EOG Resources Reports Fourth Quarter and Full-Year 2025 Results; Announces 2026 Capital Plan

HOUSTON, Feb. 24, 2026 /PRNewswire/ -- EOG Resources, Inc. (EOG) today reported fourth quarter and full-year 2025 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.

Fourth Quarter Highlights

Full-Year 2025 Highlights

2026 Outlook

CEO Commentary

"2025 was a year of exceptional operational execution for EOG. We exceeded our original oil and total volume targets, capital expenditures were on target, and we continued driving down both well costs and cash operating costs. Our differentiated marketing strategy delivered peer-leading U.S. price realizations, further strengthening margins.

Operational excellence drove outstanding financial results and peer-leading cash returns to shareholders. We generated $4.7 billion in free cash flow and returned 100% to shareholders through our sustainable, growing regular dividend, which increased 8%, and $2.5 billion in share repurchases. Since initiating buybacks in 2023, we've reduced our share count by approximately 10%. Our robust cash generation and pristine balance sheet position EOG to deliver shareholder value through industry cycles.

2025 was also a year of transformational transactions with the strategic Encino acquisition and our entry into exciting international exploration opportunities in the UAE and Bahrain. EOG's differentiated portfolio has never been stronger. Looking ahead, we have a disciplined plan for 2026 targeting $4.5 billion in free cash flow using the midpoints of guidance at current strip pricing. Our strategy prioritizes activity in the Delaware Basin, Utica and Eagle Ford while increasing activity in Dorado alongside continued international investment. EOG's relentless focus on returns, our diverse multi-basin portfolio and industry-leading exploration capabilities provide clear visibility to sustain high returns and robust free cash flow generation for years to come."

Return of Capital

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

During the fourth quarter, the company repurchased 6.3 million shares for $675 million under its share repurchase authorization, at an average purchase price of $107 per share.

For full-year 2025, the company repurchased 21.7 million shares for $2.5 billion under its share repurchase authorization, at an average purchase price of $115 per share. At December 31, 2025, EOG had $3.3 billion remaining on its current repurchase authorization.

2025 Reserves

Total proved reserves increased 16% in 2025 to 5.5 Billion Boe. Extensions and discoveries added 336 MMBoe of proved reserves in 2025. Revisions other than price increased proved reserves by 65 MMBoe. Net proved reserve additions from all sources, excluding price revisions, replaced 254% of 2025 total production.

2026 Capital Program

Total expenditures for 2026 are expected to range from $6.3 to $6.7 billion, including exploration and development drilling, facilities, leasehold acquisitions, capitalized interest, dry hole costs, and other property, plant and equipment, and excluding property acquisitions, asset retirement costs and non-cash exchanges and transactions. The capital program also excludes certain exploration costs incurred as operating expenses.

The plan holds 4Q 2025 oil production flat through 2026. Under the 2026 program, total oil production growth is 5% and total production growth is 13% year-over-year, inclusive of the Encino acquisition. EOG plans to complete 585 net wells in 2026 across our domestic multi-basin portfolio of high-return inventory.

The 2026 program targets low single-digit percentage average well cost reduction, benefiting from increasing lateral lengths and other sustainable efficiency gains. We expect higher overall activity in the Utica and Dorado, as well as continued advancement of exploration prospects in the UAE and Bahrain.

Key Financial Results

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

GAAP

4Q 2025

3Q 2025

2Q 2025

1Q 2025

4Q 2024

FY 2025

FY 2024

Total Revenue

5,638

5,847

5,478

5,669

5,585

22,632

23,698

Net Income

701

1,471

1,345

1,463

1,251

4,980

6,403

Net Income Per Share

1.30

2.70

2.46

2.65

2.23

9.12

11.25

Net Cash Provided by Operating Activities

2,612

3,111

2,032

2,289

2,763

10,044

12,143

Total Expenditures

1,730

8,544

1,883

1,546

1,446

13,703

6,653

Current and Long-Term Debt

7,936

7,694

4,236

4,744

4,752

7,936

4,752

Cash and Cash Equivalents

3,396

3,530

5,216

6,599

7,092

3,396

7,092

Debt-to-Total Capitalization

21.0 %

20.3 %

12.7 %

13.8 %

13.9 %

21.0 %

13.9 %

Cash Operating Costs ($/Boe)

10.28

10.50

10.05

10.31

10.15

10.28

10.19

Non–GAAP

Adjusted Net Income

1,222

1,472

1,268

1,586

1,535

5,548

6,612

Adjusted Net Income Per Share

2.27

2.71

2.32

2.87

2.74

10.16

11.62

Adjusted CFO 1

2,617

3,031

2,496

2,813

2,635

10,957

11,593

Capital Expenditures

1,639

1,648

1,523

1,484

1,358

6,294

6,226

Free Cash Flow

978

1,383

973

1,329

1,277

4,663

5,367

Net Debt

4,540

4,164

(980)

(1,855)

(2,340)

4,540

(2,340)

Net Debt-to-Total Capitalization

13.2 %

12.1 %

(3.5 %)

(6.7 %)

(8.7 %)

13.2 %

(8.7 %)

Cash Operating Costs ($/Boe) 2

10.22

9.93

9.94

10.31

10.15

10.09

10.17

Key Operational Results

Volumes

4Q 2025

3Q 2025

2Q 2025

1Q 2025

4Q 2024

FY 2025

FY 2024

Crude Oil and Condensate (MBod)

546.1

534.5

504.2

502.1

494.6

521.9

491.4

Natural Gas Liquids (MBbld)

342.1

309.3

258.4

241.7

252.5

288.2

245.9

Natural Gas (MMcfd)

3,065

2,745

2,229

2,080

2,092

2,533

1,948

Total Crude Oil Equivalent (MBoed)

1,399.0

1,301.2

1,134.1

1,090.4

1,095.7

1,232.2

1,062.1

Cash Operating Costs ($/Boe)

Lease & Well

3.47

3.60

3.84

4.09

3.91

3.72

4.04

Gathering, Processing & Transportation Costs

5.07

4.90

4.41

4.48

4.37

4.74

4.43

General & Administrative (GAAP)

1.74

2.00

1.80

1.74

1.87

1.82

1.72

General & Administrative (Non-GAAP) 2

1.68

1.43

1.69

1.74

1.87

1.63

1.70

Cash Operating Costs (GAAP)

10.28

10.50

10.05

10.31

10.15

10.28

10.19

Cash Operating Costs (Non-GAAP) 2

10.22

9.93

9.94

10.31

10.15

10.09

10.17

Depreciation, Depletion & Amortization ($/Boe)

9.53

9.77

10.20

10.32

10.11

9.92

10.57

Fourth Quarter 2025 Results vs Guidance

4Q 2025

(Unaudited)

4Q 2025

Guidance

Midpoint 4

Variance

3Q 2025

2Q 2025

1Q 2025

4Q 2024

Crude Oil and Condensate Volumes (MBod)

United States

544.5

543.7

0.8

532.9

503.1

500.9

493.5

Trinidad

1.5

1.3

0.2

1.6

1.1

1.2

1.1

Other International 5

0.1

0.0

0.1

0.0

0.0

0.0

0.0

Total

546.1

545.0

1.1

534.5

504.2

502.1

494.6

Natural Gas Liquids Volumes (MBbld)

Total

342.1

323.0

19.1

309.3

258.4

241.7

252.5

Natural Gas Volumes (MMcfd)

United States

2,859

2,790

69

2,511

1,977

1,834

1,840

Trinidad

195

200

(5)

230

252

246

252

Other International 5

11

0

11

4

0

0

0

Total

3,065

2,990

75

2,745

2,229

2,080

2,092

Total Crude Oil Equivalent Volumes (MBoed)

1,399.0

1,366.4

32.6

1,301.2

1,134.1

1,090.4

1,095.7

Total MMBoe

128.7

125.7

3.0

119.7

103.2

98.1

100.8

Benchmark Price

Oil (WTI) ($/Bbl)

59.17

64.95

63.71

71.42

70.28

Natural Gas (HH) ($/Mcf)

3.55

3.07

3.44

3.66

2.79

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

United States

0.37

0.25

0.12

1.02

1.13

1.48

1.40

Trinidad

(2.10)

(4.00)

1.90

(7.21)

(9.21)

(10.30)

(9.81)

Other International 5

4.81

0.00

4.81

0.00

0.00

0.00

0.00

Natural Gas Liquids - Realizations as % of WTI

Total

35.7 %

33.0 %

2.7 %

32.7 %

35.6 %

36.8 %

33.9 %

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

United States

(0.61)

(0.45)

(0.16)

(0.36)

(0.57)

(0.30)

(0.40)

Natural Gas Realizations ($/Mcf)

Trinidad

3.94

3.60

0.34

3.80

3.65

3.78

3.86

Other International 5

3.29

0.00

3.29

3.27

0.00

0.00

0.00

Total Expenditures (GAAP) ($MM)

1,730

8,544

1,883

1,546

1,446

Capital Expenditures (Non-GAAP) ($MM)

1,639

1,650

(11)

1,648

1,523

1,484

1,358

Operating Unit Costs ($/Boe)

Lease and Well

3.47

3.75

(0.28)

3.60

3.84

4.09

3.91

Gathering, Processing and Transportation Costs

5.07

5.00

0.07

4.90

4.41

4.48

4.37

General &Administrative (GAAP)

1.74

1.55

0.19

2.00

1.80

1.74

1.87

General & Administrative (Non-GAAP) 2

1.68

1.55

0.13

1.43

1.69

1.74

1.87

Cash Operating Costs (GAAP)

10.28

10.30

(0.02)

10.50

10.05

10.31

10.15

Cash Operating Costs (Non-GAAP) 2

10.22

10.30

(0.08)

9.93

9.94

10.31

10.15

Depreciation, Depletion and Amortization

9.53

9.75

(0.22)

9.77

10.20

10.32

10.11

Expenses ($MM)

Exploration and Dry Hole

54

60

(6)

71

85

75

60

Impairment (GAAP)

689

71

39

44

276

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

43

70

(27)

71

28

44

23

Capitalized Interest

36

36

0

27

11

12

13

Net Interest (GAAP)

66

66

0

71

51

47

38

Net Interest (Non-GAAP) 9

66

66

0

71

45

47

38

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

(GAAP)

6.3 %

7.0 %

(0.7 %)

6.8 %

7.3 %

7.6 %

6.8 %

(Non-GAAP)

6.3 %

7.0 %

(0.7 %)

6.8 %

7.3 %

7.6 %

6.8 %

Income Taxes

Effective Rate

22.8 %

22.5 %

0.3 %

19.4 %

23.2 %

22.1 %

23.0 %

Current Tax Expense ($MM)

293

270

23

75

301

370

454

First Quarter and Full-Year 2026 Guidance 10

(Unaudited)

1Q 2026

Guidance Range

1Q 2026

Midpoint

FY 2026

Guidance Range

FY 2026

Midpoint

Crude Oil and Condensate Volumes (MBod)

United States

542.4

-

547.0

544.7

542.7

-

547.3

545.0

Trinidad

1.6

-

2.0

1.8

1.3

-

1.7

1.5

Total

544.0

-

549.0

546.5

544.0

-

549.0

546.5

Natural Gas Liquids Volumes (MBbld)

320.0

-

340.0

330.0

325.0

-

345.0

335.0

Total

Natural Gas Volumes (MMcfd)

United States

2,700

-

2,800

2,750

2,810

-

2,910

2,860

Trinidad

225

-

245

235

215

-

235

225

Total

2,925

-

3,045

2,985

3,025

-

3,145

3,085

Crude Oil Equivalent Volumes (MBoed)

United States

1,312.4

-

1,353.7

1,333.1

1,336.0

-

1,377.3

1,356.7

Trinidad

39.1

-

42.8

41.0

37.1

-

40.9

39.0

Total

1,351.5

-

1,396.5

1,374.0

1,373.1

-

1,418.2

1,395.7

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

United States

(1.00)

-

0.50

(0.25)

(1.00)

-

1.00

0.00

Trinidad

(4.75)

-

(3.25)

(4.00)

(3.50)

-

(1.50)

(2.50)

Natural Gas Liquids - Realizations as % of WTI

Total

26.0 %

- 36.0%

31.0 %

26.0 %

- 36.0%

31.0 %

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

United States

(1.65)

-

(0.95)

(1.30)

(1.60)

-

0.40

(0.60)

Natural Gas Realizations ($/Mcf)

Trinidad

3.15

-

3.85

3.50

3.00

-

4.00

3.50

Capital Expenditures 11(Non-GAAP) ($MM)

1,575

-

1,675

1,625

6,300

-

6,700

6,500

Operating Unit Costs ($/Boe)

Lease and Well

3.50

-

4.00

3.75

3.50

-

4.00

3.75

Gathering, Processing and Transportation Costs

4.95

-

5.45

5.20

4.95

-

5.45

5.20

General & Administrative

1.40

-

1.70

1.55

1.40

-

1.70

1.55

Cash Operating Costs

9.85

-

11.15

10.50

9.85

-

11.15

10.50

Depreciation, Depletion and Amortization

9.10

-

10.10

9.60

9.35

-

10.35

9.85

Expenses ($MM)

Exploration and Dry Hole

30

-

70

50

195

-

235

215

Impairment (excluding certain impairments 8

30

-

110

70

190

-

370

280

Capitalized Interest

35

-

39

37

147

-

151

149

Net Interest

65

-

69

67

267

-

271

269

TOTI (% of Wellhead Revenue) (GAAP)

6.0 %

-

8.0 %

7.0 %

5.8 %

-

7.8 %

6.8 %

TOTI (% of Wellhead Revenue) (Non-GAAP)

Income Taxes

Effective Rate

20.0 %

-

26.0 %

23.0 %

20.0 %

-

26.0 %

23.0 %

Current Tax Expense ($MM)

230

-

330

280

925

-

1,325

1,125

Fourth Quarter and Full-Year 2025 Results Webcast

Wednesday, February 25, 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

Media Contact

Kimberly Ehmer 713-571-4676

Endnotes

1)

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

2)

Cash Operating Costs consist of LOE, GP&T and G&A. 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 "Fourth Quarter 2025 Results vs Guidance" above.

3)

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.

4)

GAAP and Non-GAAP distinctions apply solely to actual results and do not pertain to EOG's fourth quarter 2025 guidance midpoint disclosures.

5)

Production volumes from Bahrain operations; realized price represents contract price less Bapco's processing and distribution costs.

6)

EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month.

7)

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.

8)

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). Impairments (Non-GAAP) for 4Q 2024 are adjusted from Impairments (GAAP) for 4Q 2024 by excluding $253 million of impairments, primarily associated with the write- down to fair value of natural gas and crude oil assets in the Rocky Mountain area.

9)

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

10)

The forecast items for the first 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.

11)

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 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:

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, 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, 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)

2024

2025

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

3,480

3,692

3,488

3,261

13,921

3,293

2,974

3,243

2,991

12,501

Natural Gas Liquids

513

515

524

554

2,106

572

534

604

666

2,376

Natural Gas

382

303

372

494

1,551

637

600

707

847

2,791

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

237

(47)

79

(65)

204

(191)

107

116

(19)

13

Gathering, Processing and Marketing

1,459

1,519

1,481

1,341

5,800

1,340

1,247

1,178

1,149

4,914

Gains (Losses) on Asset Dispositions, Net

26

20

(7)

(23)

16

(1)

—

(18)

(16)

(35)

Other, Net

26

23

28

23

100

19

16

17

20

72

Total

6,123

6,025

5,965

5,585

23,698

5,669

5,478

5,847

5,638

22,632

Operating Expenses

Lease and Well

396

390

392

394

1,572

401

396

431

447

1,675

Gathering, Processing and Transportation Costs

413

423

445

441

1,722

440

455

587

652

2,134

Exploration Costs

45

34

43

52

174

41

74

71

50

236

Dry Hole Costs

1

5

—

8

14

34

11

—

4

49

Impairments

19

81

15

276

391

44

39

71

689

843

Marketing Costs

1,404

1,490

1,500

1,323

5,717

1,325

1,216

1,134

1,120

4,795

Depreciation, Depletion and Amortization

1,074

984

1,031

1,019

4,108

1,013

1,053

1,169

1,226

4,461

General and Administrative

162

151

167

189

669

171

186

239

224

820

Taxes Other Than Income

338

337

283

291

1,249

341

301

309

283

1,234

Total

3,852

3,895

3,876

3,993

15,616

3,810

3,731

4,011

4,695

16,247

Operating Income

2,271

2,130

2,089

1,592

8,082

1,859

1,747

1,836

943

6,385

Other Income, Net

62

66

76

70

274

65

55

59

33

212

Income Before Interest Expense and Income Taxes

2,333

2,196

2,165

1,662

8,356

1,924

1,802

1,895

976

6,597

Interest Expense, Net

33

36

31

38

138

47

51

71

66

235

Income Before Income Taxes

2,300

2,160

2,134

1,624

8,218

1,877

1,751

1,824

910

6,362

Income Tax Provision

511

470

461

373

1,815

414

406

353

209

1,382

Net Income

1,789

1,690

1,673

1,251

6,403

1,463

1,345

1,471

701

4,980

Dividends Declared per Common Share

0.9100

0.9100

0.9100

0.9750

3.7050

0.9750

1.9950

—

1.0200

3.9900

Net Income Per Share

Basic

3.11

2.97

2.97

2.25

11.31

2.66

2.48

2.72

1.31

9.17

Diluted

3.10

2.95

2.95

2.23

11.25

2.65

2.46

2.70

1.30

9.12

Average Number of Common Shares

Basic

575

569

564

557

566

550

543

541

537

543

Diluted

577

572

568

561

569

553

546

544

539

546

Volumes and Prices

(Unaudited)

2024

2025

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

486.8

490.1

491.8

493.5

490.6

500.9

503.1

532.9

544.5

520.5

Trinidad

0.6

0.6

1.2

1.1

0.8

1.2

1.1

1.6

1.5

1.4

Other International (C)

—

—

—

—

—

—

—

—

0.1

—

Total

487.4

490.7

493.0

494.6

491.4

502.1

504.2

534.5

546.1

521.9

Average Crude Oil and Condensate Prices

($/Bbl) (B)

United States

$ 78.46

$ 82.71

$ 76.95

$ 71.68

$ 77.42

$ 72.90

$ 64.84

$ 65.97

$ 59.54

$ 65.65

Trinidad

67.50

70.75

63.15

60.47

64.43

61.12

54.50

57.74

57.07

57.59

Other International (C)

—

—

—

—

—

—

—

—

63.98

—

Composite

78.45

82.69

76.92

71.66

77.40

72.87

64.82

65.95

59.54

65.63

Natural Gas Liquids Volumes (MBbld) (A)

United States

231.7

244.8

254.3

252.5

245.9

241.7

258.4

309.3

342.1

288.2

Total

231.7

244.8

254.3

252.5

245.9

241.7

258.4

309.3

342.1

288.2

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

United States

$ 24.32

$ 23.11

$ 22.42

$ 23.85

$ 23.40

$ 26.29

$ 22.70

$ 21.25

$ 21.15

$ 22.58

Composite

24.32

23.11

22.42

23.85

23.40

26.29

22.70

21.25

21.15

22.58

Natural Gas Volumes (MMcfd) (A)

United States

1,658

1,668

1,745

1,840

1,728

1,834

1,977

2,511

2,859

2,299

Trinidad

200

204

225

252

220

246

252

230

195

230

Other International (C)

—

—

—

—

—

—

—

4

11

4

Total

1,858

1,872

1,970

2,092

1,948

2,080

2,229

2,745

3,065

2,533

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

United States

$ 2.10

$ 1.57

$ 1.84

$ 2.39

$ 1.99

$ 3.36

$ 2.87

$ 2.71

$ 2.94

$ 2.94

Trinidad

3.54

3.48

3.68

3.86

3.65

3.78

3.65

3.80

3.94

3.78

Other International (C)

—

—

—

—

—

—

—

3.27

3.29

3.28

Composite

2.26

1.78

2.05

2.57

2.17

3.41

2.96

2.80

3.00

3.02

Crude Oil Equivalent Volumes (MBoed) (D)

United States

994.7

1,013.0

1,037.1

1,052.7

1,024.5

1,048.3

1,090.9

1,260.7

1,363.0

1,191.8

Trinidad

34.1

34.5

38.6

43.0

37.6

42.1

43.2

39.8

34.2

39.8

Other International (C)

—

—

—

—

—

—

—

0.7

1.8

0.6

Total

1,028.8

1,047.5

1,075.7

1,095.7

1,062.1

1,090.4

1,134.1

1,301.2

1,399.0

1,232.2

Total MMBoe (D)

93.6

95.3

99.0

100.8

388.7

98.1

103.2

119.7

128.7

449.8

(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, 2025).

(C)

Production volumes from Bahrain operations; realized price represents contract price less Bapco's processing and distribution costs.

(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)

2024

2025

MAR

JUN

SEP

DEC

MAR

JUN

SEP

DEC

Current Assets

Cash and Cash Equivalents

5,292

5,431

6,122

7,092

6,599

5,216

3,530

3,396

Accounts Receivable, Net

2,688

2,657

2,545

2,650

2,621

2,504

2,680

2,681

Inventories

1,154

1,069

1,038

985

897

934

945

1,014

Assets from Price Risk Management Activities

110

4

—

—

—

—

19

18

Other (A)

684

642

460

503

563

591

646

547

Total

9,928

9,803

10,165

11,230

10,680

9,245

7,820

7,656

Property, Plant and Equipment

Oil and Gas Properties (Successful Efforts Method)

73,356

74,615

75,887

77,091

78,432

80,139

88,301

89,857

Other Property, Plant and Equipment

5,768

6,078

6,314

6,418

6,510

6,616

6,772

6,832

Total Property, Plant and Equipment

79,124

80,693

82,201

83,509

84,942

86,755

95,073

96,689

Less: Accumulated Depreciation, Depletion and

Amortization

(46,047)

(47,049)

(48,075)

(49,297)

(50,310)

(51,394)

(52,488)

(54,348)

Total Property, Plant and Equipment, Net

33,077

33,644

34,126

34,212

34,632

35,361

42,585

42,341

Deferred Income Taxes

38

44

42

39

44

39

37

39

Other Assets

1,753

1,733

1,818

1,705

1,626

1,639

1,757

1,763

Total Assets

44,796

45,224

46,151

47,186

46,982

46,284

52,199

51,799

Current Liabilities

Accounts Payable

2,389

2,436

2,290

2,464

2,353

2,266

2,944

2,904

Accrued Taxes Payable

786

600

855

1,007

668

348

392

299

Dividends Payable

523

516

513

539

534

1,081

550

544

Liabilities from Price Risk Management Activities

—

8

32

116

276

85

17

—

Current Portion of Long-Term Debt

34

534

34

532

1,280

778

27

27

Current Portion of Operating Lease Liabilities

318

303

338

315

318

360

433

472

Other

223

231

344

381

290

257

452

445

Total

4,273

4,628

4,406

5,354

5,719

5,175

4,815

4,691

Long-Term Debt

3,757

3,250

3,742

4,220

3,464

3,458

7,667

7,909

Other Liabilities

2,533

2,456

2,480

2,395

2,368

2,398

2,496

2,512

Deferred Income Taxes

5,597

5,731

5,949

5,866

5,915

6,015

6,936

6,854

Commitments and Contingencies

Stockholders' Equity

Common Stock, $0.01 Par

206

206

206

206

206

206

206

206

Additional Paid in Capital

6,188

6,219

6,058

6,090

6,095

6,153

5,978

6,027

Accumulated Other Comprehensive Loss

(8)

(8)

(9)

(4)

(4)

(7)

(5)

(7)

Retained Earnings

23,897

25,071

26,231

26,941

27,869

28,131

29,603

29,765

Common Stock Held in Treasury

(1,647)

(2,329)

(2,912)

(3,882)

(4,650)

(5,245)

(5,497)

(6,158)

Total Stockholders' Equity

28,636

29,159

29,574

29,351

29,516

29,238

30,285

29,833

Total Liabilities and Stockholders' Equity

44,796

45,224

46,151

47,186

46,982

46,284

52,199

51,799

(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 Statements

In millions of USD (Unaudited)

2024

2025

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

1,789

1,690

1,673

1,251

6,403

1,463

1,345

1,471

701

4,980

Items Not Requiring (Providing) Cash

Depreciation, Depletion and Amortization

1,074

984

1,031

1,019

4,108

1,013

1,053

1,169

1,226

4,461

Impairments

19

81

15

276

391

44

39

71

689

843

Stock-Based Compensation Expenses

45

45

58

51

199

50

53

53

60

216

Deferred Income Taxes

199

128

220

(80)

467

44

105

278

(84)

343

(Gains) Losses on Asset Dispositions, Net

(26)

(20)

7

23

(16)

1

—

18

16

35

Other, Net

9

3

2

3

17

11

11

2

3

27

Dry Hole Costs

1

5

—

8

14

34

11

—

4

49

Mark-to-Market Financial Commodity and Other

Derivative Contracts (Gains) Losses, Net

(237)

47

(79)

65

(204)

191

(107)

(116)

19

(13)

Net Cash Received from (Payments for)

Settlements of Financial Commodity Derivative Contracts

55

79

61

19

214

(38)

(24)

27

(21)

(56)

Other, Net

—

—

—

—

—

—

—

—

(1)

(1)

Changes in Components of Working Capital and

Other Assets and Liabilities

Accounts Receivable

58

33

109

(99)

101

48

122

133

(3)

300

Inventories

117

75

30

37

259

76

(45)

4

(84)

(49)

Accounts Payable

(58)

29

(159)

152

(36)

(129)

(107)

5

(40)

(271)

Accrued Taxes Payable

319

(185)

256

151

541

(339)

(321)

28

(103)

(735)

Other Assets

(161)

42

197

(34)

44

(43)

(43)

(28)

97

(17)

Other Liabilities

(71)

(20)

108

6

23

(96)

(52)

155

10

17

Changes in Components of Working Capital

Associated with Investing Activities

(229)

(127)

59

(85)

(382)

(41)

(8)

(159)

123

(85)

Net Cash Provided by Operating Activities

2,903

2,889

3,588

2,763

12,143

2,289

2,032

3,111

2,612

10,044

Investing Cash Flows

Acquisition of Encino Acquisition Partners, LLC,

Net of Cash Acquired

—

—

—

—

—

—

—

(4,464)

13

(4,451)

Additions to Oil and Gas Properties

(1,485)

(1,357)

(1,263)

(1,248)

(5,353)

(1,381)

(1,699)

(1,492)

(1,543)

(6,115)

Additions to Other Property, Plant and

Equipment

(350)

(313)

(239)

(117)

(1,019)

(102)

(94)

(171)

(112)

(479)

Proceeds from Sales of Assets

9

10

—

4

23

12

4

5

3

24

Changes in Components of Working Capital

Associated with Investing Activities

229

127

(59)

85

382

41

8

159

(123)

85

Net Cash Used in Investing Activities

(1,597)

(1,533)

(1,561)

(1,276)

(5,967)

(1,430)

(1,781)

(5,963)

(1,762)

(10,936)

Financing Cash Flows

Long-Term Debt Borrowings

—

—

—

985

985

—

—

3,472

999

4,471

Long-Term Debt Repayments

—

—

—

—

—

—

(500)

(1,266)

(750)

(2,516)

Dividends Paid

(525)

(520)

(533)

(509)

(2,087)

(538)

(528)

(545)

(550)

(2,161)

Treasury Stock Purchased

(759)

(699)

(795)

(993)

(3,246)

(806)

(602)

(479)

(677)

(2,564)

Proceeds from Stock Options Exercised and

Employee Stock Purchase Plan

—

11

—

11

22

—

11

—

12

23

Debt Issuance and Other Financing Costs

—

—

—

(2)

(2)

—

(7)

(7)

(11)

(25)

Repayment of Finance Lease Liabilities

(8)

(9)

(8)

(8)

(33)

(8)

(9)

(8)

(7)

(32)

Net Cash Used in Financing Activities

(1,292)

(1,217)

(1,336)

(516)

(4,361)

(1,352)

(1,635)

1,167

(984)

(2,804)

Effect of Exchange Rate Changes on Cash

—

–

–

(1)

(1)

—

1

(1)

–

—

Increase (Decrease) in Cash and Cash Equivalents

14

139

691

970

1,814

(493)

(1,383)

(1,686)

(134)

(3,696)

Cash and Cash Equivalents at Beginning of Period

5,278

5,292

5,431

6,122

5,278

7,092

6,599

5,216

3,530

7,092

Cash and Cash Equivalents at End of Period

5,292

5,431

6,122

7,092

7,092

6,599

5,216

3,530

3,396

3,396

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), 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.

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)

1Q 2025

Before

Tax

Income Tax

Impact

After

Tax

Diluted

Earnings

per Share

Reported Net Income (GAAP)

1,877

(414)

1,463

2.65

Adjustments:

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

191

(41)

150

0.26

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

(38)

8

(30)

(0.05)

Add: Losses on Asset Dispositions, Net

1

2

3

0.01

Adjustments to Net Income

154

(31)

123

0.22

Adjusted Net Income (Non-GAAP)

2,031

(445)

1,586

2.87

Average Number of Common Shares

Basic

550

Diluted

553

(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, 2025, such amount was $38 million.

4Q 2024

Before

Tax

Income Tax

Impact

After

Tax

Diluted

Earnings

per Share

Reported Net Income (GAAP)

1,624

(373)

1,251

2.23

Adjustments:

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

65

(14)

51

0.10

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

19

(4)

15

0.03

Add: Losses on Asset Dispositions, Net

23

(4)

19

0.03

Add: Certain Impairments (2)

254

(55)

199

0.35

Adjustments to Net Income

361

(77)

284

0.51

Adjusted Net Income (Non-GAAP)

1,985

(450)

1,535

2.74

Average Number of Common Shares

Basic

557

Diluted

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.

(2)

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

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)

3Q 2025 Net Income per Share (GAAP) - Diluted

2.70

Realized Prices

4Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe

34.99

Less: 3Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe

(38.05)

Subtotal

(3.06)

Multiplied by: 4Q 2025 Crude Oil Equivalent Volumes (MMBoe)

128.7

Total Change in Revenue

(394)

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

87

Change in Net Income

(307)

Change in Diluted Earnings per Share

(0.57)

Volumes

4Q 2025 Crude Oil Equivalent Volumes (MMBoe)

128.7

Less: 3Q 2025 Crude Oil Equivalent Volumes (MMBoe)

(119.7)

Subtotal

9.0

Multiplied by: 4Q 2025 Composite Average Margin per Boe (GAAP) (Including Total

Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent" schedule below)

6.70

Change in Margin

60

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

(13)

Change in Net Income

47

Change in Diluted Earnings per Share

0.09

Certain Operating Costs per Boe

3Q 2025 Total Cash Operating Costs (GAAP) and Total DD&A per Boe

20.27

Less: 4Q 2025 Total Cash Operating Costs (GAAP) and Total DD&A per Boe

(19.81)

Subtotal

0.46

Multiplied by: 4Q 2025 Crude Oil Equivalent Volumes (MMBoe)

128.7

Change in Before-Tax Net Income

59

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

(13)

Change in Net Income

46

Change in Diluted Earnings per Share

0.09

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

4Q 2025 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts

(19)

Less: Income Tax Benefit (Provision)

4

After Tax - (a)

(15)

Less: 3Q 2025 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts

116

Less: Income Tax Benefit (Provision)

(25)

After Tax - (b)

91

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

(106)

Change in Diluted Earnings per Share

(0.20)

Other (1)

(0.81)

4Q 2025 Net Income per Share (GAAP) - Diluted

1.30

4Q 2025 Average Number of Common Shares - Diluted

539

(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.

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)

FY 2024 Net Income per Share (GAAP) - Diluted

11.25

Realized Prices

FY 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe

39.28

Less: FY 2024 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe

(45.22)

Subtotal

(5.94)

Multiplied by: FY 2025 Crude Oil Equivalent Volumes (MMBoe)

449.8

Total Change in Revenue

(2,672)

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

588

Change in Net Income

(2,084)

Change in Diluted Earnings per Share

(3.82)

Volumes

FY 2025 Crude Oil Equivalent Volumes (MMBoe)

449.8

Less: FY 2024 Crude Oil Equivalent Volumes (MMBoe)

(388.7)

Subtotal

61.1

Multiplied by: FY 2025 Composite Average Margin per Boe (GAAP) (Including Total

Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent" schedule below)

13.31

Change in Margin

813

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

(179)

Change in Net Income

634

Change in Diluted Earnings per Share

1.16

Certain Operating Costs per Boe

FY 2024 Total Cash Operating Costs (GAAP) and Total DD&A per Boe

20.76

Less: FY 2025 Total Cash Operating Costs (GAAP) and Total DD&A per Boe

(20.20)

Subtotal

0.56

Multiplied by: FY 2025 Crude Oil Equivalent Volumes (MMBoe)

449.8

Change in Before-Tax Net Income

252

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

(55)

Change in Net Income

197

Change in Diluted Earnings per Share

0.36

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

FY 2025 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts

13

Less: Income Tax Benefit (Provision)

(3)

After Tax - (a)

10

Less: FY 2024 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts

204

Less: Income Tax Benefit (Provision)

(44)

After Tax - (b)

160

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

(150)

Change in Diluted Earnings per Share

(0.27)

Other (1)

0.44

FY 2025 Net Income per Share (GAAP) - Diluted

9.12

FY 2025 Average Number of Common Shares - Diluted

546

(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)

3Q 2025 Adjusted Net Income per Share (Non-GAAP) - Diluted

2.71

Realized Prices

4Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe

34.99

Less: 3Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe

(38.05)

Subtotal

(3.06)

Multiplied by: 4Q 2025 Crude Oil Equivalent Volumes (MMBoe)

128.7

Total Change in Revenue

(394)

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

87

Change in Net Income

(307)

Change in Diluted Earnings per Share

(0.57)

Volumes

4Q 2025 Crude Oil Equivalent Volumes (MMBoe)

128.7

Less: 3Q 2025 Crude Oil Equivalent Volumes (MMBoe)

(119.7)

Subtotal

9.0

Multiplied by: 4Q 2025 Composite Average Margin per Boe (Non-GAAP) (Including Total Exploration Costs) (refer to

"Revenues, Costs and Margins Per Barrel of Oil Equivalent" schedule below)

11.78

Change in Margin

106

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

(23)

Change in Net Income

83

Change in Diluted Earnings per Share

0.15

Certain Operating Costs per Boe

3Q 2025 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe

19.70

Less: 4Q 2025 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe

(19.75)

Subtotal

(0.05)

Multiplied by: 4Q 2025 Crude Oil Equivalent Volumes (MMBoe)

128.7

Change in Before-Tax Net Income

(6)

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

1

Change in Net Income

(5)

Change in Diluted Earnings per Share

(0.01)

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

4Q 2025 Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts

(21)

Less: Income Tax Benefit (Provision)

4

After Tax - (a)

(17)

Less: 3Q 2025 Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts

27

Less: Income Tax Benefit (Provision)

(5)

After Tax - (b)

22

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

(39)

Change in Diluted Earnings per Share

(0.07)

Other (1)

0.06

4Q 2025 Adjusted Net Income per Share (Non-GAAP)

2.27

4Q 2025 Average Number of Common Shares - Diluted

539

(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.

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)

FY 2024 Adjusted Net Income per Share (Non-GAAP) - Diluted

11.62

Realized Prices

FY 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe

39.28

Less: FY 2024 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and Natural Gas per Boe

(45.22)

Subtotal

(5.94)

Multiplied by: FY 2025 Crude Oil Equivalent Volumes (MMBoe)

449.8

Total Change in Revenue

(2,672)

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

588

Change in Net Income

(2,084)

Change in Diluted Earnings per Share

(3.82)

Volumes

FY 2025 Crude Oil Equivalent Volumes (MMBoe)

449.8

Less: FY 2024 Crude Oil Equivalent Volumes (MMBoe)

(388.7)

Subtotal

61.1

Multiplied by: FY 2025 Composite Average Margin per Boe (Non-GAAP) (Including Total Exploration Costs) (refer to

"Revenues, Costs and Margins Per Barrel of Oil Equivalent" schedule below)

14.97

Change in Margin

915

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

(201)

Change in Net Income

714

Change in Diluted Earnings per Share

1.31

Certain Operating Costs per Boe

FY 2024 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe

20.74

Less: FY 2025 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe

(20.01)

Subtotal

0.73

Multiplied by: FY 2025 Crude Oil Equivalent Volumes (MMBoe)

449.8

Change in Before-Tax Net Income

328

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

(72)

Change in Net Income

256

Change in Diluted Earnings per Share

0.47

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

FY 2025 Net Cash Received from (Payments for) Settlement of Financial Commodity Derivative Contracts

(56)

Less: Income Tax Benefit (Provision)

12

After Tax - (a)

(44)

FY 2024 Net Cash Received from (Payments for) Settlement of Financial Commodity Derivative Contracts

214

Less: Income Tax Benefit (Provision)

(46)

After Tax - (b)

168

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

(212)

Change in Diluted Earnings per Share

(0.39)

Other (1)

0.97

FY 2025 Adjusted Net Income per Share (Non-GAAP)

10.16

FY 2025 Average Number of Common Shares - Diluted

546

(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.

2024

2025

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)

2,903

2,889

3,588

2,763

12,143

2,289

2,032

3,111

2,612

10,044

Adjustments:

Changes in Components of Working Capital and Other

Assets and Liabilities

Accounts Receivable

(58)

(33)

(109)

99

(101)

(48)

(122)

(133)

3

(300)

Inventories

(117)

(75)

(30)

(37)

(259)

(76)

45

(4)

84

49

Accounts Payable

58

(29)

159

(152)

36

129

107

(5)

40

271

Accrued Taxes Payable

(319)

185

(256)

(151)

(541)

339

321

(28)

103

735

Other Assets

161

(42)

(197)

34

(44)

43

43

28

(97)

17

Other Liabilities

71

20

(108)

(6)

(23)

96

52

(155)

(10)

(17)

Changes in Components of Working Capital

Associated with Investing Activities

229

127

(59)

85

382

41

8

159

(123)

85

Add:

Acquisition-Related Costs (1), Net of Tax

—

—

—

—

—

—

10

58

5

73

Adjusted Cash Flow from Operations (Non-GAAP)

2,928

3,042

2,988

2,635

11,593

2,813

2,496

3,031

2,617

10,957

Less:

Total Capital Expenditures (Non-GAAP) (2)

(1,703)

(1,668)

(1,497)

(1,358)

(6,226)

(1,484)

(1,523)

(1,648)

(1,639)

(6,294)

Free Cash Flow (Non-GAAP)

1,225

1,374

1,491

1,277

5,367

1,329

973

1,383

978

4,663

(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):

2024

2025

1st Qtr

2nd Qtr

3rd Qtr

4th Qtr

Year

1st Qtr

2nd Qtr

3rd Qtr

4th Qtr

Year

Total Expenditures (GAAP)

1,952

1,682

1,573

1,446

6,653

1,546

1,883

8,544

1,730

13,703

Less:

Asset Retirement Costs

(21)

60

(11)

(26)

2

(13)

(14)

(86)

(33)

(146)

Non-Cash Leasehold Acquisition Costs (3)

(31)

(34)

(17)

(3)

(85)

(9)

(2)

(3)

(10)

(24)

Acquisition Costs of Properties (3)

(21)

(5)

—

(7)

(33)

1

(270)

(6,736)

2

(7,003)

Acquisition Costs of Other Property, Plant and Equipment

(131)

(1)

(5)

—

(137)

—

—

—

—

—

Exploration Costs

(45)

(34)

(43)

(52)

(174)

(41)

(74)

(71)

(50)

(236)

Total Capital Expenditures (Non-GAAP)

1,703

1,668

1,497

1,358

6,226

1,484

1,523

1,648

1,639

6,294

Cash Flow from Operations and Free Cash Flow

(Continued)

In millions of USD (Unaudited)

FY 2023

FY 2022

FY 2021

Net Cash Provided by Operating Activities (GAAP)

11,340

11,093

8,791

Adjustments:

Changes in Components of Working Capital and Other Assets and Liabilities

Accounts Receivable

38

347

821

Inventories

231

534

13

Accounts Payable

119

(90)

(456)

Accrued Taxes Payable

(61)

113

(312)

Other Assets

(39)

364

136

Other Liabilities

(184)

266

116

Changes in Components of Working Capital Associated with Investing Activities

(295)

(375)

200

Adjusted Cash Flow from Operations (Non-GAAP)

11,149

12,252

9,309

Less:

Total Capital Expenditures (Non-GAAP) (a)

(6,041)

(4,607)

(3,755)

Free Cash Flow (Non-GAAP)

5,108

7,645

5,554

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

Total Expenditures (GAAP)

6,818

5,610

4,255

Less:

Asset Retirement Costs

(257)

(298)

(127)

Non-Cash Development Drilling

(90)

—

—

Non-Cash Leasehold Acquisition Costs (3)

(99)

(127)

(45)

Non-Cash Finance Leases

—

—

(74)

Acquisition Costs of Properties (3)

(16)

(419)

(100)

Acquisition Costs of Other Property, Plant and Equipment

(134)

—

—

Exploration Costs

(181)

(159)

(154)

Total Capital Expenditures (Non-GAAP)

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.

December 31,

2025

September 30,

2025

June 30,

2025

March 31,

2025

December 31,

2024

Total Stockholders' Equity - (a)

29,833

30,285

29,238

29,516

29,351

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

7,936

7,694

4,236

4,744

4,752

Less: Cash

(3,396)

(3,530)

(5,216)

(6,599)

(7,092)

Net Debt (Non-GAAP) - (c)

4,540

4,164

(980)

(1,855)

(2,340)

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

37,769

37,979

33,474

34,260

34,103

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

34,373

34,449

28,258

27,661

27,011

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

21.0 %

20.3 %

12.7 %

13.8 %

13.9 %

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

(c)]

13.2 %

12.1 %

-3.5 %

-6.7 %

-8.7 %

Proved Reserves and Reserve Replacement Data

(Unaudited)

2025 Net Proved Reserves Reconciliation Summary

United

States

Trinidad

Other

International

Total

Crude Oil and Condensate (MMBbl)

Beginning Reserves

1,868

2

—

1,870

Revisions

(10)

—

—

(10)

Purchases in Place

158

—

—

158

Extensions, Discoveries and Other Additions

77

1

—

78

Sales in Place

—

—

—

—

Production

(190)

(1)

—

(191)

Ending Reserves

1,903

2

—

1,905

Natural Gas Liquids (MMBbl)

Beginning Reserves

1,358

—

—

1,358

Revisions

9

—

—

9

Purchases in Place

200

—

—

200

Extensions, Discoveries and Other Additions

48

—

—

48

Sales in Place

—

—

—

—

Production

(105)

—

—

(105)

Ending Reserves

1,510

—

—

1,510

Natural Gas (Bcf)

Beginning Reserves

8,878

244

—

9,122

Revisions

798

9

—

807

Purchases in Place

2,340

—

—

2,340

Extensions, Discoveries and Other Additions

1,184

77

—

1,261

Sales in Place

(1)

—

—

(1)

Production

(851)

(86)

—

(937)

Ending Reserves

12,348

244

—

12,592

Oil Equivalents (MMBoe)

Beginning Reserves

4,706

42

—

4,748

Revisions

131

2

—

133

Purchases in Place

749

—

—

749

Extensions, Discoveries and Other Additions

322

14

—

336

Sales in Place

—

—

—

—

Production

(437)

(15)

—

(452)

Ending Reserves

5,471

43

—

5,514

Net Proved Developed Reserves (MMBoe)

At December 31, 2024

2,542

24

—

2,566

At December 31, 2025

3,317

29

—

3,346

2025 Exploration and Development Expenditures ($ Millions)

Acquisition Cost of Unproved Properties

195

2

—

197

Exploration Costs

349

79

85

513

Development Costs

5,213

147

5

5,365

Total Drilling

5,757

228

90

6,075

Acquisition Cost of Proved Properties

6,977

—

26

7,003

Asset Retirement Costs

98

35

13

146

Total Exploration and Development Expenditures

12,832

263

129

13,224

Gathering, Processing and Other

470

5

4

479

Total Expenditures

13,302

268

133

13,703

Proceeds from Sales in Place

(24)

—

—

(24)

Net Expenditures

13,278

268

133

13,679

Reserve Replacement Costs ($ / Boe) *

All-in Total, Net of Revisions (GAAP)

10.68

16.44

—

10.86

All-in Total, Net of Revisions (Non-GAAP)

12.29

12.25

—

12.44

All-in Total, Excluding Revisions Due to Price (GAAP)

11.32

16.44

—

11.50

All-in Total, Excluding Revisions Due to Price (Non-GAAP)

14.45

12.25

—

14.54

Reserve Replacement *

All-in Total, Net of Revisions and Dispositions

275 %

107 %

0 %

269 %

All-in Total, Net of Revisions and Dispositions (Adjusted)

104 %

107 %

0 %

104 %

All-in Total, Excluding Revisions Due to Price

259 %

107 %

0 %

254 %

All-in Total, Excluding Revisions Due to Price (Adjusted)

88 %

107 %

0 %

89 %

* See following reconciliation schedule for calculation methodology

Reserve Replacement Cost Data

(Unaudited; in millions, except ratio data)

For the Twelve Months Ended December 31, 2025

United

States

Trinidad

Other

International

Total

Total Costs Incurred in Exploration and Development Activities (GAAP)

12,832

263

129

13,224

Less: Asset Retirement Costs

(98)

(35)

(13)

(146)

Non-Cash Acquisition Costs of Unproved Properties

(24)

—

—

(24)

Total Acquisition Costs of Proved Properties

(6,977)

—

(26)

(7,003)

Exploration Expenses

(160)

(32)

(44)

(236)

Total Exploration and Development Expenditures for Drilling Only (Non-GAAP)

5,573

196

46

5,815

Total Costs Incurred in Exploration and Development Activities (GAAP) - (a)

12,832

263

129

13,224

Less: Asset Retirement Costs

(98)

(35)

(13)

(146)

Non-Cash Acquisition Costs of Unproved Properties

(24)

—

—

(24)

Non-Cash Acquisition Costs of Proved Properties

—

—

—

—

Certain Acquisition Costs of Proved Properties 1

(6,972)

—

—

(6,972)

Exploration Expenses

(160)

(32)

(44)

(236)

Total Exploration and Development Expenditures (Non-GAAP) - (b)

5,578

196

72

5,846

Total Expenditures (GAAP)

13,302

268

133

13,703

Less: Asset Retirement Costs

(98)

(35)

(13)

(146)

Non-Cash Acquisition Costs of Unproved Properties

(24)

—

—

(24)

Non-Cash Acquisition Costs of Proved Properties

—

—

—

—

Exploration Expenses

(160)

(32)

(44)

(236)

Total Cash Expenditures (Non-GAAP)

13,020

201

76

13,297

Net Proved Reserve Additions From All Sources - Oil Equivalents (MMBoe)

Revisions Due to Price - (c)

68

—

—

68

Revisions Other Than Price

63

2

—

65

Purchases in Place

749

—

—

749

Extensions, Discoveries and Other Additions - (d)

322

14

—

336

Total Proved Reserve Additions - (e)

1,202

16

—

1,218

Less: Acquisition Related Purchases 2

(748)

—

—

(748)

Adjusted Total Proved Reserve Additions - (f)

454

16

—

470

Sales in Place

—

—

—

—

Net Proved Reserve Additions From All Sources - (g)

1,202

16

—

1,218

Adjusted Net Proved Reserve Additions From All Sources - (h)

454

16

—

470

Production - (i)

437

15

—

452

Reserve Replacement Costs ($ / Boe)

All-in Total, Net of Revisions (GAAP) - (a / e)

10.68

16.44

—

10.86

All-in Total, Net of Revisions (Non-GAAP) - (b / f)

12.29

12.25

—

12.44

All-in Total, Excluding Revisions Due to Price (GAAP) - (a / (e - c))

11.32

16.44

—

11.50

All-in Total, Excluding Revisions Due to Price (Non-GAAP) - (b / (f - c))

14.45

12.25

—

14.54

Reserve Replacement

All-in Total, Net of Revisions and Dispositions - (g / i)

275 %

107 %

0 %

269 %

All-in Total, Net of Revisions and Dispositions (Adjusted) - (h / i)

104 %

107 %

0 %

104 %

All-in Total, Excluding Revisions Due to Price - ((g - c) / i)

259 %

107 %

0 %

254 %

All-in Total, Excluding Revisions Due to Price (Adjusted) - ((h - c) / i)

88 %

107 %

0 %

89 %

(1)

Includes $6,703 million for the Encino acquisition and $269 million of proved properties adjacent to EOG's core acreage in the Eagle Ford play.

(2)

Includes 678 MMBoe related to the Encino acquisition and 70 MMBoe related to the acquisition of proved properties adjacent to EOG's core acreage in the Eagle ford play.

Reserve Replacement Cost Data

(Continued)

(Unaudited; in millions, except ratio data)

For the Twelve Months Ended December 31, 2025

Proved Developed Reserve Replacement Costs ($ / Boe)

Total

Total Costs Incurred in Exploration and Development Activities (GAAP) - (k)

13,224

Less: Asset Retirement Costs

(146)

Acquisition Costs of Unproved Properties

(197)

Acquisition Costs of Proved Properties

(7,003)

Exploration Expenses

(236)

Drillbit Exploration and Development Expenditures (Non-GAAP) - (l)

5,642

Total Proved Reserves - Extensions, Discoveries and Other Additions (MMBoe)

336

Add: Conversion of Proved Undeveloped Reserves to Proved Developed

503

Less: Proved Undeveloped Extensions and Discoveries

(264)

Proved Developed Reserves - Extensions and Discoveries (MMBoe)

575

Total Proved Reserves - Revisions (MMBoe)

133

Less: Proved Undeveloped Reserves - Revisions

(21)

Proved Developed - Revisions Due to Price

(19)

Proved Developed Reserves - Revisions Other Than Price (MMBoe)

93

Proved Developed Reserves - Extensions and Discoveries Plus Revisions Other Than Price (MMBoe) - (m)

668

Proved Developed Reserves - Acquisitions (MMBoe) (n)

545

Proved Developed Reserves - Extensions and Discoveries plus Revisions Other Than Price plus Acquisitions (MMBoe) (o)

1,213

Proved Developed Reserve Replacement Costs Excluding Revisions Due to Price ($ / Boe) (GAAP) - (k / o)

10.90

Proved Developed Reserve Replacement Costs Excluding Revisions Due to Price ($ / Boe) (Non-GAAP) - (l / m)

8.45

Reserve Replacement Cost Data

(Continued)

In 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.

2025

2024

2023

2022

2021

Total Costs Incurred in Exploration and Development Activities (GAAP)

13,224

5,634

6,018

5,229

3,969

Less: Asset Retirement Costs

(146)

2

(257)

(298)

(127)

Non-Cash Acquisition Costs of Unproved Properties

(24)

(85)

(99)

(127)

(45)

Total Acquisition Costs of Proved Properties

(7,003)

(33)

(16)

(419)

(100)

Non-Cash Development Drilling

—

—

(90)

—

—

Exploration Expenses

(236)

(174)

(181)

(159)

(154)

Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) - (a)

5,815

5,344

5,375

4,226

3,543

Total Costs Incurred in Exploration and Development Activities (GAAP) - (b)

13,224

5,634

6,018

5,229

3,969

Less: Asset Retirement Costs

(146)

2

(257)

(298)

(127)

Non-Cash Acquisition Costs of Unproved Properties

(24)

(85)

(99)

(127)

(45)

Non-Cash Acquisition Costs of Proved Properties

—

(24)

(6)

(26)

(5)

Non-Cash Development Drilling

—

—

(90)

—

—

Certain Acquisition Costs of Proved Properties 1

(6,972)

—

—

—

—

Exploration Expenses

(236)

(174)

(181)

(159)

(154)

Total Exploration and Development Expenditures (Non-GAAP) - (c)

5,846

5,353

5,385

4,619

3,638

Net Proved Reserve Additions From All Sources - Oil Equivalents (MMBoe)

Revisions Due to Price - (d)

68

(146)

(110)

11

194

Revisions Other Than Price

65

215

139

325

(308)

Purchases in Place

749

6

2

16

9

Extensions, Discoveries and Other Additions - (e)

336

580

607

560

952

Total Proved Reserve Additions (GAAP) - (f)

1,218

655

638

912

847

Less: Acquisition Related Purchases 2

(748)

—

—

—

—

Total Proved Reserve Additions (Non-GAAP) - (g)

470

655

638

912

847

Sales in Place

—

(14)

(17)

(88)

(11)

Net Proved Reserve Additions From All Sources (GAAP)

1,218

641

621

824

836

Production

452

391

361

333

309

Reserve Replacement Costs ($ / Boe)

All-in Total, Net of Revisions (GAAP) - (b / f)

10.86

8.60

9.43

5.73

4.69

All-in Total, Net of Revisions (Non-GAAP) - (c / g)

12.44

8.17

8.44

5.06

4.30

All-in Total, Excluding Revisions Due to Price (GAAP) - (b / ( f - d))

11.50

7.03

8.05

5.80

6.08

All-in Total, Excluding Revisions Due to Price (Non-GAAP) - (c / ( g - d))

14.54

6.68

7.20

5.13

5.57

(1)

Includes $6,703 million for the Encino acquisition and $269 million of proved properties adjacent to EOG's core acreage in the Eagle Ford play.

(2)

Includes 678 MMBoe related to the Encino acquisition and 70 MMBoe related to the acquisition of proved properties adjacent to EOG's core acreage in the Eagle ford play.

Definitions

$/Boe

U.S. Dollars per barrel of oil equivalent

MMBoe

Million barrels of oil equivalent

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.

4Q 2025

3Q 2025

2Q 2025

1Q 2025

4Q 2024

Volume - Million Barrels of Oil Equivalent - (a)

128.7

119.7

103.2

98.1

100.8

Total Operating Revenues and Other - (b)

5,638

5,847

5,478

5,669

5,585

Total Operating Expenses - (c)

4,695

4,011

3,731

3,810

3,993

Operating Income - (d)

943

1,836

1,747

1,859

1,592

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

Crude Oil and Condensate

2,991

3,243

2,974

3,293

3,261

Natural Gas Liquids

666

604

534

572

554

Natural Gas

847

707

600

637

494

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

4,504

4,554

4,108

4,502

4,309

Operating Costs

Lease and Well

447

431

396

401

394

Gathering, Processing and Transportation Costs (1)

652

587

455

440

441

General and Administrative (GAAP)

224

239

186

171

189

Less: Certain Items (see Endnotes 2 & 3 to 4Q 2025 earnings release)

(8)

(68)

(12)

—

—

General and Administrative (Non-GAAP) (2)

216

171

174

171

189

Taxes Other Than Income (GAAP)

283

309

301

341

291

Add: Severance Tax Refund

—

—

—

—

—

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

283

309

301

341

291

Interest Expense, Net

66

71

51

47

38

Less: Acquisition-Related Financing Commitment Costs

—

—

(6)

—

—

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

66

71

45

47

38

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

1,672

1,637

1,389

1,400

1,353

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

1,664

1,569

1,371

1,400

1,353

Depreciation, Depletion and Amortization (DD&A)

1,226

1,169

1,053

1,013

1,019

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

2,898

2,806

2,442

2,413

2,372

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

2,890

2,738

2,424

2,413

2,372

Exploration Costs

50

71

74

41

52

Dry Hole Costs

4

—

11

34

8

Impairments

689

71

39

44

276

Total Exploration Costs (GAAP)

743

142

124

119

336

Less: Certain Impairments (5)

(646)

—

(11)

—

(254)

Total Exploration Costs (Non-GAAP)

97

142

113

119

82

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

3,641

2,948

2,566

2,532

2,708

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

2,987

2,880

2,537

2,532

2,454

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

Gas less Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP))

863

1,606

1,542

1,970

1,601

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))

1,517

1,674

1,571

1,970

1,855

Revenues, Costs and Margins Per Barrel of Oil Equivalent

(Continued)

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

4Q 2025

3Q 2025

2Q 2025

1Q 2025

4Q 2024

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

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

43.81

48.85

53.08

57.79

55.41

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

36.48

33.51

36.15

38.84

39.62

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

7.33

15.34

16.93

18.95

15.79

Composite Average Revenue from Sales of Crude Oil and Condensate,

NGLs, and Natural Gas per Boe - (e) / (a)

34.99

38.05

39.80

45.88

42.74

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

12.99

13.67

13.46

14.26

13.42

Composite Average Margin per Boe (excluding DD&A and Total Exploration

Costs) - [(e) / (a) - (f) / (a)]

22.00

24.38

26.34

31.62

29.32

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

22.52

23.44

23.66

24.58

23.53

Composite Average Margin per Boe (excluding Total Exploration Costs)

- [(e) / (a) - (h) / (a)]

12.47

14.61

16.14

21.30

19.21

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

28.29

24.63

24.86

25.79

26.86

Composite Average Margin per Boe (including Total Exploration

Costs) - [(e) / (a) - (j) / (a)]

6.70

13.42

14.94

20.09

15.88

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

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

12.93

13.10

13.30

14.26

13.42

Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) -

[(e) / (a) - (g) / (a)]

22.06

24.95

26.50

31.62

29.32

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

22.46

22.87

23.50

24.58

23.53

Composite Average Margin per Boe (excluding Total Exploration Costs) -

[(e) / (a) - (i) / (a)]

12.53

15.18

16.30

21.30

19.21

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

23.21

24.06

24.59

25.79

24.34

Composite Average Margin per Boe (including Total Exploration Costs) -

[(e) / (a) - (k) / (a)]

11.78

13.99

15.21

20.09

18.40

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 International 1

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 1

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) WTI 2 ($/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 1

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 Hub 3 ($/Mcf)

United States

(0.49)

(0.28)

(0.04)

0.63

1.03

Natural Gas Realizations 4 ($/Mcf)

Trinidad

3.78

3.65

3.65

4.43

3.40

Other International 1

3.28

—

—

—

—

Total Expenditures (GAAP) ($MM)

13,703

6,653

6,818

5,610

4,255

Capital Expenditures 5 (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 Costs 6

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

1)

Production volumes from Bahrain operations; realized price represents contract price less Bapco's processing and distribution costs.

2)

EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month.

3)

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.

4)

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.

5)

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

6)

Effective January 1, 2024, EOG combined Transportation Costs and Gathering and Processing Costs into one line item titled Gathering, Processing and Transportation Costs. This presentation has been conformed for all periods presented and had no impact on previously reported Net Income.

7)

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.

8)

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.

9)

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).

SOURCE EOG Resources, Inc.