploration Costs

(41)

(74)

(71)

(50)

(236)

(45)

(47)

(92)

Total Capital Expenditures (Non-GAAP)

1,484

1,523

1,648

1,639

6,294

1,636

1,587

3,223

Cash Flow from Operations and Free Cash Flow (Continued)

In millions of USD (Unaudited)

FY 2024

FY 2023

FY 2022

FY 2021

Net Cash Provided by Operating Activities (GAAP)

12,143

11,340

11,093

8,791

Adjustments:

Changes in Components of Working Capital and Other Assets and Liabilities

Accounts Receivable

(101)

38

347

821

Inventories

(259)

231

534

13

Accounts Payable

36

119

(90)

(456)

Accrued Taxes Payable

(541)

(61)

113

(312)

Other Assets

(44)

(39)

364

136

Other Liabilities

(23)

(184)

266

116

Changes in Components of Working Capital Associated with Investing Activities

382

(295)

(375)

200

Adjusted Cash Flow from Operations (Non-GAAP)

11,593

11,149

12,252

9,309

Less:

Total Capital Expenditures (Non-GAAP) (2)

(6,226)

(6,041)

(4,607)

(3,755)

Free Cash Flow (Non-GAAP)

5,367

5,108

7,645

5,554

(2) See below reconciliation of Total Expenditures (GAAP) to Total Capital Expenditures (Non-GAAP):

Total Expenditures (GAAP)

6,653

6,818

5,610

4,255

Less:

Asset Retirement Costs

2

(257)

(298)

(127)

Non-Cash Development Drilling

—

(90)

—

—

Non-Cash Leasehold Acquisition Costs (3)

(85)

(99)

(127)

(45)

Non-Cash Finance Leases

—

—

—

(74)

Acquisition Costs of Properties (3)

(33)

(16)

(419)

(100)

Acquisition Costs of Other Property, Plant and Equipment

(137)

(134)

—

—

Exploration Costs

(174)

(181)

(159)

(154)

Total Capital Expenditures (Non-GAAP)

6,226

6,041

4,607

3,755

(3)

Line item descriptions revised (from descriptions shown in EOG's previously published tables) to more accurately describe the costs reflected therein; previously reported cost amounts not impacted by such changes in presentation.

Net Debt-to-Total Capitalization Ratio

In 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.

June 30, 2026

March 31, 2026

December 31, 2025

September 30, 2025

June 30, 2025

Total Stockholders' Equity - (a)

31,864

30,908

29,833

30,285

29,238

Current and Long-Term Debt (GAAP) - (b)

7,926

7,931

7,936

7,694

4,236

Less: Cash

(4,907)

(3,849)

(3,396)

(3,530)

(5,216)

Net Debt (Non-GAAP) - (c)

3,019

4,082

4,540

4,164

(980)

Total Capitalization (GAAP) - (a) + (b)

39,790

38,839

37,769

37,979

33,474

Total Capitalization (Non-GAAP) - (a) + (c)

34,883

34,990

34,373

34,449

28,258

Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)]

19.9 %

20.4 %

21.0 %

20.3 %

12.7 %

Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)]

8.7 %

11.7 %

13.2 %

12.1 %

-3.5 %

Revenues, Costs and Margins Per Barrel of Oil Equivalent

In 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.

2Q 2026

1Q 2026

4Q 2025

3Q 2025

2Q 2025

Volume - Million Barrels of Oil Equivalent - (a)

128.3

124.5

128.7

119.7

103.2

Total Operating Revenues and Other - (b)

8,620

6,921

5,638

5,847

5,478

Total Operating Expenses - (c)

5,092

4,323

4,695

4,011

3,731

Operating Income - (d)

3,528

2,598

943

1,836

1,747

Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas

Crude Oil and Condensate

4,901

3,577

2,991

3,243

2,974

Natural Gas Liquids

770

664

666

604

534

Natural Gas

812

1,021

847

707

600

Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas - (e)

6,483

5,262

4,504

4,554

4,108

Operating Costs

Lease and Well

467

462

447

431

396

Gathering, Processing and Transportation Costs (1)

676

654

652

587

455

General and Administrative (GAAP)

213

185

224

239

186

Less: Certain Items (see Endnote 2 to 2Q 2026 earnings release)

—

—

(8)

(68)

(12)

General and Administrative (Non-GAAP) (2)

213

185

216

171

174

Taxes Other Than Income (GAAP)

431

338

283

309

301

Add: Severance Tax Refund

—

—

—

—

—

Taxes Other Than Income (Non-GAAP) (3)

431

338

283

309

301

Interest Expense, Net

67

66

66

71

51

Less: Acquisition-Related Financing Commitment Costs

—

—

—

—

(6)

Interest Expense, Net (Non-GAAP) (4)

67

66

66

71

45

**Total Operating Cost (GAAP) (excluding DD&A and Total Exploration Costs)

• (f)**

1,854

1,705

1,672

1,637

1,389

Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration Costs) - (g)

1,854

1,705

1,664

1,569

1,371

Depreciation, Depletion and Amortization (DD&A)

1,259

1,193

1,226

1,169

1,053

Total Operating Cost (GAAP) (excluding Total Exploration Costs) - (h)

3,113

2,898

2,898

2,806

2,442

Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (i)

3,113

2,898

2,890

2,738

2,424

Exploration Costs

47

45

50

71

74

Dry Hole Costs

30

23

4

—

11

Impairments

19

39

689

71

39

Total Exploration Costs (GAAP)

96

107

743

142

124

Less: Certain Impairments (5)

—

—

(646)

—

(11)

Total Exploration Costs (Non-GAAP)

96

107

97

142

113

Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) - (j)

3,209

3,005

3,641

2,948

2,566

Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non- GAAP)) - (k)

3,209

3,005

2,987

2,880

2,537

Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas less Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP))

3,274

2,257

863

1,606

1,542

Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas less Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non-GAAP))

3,274

2,257

1,517

1,674

1,571

Revenues, Costs and Margins Per Barrel of Oil Equivalent (Continued)

In millions of USD, except Boe and per Boe amounts (Unaudited)

2Q 2026

1Q 2026

4Q 2025

3Q 2025

2Q 2025

Per Barrel of Oil Equivalent (Boe) Calculations (GAAP)

Composite Average Operating Revenues and Other per Boe - (b) / (a)

67.19

55.59

43.81

48.85

53.08

Composite Average Operating Expenses per Boe - (c) / (a)

39.69

34.72

36.48

33.51

36.15

Composite Average Operating Income per Boe - (d) / (a)

27.50

20.87

7.33

15.34

16.93

Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe - (e) / (a)

50.52

42.24

34.99

38.05

39.80

Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - (f) / (a)

14.45

13.69

12.99

13.67

13.46

Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) - [(e) / (a) - (f) / (a)]

36.07

28.55

22.00

24.38

26.34

Total Operating Cost per Boe (excluding Total Exploration Costs) - (h) / (a)

24.26

23.27

22.52

23.44

23.66

Composite Average Margin per Boe (excluding Total Exploration Costs) - [(e) / (a) - (h) / (a)]

26.26

18.97

12.47

14.61

16.14

Total Operating Cost per Boe (including Total Exploration Costs) - (j) / (a)

25.01

24.13

28.29

24.63

24.86

Composite Average Margin per Boe (including Total Exploration Costs) - [(e) / (a) - (j) / (a)]

25.51

18.11

6.70

13.42

14.94

Per Barrel of Oil Equivalent (Boe) Calculations (Non-GAAP)

Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - (g) / (a)

14.45

13.69

12.93

13.10

13.30

Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) - [(e) / (a) - (g) / (a)]

36.07

28.55

22.06

24.95

26.50

Total Operating Cost per Boe (excluding Total Exploration Costs) - (i) / (a)

24.26

23.27

22.46

22.87

23.50

Composite Average Margin per Boe (excluding Total Exploration Costs) - [(e) / (a) - (i) / (a)]

26.26

18.97

12.53

15.18

16.30

Total Operating Cost per Boe (including Total Exploration Costs) - (k) / (a)

25.01

24.13

23.21

24.06

24.59

Composite Average Margin per Boe (including Total Exploration Costs) - [(e) / (a) - (k) / (a)]

25.51

18.11

11.78

13.99

15.21

Revenues, Costs and Margins Per Barrel of Oil Equivalent (Continued)

In millions of USD, except Boe and per Boe amounts (Unaudited)

2025

2024

2023

2022

2021

Volume - Million Barrels of Oil Equivalent - (a)

449.8

388.7

359.4

331.5

302.5

Total Operating Revenues and Other - (b)

22,632

23,698

24,186

25,702

18,642

Total Operating Expenses - (c)

16,247

15,616

14,583

15,736

12,540

Operating Income (Loss) - (d)

6,385

8,082

9,603

9,966

6,102

Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas

Crude Oil and Condensate

12,501

13,921

13,748

16,367

11,125

Natural Gas Liquids

2,376

2,106

1,884

2,648

1,812

Natural Gas

2,791

1,551

1,744

3,781

2,444

Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas - (e)

17,668

17,578

17,376

22,796

15,381

Operating Costs

Lease and Well

1,675

1,572

1,454

1,331

1,135

Gathering, Processing and Transportation Costs (1)

2,134

1,722

1,620

1,587

1,422

General and Administrative (GAAP)

820

669

640

570

511

Less: Certain Items (see Endnote 7 to Additional Key Financial Information below)

(88)

(10)

—

(16)

—

General and Administrative (Non-GAAP) (2)

732

659

640

554

511

Taxes Other Than Income (GAAP)

1,234

1,249

1,284

1,585

1,047

Add: Severance Tax Refund

—

31

—

115

—

Taxes Other Than Income (Non-GAAP) (3)

1,234

1,280

1,284

1,700

1,047

Interest Expense, Net

235

138

148

179

178

Less: Acquisition-Related Financing Commitment Costs

(6)

—

—

—

—

Interest Expense, Net (Non-GAAP) (4)

229

138

148

179

178

Total Operating Cost (GAAP) (excluding DD&A and Total Exploration Costs) - (f)

6,098

5,350

5,146

5,252

4,293

Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration Costs) - (g)

6,004

5,371

5,146

5,351

4,293

Depreciation, Depletion and Amortization (DD&A)

4,461

4,108

3,492

3,542

3,651

Total Operating Cost (GAAP) (excluding Total Exploration Costs) - (h)

10,559

9,458

8,638

8,794

7,944

Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) - (i)

10,465

9,479

8,638

8,893

7,944

Exploration Costs

236

174

181

159

154

Dry Hole Costs

49

14

1

45

71

Impairments

843

391

202

382

376

Total Exploration Costs (GAAP)

1,128

579

384

586

601

Less: Certain Impairments (5)

(657)

(291)

(42)

(113)

(15)

Total Exploration Costs (Non-GAAP)

471

288

342

473

586

Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) - (j)

11,687

10,037

9,022

9,380

8,545

Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non- GAAP)) - (k)

10,936

9,767

8,980

9,366

8,530

Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas less Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP))

5,981

7,541

8,354

13,416

6,836

Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural Gas less Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non-GAAP))

6,732

7,811

8,396

13,430

6,851

Revenues, Costs and Margins Per Barrel of Oil Equivalent (Continued)

In millions of USD, except Boe and per Boe amounts (Unaudited)

2025

2024

2023

2022

2021

Per Barrel of Oil Equivalent (Boe) Calculations (GAAP)

Composite Average Operating Revenues and Other per Boe - (b) / (a)

50.32

60.97

67.30

77.53

61.63

Composite Average Operating Expenses per Boe - (c) / (a)

36.12

40.18

40.58

47.47

41.46

Composite Average Operating Income (Loss) per Boe - (d) / (a)

14.20

20.79

26.72

30.06

20.17

Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe - (e) / (a)

39.28

45.22

48.34

68.77

50.84

Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - (f) / (a)

13.54

13.76

14.31

15.84

14.19

Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) - [(e) / (a) - (f) / (a)]

25.74

31.46

34.03

52.93

36.65

Total Operating Cost per Boe (excluding Total Exploration Costs) - (h) / (a)

23.46

24.33

24.03

26.53

26.26

Composite Average Margin per Boe (excluding Total Exploration Costs) - [(e) / (a) - (h) / (a)]

15.82

20.89

24.31

42.24

24.58

Total Operating Cost per Boe (including Total Exploration Costs) - (j) / (a)

25.97

25.82

25.10

28.30

28.25

Composite Average Margin per Boe (including Total Exploration Costs) - [(e) / (a) - (j) / (a)]

13.31

19.40

23.24

40.47

22.59

Per Barrel of Oil Equivalent (Boe) Calculations (Non-GAAP)

Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) - (g) / (a)

13.34

13.82

14.31

16.14

14.19

Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) - [(e) / (a) - (g) / (a)]

25.94

31.40

34.03

52.63

36.65

Total Operating Cost per Boe (excluding Total Exploration Costs) - (i) / (a)

23.26

24.39

24.03

26.83

26.26

Composite Average Margin per Boe (excluding Total Exploration Costs) - [(e) / (a) - (i) / (a)]

16.02

20.83

24.31

41.94

24.58

Total Operating Cost per Boe (including Total Exploration Costs) - (k) / (a)

24.31

25.13

24.98

28.26

28.20

Composite Average Margin per Boe (including Total Exploration Costs) - [(e) / (a) - (k) / (a)]

14.97

20.09

23.36

40.51

22.64

(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)

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.

(3)

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.

(4)

EOG believes excluding the above-referenced items from Interest Expense, Net is appropriate and provides useful information to investors, as EOG views such items as non-recurring.

(5)

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).

Additional Key Financial Information

(Unaudited)

See "Endnotes" below for related discussion and definitions.

2025 Actual

2024 Actual

2023 Actual

2022 Actual

2021 Actual

Crude Oil and Condensate Volumes (MBod)

United States

520.5

490.6

475.2

460.7

443.4

Trinidad

1.4

0.8

0.6

0.6

1.5

Other International

—

—

—

—

0.1

Total

521.9

491.4

475.8

461.3

445.0

Natural Gas Liquids Volumes (MBbld)

Total

288.2

245.9

223.8

197.7

144.5

Natural Gas Volumes (MMcfd)

United States

2,299

1,728

1,551

1,315

1,210

Trinidad

230

220

160

180

217

Other International1

4

—

—

—

9

Total

2,533

1,948

1,711

1,495

1,436

Crude Oil Equivalent Volumes (MBoed)

United States

1,191.8

1,024.5

957.5

877.5

789.6

Trinidad

39.8

37.6

27.3

30.7

37.7

Other International

0.6

—

—

—

1.6

Total

1,232.2

1,062.1

984.8

908.2

828.9

Benchmark Price

Oil (WTI) ($/Bbl)

64.78

75.72

77.61

94.23

67.96

Natural Gas (HH) ($/Mcf)

3.43

2.27

2.74

6.64

3.85

Crude Oil and Condensate - above (below) WTI2 ($/Bbl)

United States

0.87

1.70

1.57

2.99

0.58

Trinidad

(7.19)

(11.29)

(9.03)

(8.07)

(11.70)

Other International

0.36

—

—

—

—

Natural Gas Liquids - Realizations as % of WTI

Total

34.9 %

30.9 %

29.7 %

39.0 %

50.5 %

Natural Gas - above (below) NYMEX Henry Hub3 ($/Mcf)

United States

(0.49)

(0.28)

(0.04)

0.63

1.03

Natural Gas Realizations4 ($/Mcf)

Trinidad

3.78

3.65

3.65

4.43

3.40

Other International1

3.28

—

—

—

—

Total Expenditures (GAAP) ($MM)

13,703

6,653

6,818

5,610

4,255

Capital Expenditures5 (Non-GAAP) ($MM)

6,294

6,226

6,041

4,607

3,755

Operating Unit Costs ($/Boe)

Lease and Well

3.72

4.04

4.05

4.02

3.75

Gathering, Processing and Transportation Costs6

4.74

4.43

4.50

4.78

4.70

General and Administrative (GAAP)

1.82

1.72

1.78

1.72

1.69

General and Administrative (Non-GAAP)7

1.63

1.70

1.78

1.67

1.69

Cash Operating Costs (GAAP)

10.28

10.19

10.33

10.52

10.14

Cash Operating Costs (Non-GAAP)7

10.09

10.17

10.33

10.47

10.14

Depreciation, Depletion and Amortization

9.92

10.57

9.72

10.69

12.07

Expenses ($MM)

Exploration and Dry Hole

285

188

182

204

225

Impairment (GAAP)

843

391

202

382

376

Impairment (excluding certain impairments (Non-GAAP))8

186

100

160

269

361

Capitalized Interest

86

45

33

36

33

Net Interest

235

138

148

179

178

Net Interest (Non-GAAP)9

229

—

—

—

—

TOTI (% of revenues from sales of crude oil and condensate, NGLs and natural gas)

(GAAP)

7.0 %

7.1 %

7.4 %

7.0 %

6.8 %

(Non-GAAP)7

7.0 %

7.3 %

7.4 %

7.5 %

6.8 %

Income Taxes

Effective Rate

21.7 %

22.1 %

21.6 %

21.7 %

21.4 %

Current Tax Expense ($MM)

1,039

1,348

1,415

2,208

1,393

Additional Key Financial Information (Continued)

Endnotes

2025 volumes are from Bahrain operations; natural gas realized price represents contract price less partner's processing and distribution costs.

EOG bases United States, Trinidad and Other International crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the daily settlement prices for the prompt-month NYMEX futures contract for each of the applicable calendar months.

EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the NYMEX Last Day Settle price for each of the applicable months.

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.

Capital Expenditures include expenditures for Exploration and Development Drilling, Facilities, Leasehold Acquisitions, Capitalized Interest, Dry Hole Costs and Other Property, Plant and Equipment. Capital Expenditures exclude Property Acquisitions, Asset Retirement Costs, Non-Cash Exchanges and Transactions and exploration costs incurred as operating expenses.

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.

Cash Operating Costs consist of LOE, GP&T and G&A. G&A (Non-GAAP) for fiscal year 2025 excludes costs related to the Encino acquisition, as reflected in the accompanying reconciliation schedules (see "Revenues, Costs and Margins Per Barrel of Oil Equivalent"). In addition, TOTI (% of revenues from sales of crude oil and condensate, NGLs and natural gas) (Non-GAAP) and G&A (Non-GAAP) for 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 acquisition-related costs and consulting fees on G&A and total Cash Operating Costs for fiscal year 2025, 2024 and 2022 was $(0.19), $(0.02) and $(0.05), respectively.

In general, EOG excludes impairments which are (i) attributable to declines in commodity prices, (ii) related to sales of certain oil and gas properties or (iii) the result of certain other events or decisions (e.g., a periodic review of EOG's oil and gas properties or other assets). EOG believes excluding these impairments from total impairment costs is appropriate and provides useful information to investors, as such impairments were caused by factors outside of EOG's control (versus, for example, impairments that are due to EOG's proved oil and gas properties not being as productive as it originally estimated). Impairments (Non-GAAP) for FY 2025 are adjusted from Impairments (GAAP) for FY 2025 by excluding $657 million of impairments, primarily associated with the write-down to fair value of natural gas and crude oil assets in the Barnett Shale and Woodford Oil Window (mainly driven by play-specific economics and resource allocation). Impairments (Non-GAAP) for FY 2024 are adjusted from Impairments (GAAP) for FY 2024 by excluding $291 million of impairments, primarily associated with the write-down to fair value of natural gas and crude oil assets in the Rocky Mountain area.

Net Interest for fiscal year 2025 excludes financing commitment costs related to the Encino acquisition, as reflected in the accompanying reconciliation schedules (see "Revenues, Costs and Margins Per Barrel of Oil Equivalent"). The per-Boe impact of such cost for fiscal year 2025 is $(0.01).