EOG Resources Reports Third Quarter 2025 Results – Energy News, Top Headlines, Commentaries, Features & Events

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

Key Financial Results 

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

GAAP
 3Q 2025

2Q 2025

1Q 2025

4Q 2024

3Q 2024

Total Revenue
5,847

5,478

5,669

5,585

5,965

Net Income
1,471

1,345

1,463

1,251

1,673

Net Income Per Share
2.70

2.46

2.65

2.23

2.95

Net Cash Provided by Operating Activities
3,111

2,032

2,289

2,763

3,588

Total Expenditures
8,544

1,883

1,546

1,446

1,573

Current and Long–Term Debt
7,694

4,236

4,744

4,752

3,776

Cash and Cash Equivalents
3,530

5,216

6,599

7,092

6,122

Debt–to–Total Capitalization
20.3 %

12.7 %

13.8 %

13.9 %

11.3 %

Cash Operating Costs ($/Boe)
10.50

10.05

10.31

10.15

10.15

Non–GAAP

Adjusted Net Income
1,472

1,268

1,586

1,535

1,644

Adjusted Net Income Per Share
2.71

2.32

2.87

2.74

2.89

Adjusted CFO1
3,031

2,496

2,813

2,635

2,988

Capital Expenditures
1,648

1,523

1,484

1,358

1,497

Free Cash Flow
1,383

973

1,329

1,277

1,491

Net Debt
4,164

(980)

(1,855)

(2,340)

(2,346)

Net Debt–to–Total Capitalization
12.1 %

(3.5 %)

(6.7 %)

(8.7 %)

(8.6 %)

Cash Operating Costs ($/Boe) 2,3
9.93

9.94

10.31

10.15

10.05

Third Quarter Highlights

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

Third Quarter 2025 Highlights and Cash Return

Volumes and Capital Expenditures

Volumes
3Q 2025

3Q 2025
Guidance
Midpoint

 2Q 2025

 1Q 2025

 4Q 2024

 3Q 2024

Crude Oil and Condensate (MBod)
534.5

532.4

504.2

502.1

494.6

493.0

Natural Gas Liquids (MBbld)
309.3

305.0

258.4

241.7

252.5

254.3

Natural Gas (MMcfd)
2,745

2,735

2,229

2,080

2,092

1,970

Total Crude Oil Equivalent (MBoed)
1,301.2

1,293.3

1,134.1

1,090.4

1,095.7

1,075.7

Capital Expenditures ($MM)
1,648

1,650

1,523

1,484

1,358

1,497

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

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

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

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

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

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

Third Quarter 2025 Financial Performance

Prices

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

Volumes

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

Per–Unit Costs

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

Hedges

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

Free Cash Flow

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

Cash Return and Working Capital

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

Third Quarter 2025 Operating Performance

Lease and Well

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

General and Administrative (Non–GAAP)

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

Gathering, Processing and Transportation Costs

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

Depreciation, Depletion and Amortization

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

Third Quarter 2025 Results vs Guidance

(Unaudited)

See “Endnotes” below for related discussion and definitions.

     3Q 2025

3Q 2025

Guidance 

Midpoint6

Variance

2Q 2025

1Q 2025

4Q 2024

3Q 2024

Crude Oil and Condensate Volumes (MBod)

United States
532.9

531.0

1.9

503.1

500.9

493.5

491.8

Trinidad
1.6

1.4

0.2

1.1

1.2

1.1

1.2

Total
534.5

532.4

2.1

504.2

502.1

494.6

493.0

Natural Gas Liquids Volumes (MBbld)

Total
309.3

305.0

4.3

258.4

241.7

252.5

254.3

Natural Gas Volumes (MMcfd)

United States
2,511

2,525

(14)

1,977

1,834

1,840

1,745

Trinidad
230

210

20

252

246

252

225

Other International7
4

0

4

0

0

0

0

Total
2,745

2,735

10

2,229

2,080

2,092

1,970

Total Crude Oil Equivalent Volumes (MBoed)
1,301.2

1,293.3

7.9

1,134.1

1,090.4

1,095.7

1,075.7

Total MMBoe
119.7

119.0

0.7

103.2

98.1

100.8

99.0

Benchmark Price

Oil (WTI) ($/Bbl)
64.95

63.71

71.42

70.28

75.16

Natural Gas (HH) ($/Mcf)
3.07

3.44

3.66

2.79

2.16

Crude Oil and Condensate – above (below) WTI8 ($/Bbl)

United States
1.02

0.80

0.22

1.13

1.48

1.40

1.79

Trinidad
(7.21)

(5.00)

(2.21)

(9.21)

(10.30)

(9.81)

(12.01)

Natural Gas Liquids – Realizations as % of WTI

Total
32.7 %

34.0 %

(1.3 %)

35.6 %

36.8 %

33.9 %

29.8 %

Natural Gas – above (below) NYMEX Henry Hub9 ($/Mcf)

United States
(0.36)

(0.40)

0.04

(0.57)

(0.30)

(0.40)

(0.32)

Natural Gas Realizations ($/Mcf)

Trinidad
3.80

3.60

0.20

3.65

3.78

3.86

3.68

Other International7
3.27

0.00

3.27

0.00

0.00

0.00

0.00

Total Expenditures (GAAP) ($MM)
8,544

1,883

1,546

1,446

1,573

Capital Expenditures (non–GAAP) ($MM)
1,648

1,650

(2)

1,523

1,484

1,358

1,497

Operating Unit Costs ($/Boe)

Lease and Well
3.60

3.70

(0.10)

3.84

4.09

3.91

3.96

Gathering, Processing and Transportation Costs5
4.90

5.10

(0.20)

4.41

4.48

4.37

4.50

General and Administrative (GAAP)
2.00

1.50

0.50

1.80

1.74

1.87

1.69

General and Administrative (non–GAAP)2,3
1.43

1.50

(0.07)

1.69

1.74

1.87

1.59

Cash Operating Costs (GAAP)
10.50

10.30

0.20

10.05

10.31

10.15

10.15

Cash Operating Costs (non–GAAP)2,3
9.93

10.30

(0.37)

9.94

10.31

10.15

10.05

Depreciation, Depletion and Amortization
9.77

9.85

(0.08)

10.20

10.32

10.11

10.42

Expenses ($MM)

Exploration and Dry Hole
71

75

(4)

85

75

60

43

Impairment (GAAP)
71

39

44

276

15

Impairment (excluding certain impairments (non–GAAP))10
71

70

1

28

44

23

15

Capitalized Interest
27

21

6

11

12

13

12

Net Interest (GAAP)
71

83

(12)

51

47

38

31

Net Interest (non–GAAP)11
71

83

(12)

45

47

38

31

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

(GAAP)
6.8 %

7.5 %

(0.7 %)

7.3 %

7.6 %

6.8 %

6.5 %

(non–GAAP)3
6.8 %

7.5 %

(0.7 %)

7.3 %

7.6 %

6.8 %

7.2 %

Income Taxes

Effective Rate
19.4 %

20.5 %

(1.1 %)

23.2 %

22.1 %

23.0 %

21.6 %

Current Tax Expense ($MM)
75

180

(105)

301

370

454

240

Fourth Quarter and Full‐Year 2025 Guidance12

(Unaudited)

See “Endnotes” below for related discussion and definitions
.
4Q 2025
Guidance Range

4Q 2025
Midpoint

FY 2025
Guidance Range

FY 2025
Midpoint

Crude Oil and Condensate Volumes (MBod)

United States
541.4
–
546.0

543.7

518.7
–
521.9

520.3

Trinidad
1.1
–
1.5

1.3

1.1
–
1.5

1.3

Total
542.5
–
547.5

545.0

519.8
–
523.4

521.6

Natural Gas Liquids Volumes (MBbld)

Total
315.5
–
330.5

323.0

280.0
–
286.0

283.0

 Natural Gas Volumes (MMcfd)

United States
2,740
–
2,840

2,790

2,250
–
2,310

2,280

Trinidad
190
–
210

200

220
–
240

230

Total
2,930
–
3,050

2,990

2,470
–
2,550

2,510

Crude Oil Equivalent Volumes (MBoed)

United States
1,313.6
–
1,349.8

1,331.7

1,173.7
–
1,192.9

1,183.3

Trinidad
32.8
–
36.5

34.7

37.8
–
41.5

39.7

Total
1,346.4
–
1,386.3

1,366.4

1,211.5
–
1,234.4

1,223.0

Crude Oil and Condensate – above (below) WTI8 ($/Bbl)

United States
(0.50)
–
1.00

0.25

0.35
–
1.35

0.85

Trinidad
(5.25)
–
(2.75)

(4.00)

(8.40)
–
(6.90)

(7.65)

Natural Gas Liquids – Realizations as % of WTI

Total
28.0 %
–
38.0 %

33.0 %

31.5 %
–
36.5 %

34.0 %

Natural Gas – above (below) NYMEX Henry Hub9 ($/Mcf)

United States
(0.80)
–
(0.10)

(0.45)

(0.95)
–
0.05

(0.45)

Natural Gas Realizations ($/Mcf)

Trinidad
3.00
–
4.20

3.60

3.40
–
3.90

3.65

Capital Expenditures13 ($MM)
1,600
–
1,700

1,650

6,200
–
6,400

6,300

Operating Unit Costs ($/Boe)

Lease and Well
3.50
–
4.00

3.75

3.70
–
3.90

3.80

Gathering, Processing and Transportation Costs5
4.75
–
5.25

5.00

4.65
–
4.85

4.75

General and Administrative
1.40
–
1.70

1.55

1.45
–
1.65

1.55

Cash Operating Costs
9.65
–
10.95

10.30

9.80
–
10.40

10.10

Depreciation, Depletion and Amortization
9.25
–
10.25

9.75

9.70
–
10.30

10.00

Expenses ($MM)

Exploration and Dry Hole
40
–
80

60

270
–
310

290

Impairment (excluding certain impairments)10
30
–
110

70

180
–
260

220

Capitalized Interest
34
–
38

36

85
–
89

87

Net Interest
64
–
68

66

228
–
232

230

TOTI (% of revenues from sales of crude oil and

condensate, NGLs and natural gas)
6.0 %
–
8.0 %

7.0 %

6.5 %
–
8.5 %

7.5 %

Income Taxes

Effective Rate
20.0 %
–
25.0 %

22.5 %

19.0 %
–
24.0 %

21.5 %

Current Tax Expense ($MM)
220
–
320

270

970
–
1,070

1,020

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

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

Investor Contacts
Pearce Hammond 713–571–4684
Neel Panchal 713–571–4884
Shelby O’Connor 713–571–4560

Media Contact
Kimberly Ehmer 713–571–4676

Endnotes

1)
Cash flow from operations before changes in working capital and certain acquisition–related costs.

2)
Cash Operating Costs consist of LOE, GP&T and G&A. Excludes Encino acquisition–related G&A costs of $68 million for 3Q 2025 and $12 million for 2Q 2025, as reflected in the accompanying reconciliation schedules (see “Revenues, Costs and Margins Per Barrel of Oil Equivalent”). The per–Boe impact of such Encino acquisition–related costs on G&A and total Cash Operating Costs for 3Q 2025 was ($0.57) and for 2Q 2025 was ($0.11) as set forth in “Third Quarter 2025 Results vs Guidance” above. G&A per Boe (GAAP) for 3Q 2025 was $2.00 and for 2Q 2025 was $1.80.

3)
Cash Operating Costs consist of LOE, GP&T and G&A. TOTI (% of revenues from sales of crude oil and condensate, NGLs and natural gas) (non–GAAP) and G&A (non–GAAP) for 3Q 2024 exclude a state severance tax refund and related consulting fees, as reflected in the accompanying reconciliation schedules (see “Revenues, Costs and Margins Per Barrel of Oil Equivalent”). The per–Boe impact of such consulting fees on G&A and total Cash Operating Costs for 3Q 2024 was $(0.10) as set forth in “Third Quarter 2025 Results vs Guidance” above.

4)
Includes gathering, processing and marketing revenue, gains (losses) on asset dispositions (for GAAP earnings per share only), other revenue, exploration costs, dry hole costs, impairments, marketing costs, taxes other than income, other income (expense), interest expense, the impact of changes in the effective income tax rate and the impact of share repurchases on diluted shares.

5)
Effective January 1, 2024, EOG combined Transportation Costs and Gathering and Processing Costs into one line–item titled Gathering, Processing and Transportation Costs. This presentation has been conformed for all periods presented and had no impact on previously reported Net Income.

6)
GAAP and non–GAAP distinctions apply solely to actual results and do not pertain to EOG’s third quarter 2025 guidance midpoint disclosures.

7)
Other International represents EOG’s Kingdom of Bahrain operations. Realized price represents contract price less Bapco’s processing and distribution costs.

8)
EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month.

9)
EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the NYMEX Last Day Settle price for each of the applicable months.

10)
In general, EOG excludes impairments which are (i) attributable to declines in commodity prices, (ii) related to sales of certain oil and gas properties or (iii) the result of certain other events or decisions (e.g., a periodic review of EOG’s oil and gas properties or other assets). EOG believes excluding these impairments from total impairment costs is appropriate and provides useful information to investors, as such impairments were caused by factors outside of EOG’s control (versus, for example, impairments that are due to EOG’s proved oil and gas properties not being as productive as it originally estimated).

11)
Net interest expense (non–GAAP) excludes Encino acquisition–related financing commitment costs of $6 million in 2Q 2025.

12)
The forecast items for the fourth quarter and full year 2025 set forth above for EOG are based on currently available information and expectations as of the date of this press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with this press release and EOG’s related Current Report on Form 8–K filing, replaces and supersedes any previously issued guidance or forecast.

13)
The forecast includes expenditures for Exploration and Development Drilling, Facilities, Leasehold Acquisitions, Capitalized Interest, Dry Hole Costs and Other Property, Plant and Equipment. The forecast excludes Property Acquisitions, Asset Retirement Costs, Non–Cash Exchanges and Transactions and exploration costs incurred as operating expenses.

Glossary

Acq
Acquisitions

Adjusted CFO
Cash flow from operations before changes in working capital and certain acquisition–related costs

ATROR
After–tax rate of return

Bbl
Barrel

Bn
Billion

Boe
Barrels of oil equivalent

Bopd
Barrels of oil per day

CAGR
Compound annual growth rate

Capex
Capital expenditures

CO2e
Carbon dioxide equivalent

DD&A
Depreciation, Depletion and Amortization

Disc
Discoveries

Divest
Divestitures

EPS
Earnings per share

Ext
Extensions

GAAP
Generally Accepted Accounting Principles

G&A
General and administrative expense

G&P
Gathering and processing

GHG
Greenhouse gas

GP&T
Gathering, processing & transportation expense

HH
Henry Hub

LOE
Lease operating expense, or lease and well expense

MBbld
Thousand barrels of liquids per day

MBod
Thousand barrels of oil per day

MBoe
Thousand barrels of oil equivalent

MBoed
Thousand barrels of oil equivalent per day

Mcf
Thousand cubic feet of natural gas

MMBoe
Million barrels of oil equivalent

MMcfd
Million cubic feet of natural gas per day

NGLs
Natural gas liquids

NYMEX
U.S. New York Mercantile Exchange

OTP
Other than price

QoQ
Quarter over quarter

TOTI
Taxes other than income

USD
United States dollar

WTI
West Texas Intermediate

YoY
Year over year

$MM
Million United States dollars

$/Bbl
U.S. Dollars per barrel

$/Boe
U.S. Dollars per barrel of oil equivalent

$/Mcf
U.S. Dollars per thousand cubic feet

This press release and any accompanying disclosures may include forward–looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG’s future financial position, operations, performance, business strategy, goals, returns and rates of return, budgets, reserves, levels of production, capital expenditures, operating costs and asset sales, statements regarding future commodity prices, statements regarding the plans and objectives of EOG’s management for future operations and statements and projections regarding the strategic rationale for, and anticipated benefits of, EOG’s acquisition of Encino Acquisition Partners, LLC (Encino) are forward–looking statements. EOG typically uses words such as “expect,” “anticipate,” “estimate,” “project,” “strategy,” “intend,” “plan,” “target,” “aims,” “ambition,” “initiative,” “goal,” “may,” “will,” “focused on,” “should” and “believe” or the negative of those terms or other variations or comparable terminology to identify its forward–looking statements. In particular, statements, express or implied, concerning (i) EOG’s future financial or operating results and returns, (ii) EOG’s ability to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control drilling, completion and operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, other environmental matters or safety matters, pay and/or increase regular and/or special dividends or repurchase shares or (iii) the successful integration of Encino’s assets and operations or the strategic rationale for, or anticipated benefits of, EOG’s acquisition of Encino, in each case are forward–looking statements. Forward–looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward–looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that such assumptions are accurate or will prove to have been correct or that any of such expectations will be achieved (in full or at all) or will be achieved on the expected or anticipated timelines. Moreover, EOG’s forward–looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG’s control. Important factors that could cause EOG’s actual results to differ materially from the expectations reflected in EOG’s forward–looking statements include, among others:

the timing, magnitude and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids (NGLs),
natural gas and related commodities;
the extent to which EOG is successful in its efforts to acquire or discover additional reserves;
the extent to which EOG is successful in its efforts to (i) economically develop its acreage in, (ii) produce reserves and achieve anticipated production levels and rates of return from, (iii) decrease or otherwise control its drilling, completion and operating costs and capital expenditures related to, and (iv) maximize reserve recoveries from, its existing and future crude oil and natural gas exploration and development projects and associated potential and existing drilling locations;
the success of EOG’s cost–mitigation initiatives and actions in offsetting the impact of any inflationary or other pressures on EOG’s operating costs and capital expenditures;
the extent to which EOG is successful in its efforts to market its production of crude oil and condensate, NGLs and natural gas;
security threats, including cybersecurity threats and disruptions to our business and operations from breaches of our information technology systems, physical breaches of our facilities and other infrastructure or breaches of the information technology systems, facilities and infrastructure of third parties with which we transact business, and enhanced regulatory focus on the prevention of, and disclosure requirements relating to, cyber incidents;
the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, storage, transportation, refining, liquefaction and export facilities and equipment;
the availability, cost, terms and timing of issuance or execution of mineral licenses, concessions and leases and governmental and other permits and rights–of–way, and EOG’s ability to retain mineral licenses, concessions and leases;
the impact of, and changes in, government policies, laws and regulations, including climate change–related regulations, policies and initiatives (for example, with respect to air emissions); tax laws and regulations (including, but not limited to, carbon tax or other emissions–related legislation); environmental, health and safety laws and regulations relating to disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations affecting the leasing of acreage and permitting for oil and gas drilling and the calculation of royalty payments in respect of oil and gas production; laws and regulations imposing additional permitting and disclosure requirements, additional operating restrictions and conditions or restrictions on drilling and completion operations and on the transportation of crude oil, NGLs and natural gas; laws and regulations with respect to financial and other derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;
the impact of climate change–related legislation, policies and initiatives; climate change–related political, social and shareholder activism; and physical, transition and reputational risks and other potential developments related to climate change;
the extent to which EOG is able to successfully and economically develop, implement and carry out its emissions and other environmental or safety–related initiatives and achieve its related targets, goals, ambitions and initiatives;
EOG’s failure to realize, in full or at all, the anticipated benefits of its acquisition of Encino and/or business disruptions resulting from the acquisition (e.g., relating to the integration of Encino’s assets and operations into EOG’s operations) that could harm EOG’s business operations (including current plans and operations and the diversion of management’s attention from EOG’s ongoing business operations);
EOG’s ability to effectively integrate acquired crude oil and natural gas properties into its operations, identify and resolve existing and potential issues with respect to such properties and accurately estimate reserves, production, drilling, completion and operating costs and capital expenditures with respect to such properties;
the extent to which EOG’s third–party–operated crude oil and natural gas properties are operated successfully, economically and in compliance with applicable laws and regulations;
competition in the oil and gas exploration and production industry for the acquisition of licenses, concessions, leases and properties;
the availability and cost of, and competition in the oil and gas exploration and production industry for, employees, labor and other personnel, facilities, equipment, materials (such as water, sand, fuel and tubulars) and services;
the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;
weather and natural disasters, including its impact on crude oil and natural gas demand, and related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, liquefaction, compression, storage, transportation, and export facilities;
the ability of EOG’s customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;
EOG’s ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;
the extent to which EOG is successful in its completion of planned asset dispositions;
the extent and effect of any hedging activities engaged in by EOG;
the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;
the economic and financial impact of epidemics, pandemics or other public health issues;
geopolitical factors and political conditions and developments around the world (such as the imposition of tariffs or trade or other economic sanctions, political instability and armed conflicts), including in the areas in which EOG operates;
the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage; and
the other factors described under ITEM 1A, Risk Factors of EOG’s Annual Report on Form 10–K for the fiscal year ended December 31, 2024, and any updates to those factors set forth in EOG’s subsequent Quarterly Reports on Form 10–Q or Current Reports on Form 8–K.

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

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

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

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

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

9,510

Natural Gas Liquids
513
515
524
554
2,106

572
534
604

1,710

Natural Gas
382
303
372
494
1,551

637
600
707

1,944

Gains (Losses) on Mark-to-Market
Financial Commodity and Other
Derivative Contracts, Net
237
(47)
79
(65)
204

(191)
107
116

32

Gathering, Processing and Marketing
1,459
1,519
1,481
1,341
5,800

1,340
1,247
1,178

3,765

Gains (Losses) on Asset Dispositions,
Net
26
20
(7)
(23)
16

(1)
—
(18)

(19)

Other, Net
26
23
28
23
100

19
16
17

52

Total
6,123
6,025
5,965
5,585
23,698

5,669
5,478
5,847

16,994

Operating Expenses

Lease and Well
396
390
392
394
1,572

401
396
431

1,228

Gathering, Processing and
Transportation Costs
413
423
445
441
1,722

440
455
587

1,482

Exploration Costs
45
34
43
52
174

41
74
71

186

Dry Hole Costs
1
5
—
8
14

34
11
—

45

Impairments
19
81
15
276
391

44
39
71

154

Marketing Costs
1,404
1,490
1,500
1,323
5,717

1,325
1,216
1,134

3,675

Depreciation, Depletion and
Amortization
1,074
984
1,031
1,019
4,108

1,013
1,053
1,169

3,235

General and Administrative
162
151
167
189
669

171
186
239

596

Taxes Other Than Income
338
337
283
291
1,249

341
301
309

951

Total
3,852
3,895
3,876
3,993
15,616

3,810
3,731
4,011

11,552

Operating Income
2,271
2,130
2,089
1,592
8,082

1,859
1,747
1,836

5,442

Other Income, Net
62
66
76
70
274

65
55
59

179

Income Before Interest Expense and
Income Taxes
2,333
2,196
2,165
1,662
8,356

1,924
1,802
1,895

5,621

Interest Expense, Net
33
36
31
38
138

47
51
71

169

Income Before Income Taxes
2,300
2,160
2,134
1,624
8,218

1,877
1,751
1,824

5,452

Income Tax Provision
511
470
461
373
1,815

414
406
353

1,173

Net Income
1,789
1,690
1,673
1,251
6,403

1,463
1,345
1,471

4,279

Dividends Declared per Common Share
0.9100
0.9100
0.9100
0.9750
3.7050

0.9750
1.9950
—

2.9700

Net Income Per Share

Basic
3.11
2.97
2.97
2.25
11.31

2.66
2.48
2.72

7.85

Diluted
3.10
2.95
2.95
2.23
11.25

2.65
2.46
2.70

7.81

Average Number of Common Shares

Basic
575
569
564
557
566

550
543
541

545

Diluted
577
572
568
561
569

553
546
544

548

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

512.4

Trinidad
0.6
0.6
1.2
1.1
0.8

1.2
1.1
1.6

1.3

Total
487.4
490.7
493.0
494.6
491.4

502.1
504.2
534.5

513.7

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

$   67.83

Trinidad
67.50
70.75
63.15
60.47
64.43

61.12
54.50
57.74

57.80

Composite
78.45
82.69
76.92
71.66
77.40

72.87
64.82
65.95

67.81

Natural Gas Liquids Volumes (MBbld) (A)

United States
231.7
244.8
254.3
252.5
245.9

241.7
258.4
309.3

270.0

Total
231.7
244.8
254.3
252.5
245.9

241.7
258.4
309.3

270.0

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

$   23.20

Composite
24.32
23.11
22.42
23.85
23.40

26.29
22.70
21.25

23.20

Natural Gas Volumes (MMcfd) (A)

United States
1,658
1,668
1,745
1,840
1,728

1,834
1,977
2,511

2,110

Trinidad
200
204
225
252
220

246
252
230

243

Other International (C)
—
—
—
—
—

—
—
4

1

Total
1,858
1,872
1,970
2,092
1,948

2,080
2,229
2,745

2,354

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

Trinidad
3.54
3.48
3.68
3.86
3.65

3.78
3.65
3.80

3.74

Other International (C)
—
—
—
—
—

—
—
3.27

3.27

Composite
2.26
1.78
2.05
2.57
2.17

3.41
2.96
2.80

3.03

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

1,134.1

Trinidad
34.1
34.5
38.6
43.0
37.6

42.1
43.2
39.8

41.7

Other International
—
—
—
—
—

—
—
0.7

0.2

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

1,176.0

Total MMBoe (D)
93.6
95.3
99.0
100.8
388.7

98.1
103.2
119.7

321.0

(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 10 to the Condensed Consolidated Financial Statements in EOG’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2025).

(C)
Other International represents EOG’s Kingdom of 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

Accounts Receivable, Net
2,688
2,657
2,545
2,650

2,621
2,504
2,680

Inventories
1,154
1,069
1,038
985

897
934
945

Assets from Price Risk Management Activities
110
4
—
—

—
—
19

Other (A)
684
642
460
503

563
591
646

Total
9,928
9,803
10,165
11,230

10,680
9,245
7,820

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

Other Property, Plant and Equipment
5,768
6,078
6,314
6,418

6,510
6,616
6,772

Total Property, Plant and Equipment
79,124
80,693
82,201
83,509

84,942
86,755
95,073

Less:  Accumulated Depreciation, Depletion and
Amortization
(46,047)
(47,049)
(48,075)
(49,297)

(50,310)
(51,394)
(52,488)

Total Property, Plant and Equipment, Net
33,077
33,644
34,126
34,212

34,632
35,361
42,585

Deferred Income Taxes
38
44
42
39

44
39
37

Other Assets
1,753
1,733
1,818
1,705

1,626
1,639
1,757

Total Assets
44,796
45,224
46,151
47,186

46,982
46,284
52,199

Current Liabilities

Accounts Payable
2,389
2,436
2,290
2,464

2,353
2,266
2,944

Accrued Taxes Payable
786
600
855
1,007

668
348
392

Dividends Payable
523
516
513
539

534
1,081
550

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

Current Portion of Operating Lease Liabilities
318
303
338
315

318
360
433

Other
223
231
344
381

290
257
452

Total
4,273
4,628
4,406
5,354

5,719
5,175
4,815

Long-Term Debt
3,757
3,250
3,742
4,220

3,464
3,458
7,667

Other Liabilities
2,533
2,456
2,480
2,395

2,368
2,398
2,496

Deferred Income Taxes
5,597
5,731
5,949
5,866

5,915
6,015
6,936

Commitments and Contingencies

Stockholders’ Equity

Common Stock, $0.01 Par
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

Accumulated Other Comprehensive Loss
(8)
(8)
(9)
(4)

(4)
(7)
(5)

Retained Earnings
23,897
25,071
26,231
26,941

27,869
28,131
29,603

Common Stock Held in Treasury
(1,647)
(2,329)
(2,912)
(3,882)

(4,650)
(5,245)
(5,497)

Total Stockholders’ Equity
28,636
29,159
29,574
29,351

29,516
29,238
30,285

Total Liabilities and Stockholders’ Equity
44,796
45,224
46,151
47,186

46,982
46,284
52,199

(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

4,279

Items Not Requiring (Providing) Cash

Depreciation, Depletion and Amortization
1,074
984
1,031
1,019
4,108

1,013
1,053
1,169

3,235

Impairments
19
81
15
276
391

44
39
71

154

Stock-Based Compensation Expenses
45
45
58
51
199

50
53
53

156

Deferred Income Taxes
199
128
220
(80)
467

44
105
278

427

(Gains) Losses on Asset Dispositions, Net
(26)
(20)
7
23
(16)

1
—
18

19

Other, Net
9
3
2
3
17

11
11
2

24

Dry Hole Costs
1
5
—
8
14

34
11
—

45

Mark-to-Market Financial Commodity and Other
Derivative Contracts (Gains) Losses, Net
(237)
47
(79)
65
(204)

191
(107)
(116)

(32)

Net Cash Received from (Payments for)
Settlements of Financial Commodity
Derivative Contracts
55
79
61
19
214

(38)
(24)
27

(35)

Changes in Components of Working Capital and
Other Assets and Liabilities

Accounts Receivable
58
33
109
(99)
101

48
122
133

303

Inventories
117
75
30
37
259

76
(45)
4

35

Accounts Payable
(58)
29
(159)
152
(36)

(129)
(107)
5

(231)

Accrued Taxes Payable
319
(185)
256
151
541

(339)
(321)
28

(632)

Other Assets
(161)
42
197
(34)
44

(43)
(43)
(28)

(114)

Other Liabilities
(71)
(20)
108
6
23

(96)
(52)
155

7

Changes in Components of Working Capital
Associated with Investing Activities
(229)
(127)
59
(85)
(382)

(41)
(8)
(159)

(208)

Net Cash Provided by Operating Activities
2,903
2,889
3,588
2,763
12,143

2,289
2,032
3,111

7,432

Investing Cash Flows

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

—
—
(4,464)

(4,464)

Additions to Oil and Gas Properties
(1,485)
(1,357)
(1,263)
(1,248)
(5,353)

(1,381)
(1,699)
(1,492)

(4,572)

Additions to Other Property, Plant and
Equipment
(350)
(313)
(239)
(117)
(1,019)

(102)
(94)
(171)

(367)

Proceeds from Sales of Assets
9
10
—
4
23

12
4
5

21

Changes in Components of Working Capital
Associated with Investing Activities
229
127
(59)
85
382

41
8
159

208

Net Cash Used in Investing Activities
(1,597)
(1,533)
(1,561)
(1,276)
(5,967)

(1,430)
(1,781)
(5,963)

(9,174)

Financing Cash Flows

Long-Term Debt Borrowings
—
—
—
985
985

—
—
3,472

3,472

Long-Term Debt Repayments
—
—
—
—
—

—
(500)
(1,266)

(1,766)

Dividends Paid
(525)
(520)
(533)
(509)
(2,087)

(538)
(528)
(545)

(1,611)

Treasury Stock Purchased
(759)
(699)
(795)
(993)
(3,246)

(806)
(602)
(479)

(1,887)

Proceeds from Stock Options Exercised and
Employee Stock Purchase Plan
—
11
—
11
22

—
11
—

11

Debt Issuance and Other Financing Costs
—
—
—
(2)
(2)

—
(7)
(7)

(14)

Repayment of Finance Lease Liabilities
(8)
(9)
(8)
(8)
(33)

(8)
(9)
(8)

(25)

Net Cash Used in Financing Activities
(1,292)
(1,217)
(1,336)
(516)
(4,361)

(1,352)
(1,635)
1,167

(1,820)

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)

(3,562)

Cash and Cash Equivalents at Beginning of Period
5,278
5,292
5,431
6,122
5,278

7,092
6,599
5,216

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

3,530

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.

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).

Adjusted Net Income
(Continued)

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

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.

Adjusted Net Income
(Continued)

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

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
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.

Adjusted Net Income
(Continued)

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

3Q 2024

Before
Tax

Income Tax
Impact

After
Tax

Diluted
Earnings
per Share

Reported Net Income (GAAP)
2,134

(461)

1,673

2.95

Adjustments:

Gains on Mark-to-Market Financial Commodity and Other Derivative
Contracts, Net
(79)

17

(62)

(0.11)

Net Cash Received from Settlements of Financial Commodity Derivative
Contracts (1)
61

(13)

48

0.08

Add: Losses on Asset Dispositions, Net
7

(2)

5

0.01

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
(37)

8

(29)

(0.06)

Adjusted Net Income (Non-GAAP)
2,097

(453)

1,644

2.89

Average Number of Common Shares

Basic

564

Diluted

568

(1)
Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG adds to reported Net Income (GAAP) the total net cash received from settlements of financial commodity derivative contracts during such period.  For the three months ended September 30, 2024, such amount was $61 million.

Adjusted Net Income
(Continued)

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

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
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.

Adjusted Net Income
(Continued)

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

FY 2023

Before
Tax

Income Tax
Impact

After
Tax

Diluted
Earnings per
Share

Reported Net Income (GAAP)
9,689

(2,095)

7,594

13.00

Adjustments:

Gains on Mark-to-Market Financial Commodity Derivative
Contracts, Net
(818)

176

(642)

(1.09)

Net Cash Payments for Settlements of Financial Commodity
Derivative Contracts (1)
(112)

24

(88)

(0.15)

Less: Gains on Asset Dispositions, Net
(95)

20

(75)

(0.13)

Add: Certain Impairments
42

(6)

36

0.06

Adjustments to Net Income
(983)

214

(769)

(1.31)

Adjusted Net Income (Non-GAAP)
8,706

(1,881)

6,825

11.69

Average Number of Common Shares

Basic

581

Diluted

584

(1)
Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG subtracts from reported Net Income (GAAP) the total net cash paid for settlements of financial commodity derivative contracts during such period.  For the twelve months ended December 31, 2023, such amount was $112 million.

Net Income per Share

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

2Q 2025 Net Income per Share (GAAP) – Diluted

2.46

Realized Prices

3Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and
Natural Gas per Boe
38.05

Less:  2Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and
Natural Gas per Boe
(39.80)

Subtotal
(1.75)

Multiplied by: 3Q 2025 Crude Oil Equivalent Volumes (MMBoe)
119.7

Total Change in Revenue
(209)

Add: Income Tax Benefit (Provision) Imputed (based on 22%)
46

Change in Net Income
(163)

Change in Diluted Earnings per Share

(0.30)

Volumes

3Q 2025 Crude Oil Equivalent Volumes (MMBoe)
119.7

Less:  2Q 2025 Crude Oil Equivalent Volumes (MMBoe)
(103.2)

Subtotal
16.5

Multiplied by:  3Q 2025 Composite Average Margin per Boe (GAAP) (Including Total
Exploration Costs) (refer to “Revenues, Costs and Margins Per Barrel of Oil Equivalent”
schedule below)
13.42

Change in Margin
221

Less:  Income Tax Benefit (Provision) Imputed (based on 22%)
(49)

Change in Net Income
172

Change in Diluted Earnings per Share

0.32

Certain Operating Costs per Boe

2Q 2025 Total Cash Operating Costs (GAAP) and Total DD&A per Boe
20.25

Less:  3Q 2025 Total Cash Operating Costs (GAAP) and Total DD&A per Boe
(20.27)

Subtotal
(0.02)

Multiplied by:  3Q 2025 Crude Oil Equivalent Volumes (MMBoe)
119.7

Change in Before-Tax Net Income
(2)

Add:  Income Tax Benefit (Provision) Imputed (based on 22%)
1

Change in Net Income
(1)

Change in Diluted Earnings per Share

0.00

Net Income Per Share
(Continued)

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

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

3Q 2025 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative
Contracts
116

Less:  Income Tax Benefit (Provision)
(25)

After Tax – (a)
91

Less: 2Q 2025 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative
Contracts
107

Less:  Income Tax Benefit (Provision)
(23)

After Tax – (b)
84

Change in Net Income – (a) – (b)
7

Change in Diluted Earnings per Share

0.01

Other (1)

0.21

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

2.70

3Q 2025 Average Number of Common Shares – Diluted
544

(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)

2Q 2025 Adjusted Net Income per Share (Non-GAAP) – Diluted

2.32

Realized Prices

3Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and
Natural Gas per Boe
38.05

Less:  2Q 2025 Composite Average Revenue from Sales of Crude Oil and Condensate, NGLs, and
Natural Gas per Boe
(39.80)

Subtotal
(1.75)

Multiplied by: 3Q 2025 Crude Oil Equivalent Volumes (MMBoe)
119.7

Total Change in Revenue
(209)

Add: Income Tax Benefit (Provision) Imputed (based on 22%)
46

Change in Net Income
(163)

Change in Diluted Earnings per Share

(0.30)

Volumes

3Q 2025 Crude Oil Equivalent Volumes (MMBoe)
119.7

Less:  2Q 2025 Crude Oil Equivalent Volumes (MMBoe)
(103.2)

Subtotal
16.5

Multiplied by:  3Q 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)
13.99

Change in Margin
231

Less:  Income Tax Benefit (Provision) Imputed (based on 22%)
(51)

Change in Net Income
180

Change in Diluted Earnings per Share

0.33

Certain Operating Costs per Boe

2Q 2025 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe
20.14

Less:  3Q 2025 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe
(19.70)

Subtotal
0.44

Multiplied by:  3Q 2025 Crude Oil Equivalent Volumes (MMBoe)
119.7

Change in Before-Tax Net Income
53

Add:  Income Tax Benefit (Provision) Imputed (based on 22%)
(12)

Change in Net Income
41

Change in Diluted Earnings per Share

0.08

Adjusted Net Income Per Share
(Continued)

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

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

3Q 2025 Net Cash Received from (Payments for)  Settlements of Financial Commodity Derivative
Contracts
27

Less:  Income Tax Benefit (Provision)
(5)

After Tax – (a)
22

Less: 2Q 2025 Net Cash Received from (Payments for) Settlements of Financial Commodity
Derivative Contracts
(24)

Less:  Income Tax Benefit (Provision)
5

After Tax – (b)
(19)

Change in Net Income – (a) – (b)
41

Change in Diluted Earnings per Share

0.08

Other (1)

0.20

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

2.71

3Q 2025 Average Number of Common Shares – Diluted
544

(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 and third 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 and third 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

7,432

Adjustments:

Changes in Components of Working Capital
and Other Assets and Liabilities

Accounts Receivable
(58)
(33)
(109)
99
(101)

(48)
(122)
(133)

(303)

Inventories
(117)
(75)
(30)
(37)
(259)

(76)
45
(4)

(35)

Accounts Payable
58
(29)
159
(152)
36

129
107
(5)

231

Accrued Taxes Payable
(319)
185
(256)
(151)
(541)

339
321
(28)

632

Other Assets
161
(42)
(197)
34
(44)

43
43
28

114

Other Liabilities
71
20
(108)
(6)
(23)

96
52
(155)

(7)

Changes in Components of Working Capital
Associated with Investing Activities
229
127
(59)
85
382

41
8
159

208

Add:

Acquisition-Related Costs (1), Net of Tax
—
—
—
—
—

—
10
58

68

Adjusted Cash Flow from Operations (Non-
GAAP)
2,928
3,042
2,988
2,635
11,593

2,813
2,496
3,031

8,340

Less:

Total Capital Expenditures (Non-GAAP) (2)
(1,703)
(1,668)
(1,497)
(1,358)
(6,226)

(1,484)
(1,523)
(1,648)

(4,655)

Free Cash Flow (Non-GAAP)
1,225
1,374
1,491
1,277
5,367

1,329
973
1,383

3,685

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

11,973

Less:

Asset Retirement Costs
(21)
60
(11)
(26)
2

(13)
(14)
(86)

(113)

Non-Cash Leasehold Acquisition Costs (3)
(31)
(34)
(17)
(3)
(85)

(9)
(2)
(3)

(14)

Acquisition Costs of Properties (3)
(21)
(5)
—
(7)
(33)

1
(270)
(6,736)

(7,005)

Acquisition Costs of Other Property,
Plant and Equipment
(131)
(1)
(5)
—
(137)

—
—
—

—

Exploration Costs
(45)
(34)
(43)
(52)
(174)

(41)
(74)
(71)

(186)

Total Capital Expenditures (Non-GAAP)
1,703
1,668
1,497
1,358
6,226

1,484
1,523
1,648

4,655

Cash Flow from Operations and Free Cash Flow (Continued) 

In millions of USD (Unaudited)

FY 2023

FY 2022

Net Cash Provided by Operating Activities (GAAP)

11,340

11,093

Adjustments:

Changes in Components of Working Capital and Other Assets and Liabilities

Accounts Receivable

38

347

Inventories

231

534

Accounts Payable

119

(90)

Accrued Taxes Payable

(61)

113

Other Assets

(39)

364

Other Liabilities

(184)

266

Changes in Components of Working Capital Associated with Investing Activities

(295)

(375)

Adjusted Cash Flow from Operations (Non-GAAP)

11,149

12,252

Less:

Total Capital Expenditures (Non-GAAP) (a)

(6,041)

(4,607)

Free Cash Flow (Non-GAAP)

5,108

7,645

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

Total Expenditures (GAAP)

6,818

5,610

Less:

Asset Retirement Costs

(257)

(298)

Non-Cash Development Drilling

(90)

—

Non-Cash Leasehold Acquisition Costs (3)

(99)

(127)

Acquisition Costs of Properties (3)

(16)

(419)

Acquisition Costs of Other Property, Plant and Equipment

(134)

—

Exploration Costs

(181)

(159)

Total Capital Expenditures (Non-GAAP)

6,041

4,607

(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.

September 30,
2025

June 30,
2025

March 31,
2025

December 31,
2024

September 30,
2024

Total Stockholders’ Equity – (a)
30,285

29,238

29,516

29,351

29,574

Current and Long-Term Debt (GAAP) – (b)
7,694

4,236

4,744

4,752

3,776

Less: Cash
(3,530)

(5,216)

(6,599)

(7,092)

(6,122)

Net Debt (Non-GAAP) – (c)
4,164

(980)

(1,855)

(2,340)

(2,346)

Total Capitalization (GAAP) – (a) + (b)
37,979

33,474

34,260

34,103

33,350

Total Capitalization (Non-GAAP) – (a) + (c)
34,449

28,258

27,661

27,011

27,228

Debt-to-Total Capitalization (GAAP) – (b) / [(a) + (b)]
20.3 %

12.7 %

13.8 %

13.9 %

11.3 %

Net Debt-to-Total Capitalization (Non-GAAP) – (c) /
[(a) + (c)]
12.1 %

-3.5 %

-6.7 %

-8.7 %

-8.6 %

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.

3Q 2025

2Q 2025

1Q 2025

4Q 2024

3Q 2024

Volume – Million Barrels of Oil Equivalent – (a)
119.7

103.2

98.1

100.8

99.0

Total Operating Revenues and Other – (b)
5,847

5,478

5,669

5,585

5,965

Total Operating Expenses – (c)
4,011

3,731

3,810

3,993

3,876

Operating Income – (d)
1,836

1,747

1,859

1,592

2,089

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

Crude Oil and Condensate
3,243

2,974

3,293

3,261

3,488

Natural Gas Liquids
604

534

572

554

524

Natural Gas
707

600

637

494

372

Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural
Gas  – (e)
4,554

4,108

4,502

4,309

4,384

Operating Costs

Lease and Well
431

396

401

394

392

Gathering, Processing and Transportation Costs (1)
587

455

440

441

445

General and Administrative (GAAP)
239

186

171

189

167

Less:  Certain Items (see Endnotes 2 & 3 to 3Q 2025 earnings release)
(68)

(12)

—

—

(10)

General and Administrative (Non-GAAP) (2)
171

174

171

189

157

Taxes Other Than Income (GAAP)
309

301

341

291

283

Add:  Severance Tax Refund
—

—

—

—

31

Taxes Other Than Income (Non-GAAP) (3)
309

301

341

291

314

Interest Expense, Net
71

51

47

38

31

Less:  Acquisition-Related Financing Commitment Costs
—

(6)

—

—

—

Interest Expense, Net  (Non-GAAP) (4)
71

45

47

38

31

Total Operating Cost (GAAP)  (excluding DD&A and Total Exploration Costs)
– (f)
1,637

1,389

1,400

1,353

1,318

Total Operating Cost (Non-GAAP)  (excluding DD&A and Total Exploration
Costs) – (g)
1,569

1,371

1,400

1,353

1,339

Depreciation, Depletion and Amortization (DD&A)
1,169

1,053

1,013

1,019

1,031

Total Operating Cost (GAAP) (excluding Total Exploration Costs) – (h)
2,806

2,442

2,413

2,372

2,349

Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) – (i)
2,738

2,424

2,413

2,372

2,370

Exploration Costs
71

74

41

52

43

Dry Hole Costs
—

11

34

8

—

Impairments
71

39

44

276

15

Total Exploration Costs (GAAP)
142

124

119

336

58

Less:  Certain Impairments (5)
—

(11)

—

(254)

—

Total Exploration Costs (Non-GAAP)
142

113

119

82

58

Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) – (j)
2,948

2,566

2,532

2,708

2,407

Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non-
GAAP)) – (k)
2,880

2,537

2,532

2,454

2,428

Total Revenues from Sales of Crude Oil and Condensate, NGLs, and Natural
Gas less Total Operating Cost (GAAP) (including Total Exploration Costs
(GAAP))
1,606

1,542

1,970

1,601

1,977

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))
1,674

1,571

1,970

1,855

1,956

Revenues, Costs and Margins Per Barrel of Oil Equivalent 

(Continued)

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

3Q 2025

2Q 2025

1Q 2025

4Q 2024

3Q 2024

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

Composite Average Operating Revenues and Other per Boe – (b) / (a)
48.85

53.08

57.79

55.41

60.25

Composite Average Operating Expenses per Boe – (c) / (a)
33.51

36.15

38.84

39.62

39.15

Composite Average Operating Income per Boe  – (d) / (a)
15.34

16.93

18.95

15.79

21.10

Composite Average Revenue from Sales of Crude Oil and Condensate,
NGLs, and Natural Gas per Boe – (e) / (a)
38.05

39.80

45.88

42.74

44.31

Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) –
(f) / (a)
13.67

13.46

14.26

13.42

13.32

Composite Average Margin per Boe (excluding DD&A and Total Exploration
Costs) – [(e) / (a) – (f) / (a)]
24.38

26.34

31.62

29.32

30.99

Total Operating Cost per Boe (excluding Total Exploration Costs) – (h) / (a)
23.44

23.66

24.58

23.53

23.74

Composite Average Margin per Boe (excluding Total Exploration Costs) –
[(e) / (a) – (h) / (a)]
14.61

16.14

21.30

19.21

20.57

Total Operating Cost per Boe (including Total Exploration Costs) – (j) / (a)
24.63

24.86

25.79

26.86

24.33

Composite Average Margin per Boe (including Total Exploration Costs) –
[(e) / (a) – (j) / (a)]
13.42

14.94

20.09

15.88

19.98

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

Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) –
(g) / (a)
13.10

13.30

14.26

13.42

13.53

Composite Average Margin per Boe (excluding DD&A and Total Exploration
Costs) – [(e) / (a) – (g) / (a)]
24.95

26.50

31.62

29.32

30.78

Total Operating Cost per Boe (excluding Total Exploration Costs) – (i) / (a)
22.87

23.50

24.58

23.53

23.95

Composite Average Margin per Boe (excluding Total Exploration Costs) –
[(e) / (a) – (i) / (a)]
15.18

16.30

21.30

19.21

20.36

Total Operating Cost per Boe (including Total Exploration Costs) – (k) / (a)
24.06

24.59

25.79

24.34

24.54

Composite Average Margin per Boe (including Total Exploration Costs) –
[(e) / (a) – (k) / (a)]
13.99

15.21

20.09

18.40

19.77

Revenues, Costs and Margins Per Barrel of Oil Equivalent 

(Continued)

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

2024

2023

2022

Volume – Million Barrels of Oil Equivalent – (a)

388.7

359.4

331.5

Total Operating Revenues and Other – (b)

23,698

24,186

25,702

Total Operating Expenses – (c)

15,616

14,583

15,736

Operating Income (Loss) – (d)

8,082

9,603

9,966

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

Crude Oil and Condensate

13,921

13,748

16,367

Natural Gas Liquids

2,106

1,884

2,648

Natural Gas

1,551

1,744

3,781

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

17,578

17,376

22,796

Operating Costs

Lease and Well

1,572

1,454

1,331

Gathering, Processing and Transportation Costs (1)

1,722

1,620

1,587

General and Administrative (GAAP)

669

640

570

Less:  Severance Tax Consulting Fees

(10)

—

(16)

General and Administrative (Non-GAAP) (2)

659

640

554

Taxes Other Than Income (GAAP)

1,249

1,284

1,585

Add:  Severance Tax Refund

31

—

115

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

1,280

1,284

1,700

Interest Expense, Net

138

148

179

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

5,350

5,146

5,252

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

5,371

5,146

5,351

Depreciation, Depletion and Amortization (DD&A)

4,108

3,492

3,542

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

9,458

8,638

8,794

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

9,479

8,638

8,893

Exploration Costs

174

181

159

Dry Hole Costs

14

1

45

Impairments

391

202

382

Total Exploration Costs (GAAP)

579

384

586

Less:  Certain Impairments (5)

(291)

(42)

(113)

Total Exploration Costs (Non-GAAP)

288

342

473

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

10,037

9,022

9,380

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

9,767

8,980

9,366

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

7,541

8,354

13,416

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))

7,811

8,396

13,430

Revenues, Costs and Margins Per Barrel of Oil Equivalent 

(Continued)

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

2024

2023

2022

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

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

60.97

67.30

77.53

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

40.18

40.58

47.47

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

20.79

26.72

30.06

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

45.22

48.34

68.77

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

13.76

14.31

15.84

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

31.46

34.03

52.93

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

24.33

24.03

26.53

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

20.89

24.31

42.24

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

25.82

25.10

28.30

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

19.40

23.24

40.47

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

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

13.82

14.31

16.14

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

31.40

34.03

52.63

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

24.39

24.03

26.83

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

20.83

24.31

41.94

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

25.13

24.98

28.26

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

20.09

23.36

40.51

(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.

2024 Actual

2023 Actual

2022 Actual

Crude Oil and Condensate Volumes (MBod)

United States

490.6

475.2

460.7

Trinidad

0.8

0.6

0.6

Total

491.4

475.8

461.3

Natural Gas Liquids Volumes (MBbld)

Total

245.9

223.8

197.7

Natural Gas Volumes (MMcfd)

United States

1,728

1,551

1,315

Trinidad

220

160

180

Total

1,948

1,711

1,495

Crude Oil Equivalent Volumes (MBoed)

United States

1,024.5

957.5

877.5

Trinidad

37.6

27.3

30.7

Total

1,062.1

984.8

908.2

Benchmark Price

Oil (WTI) ($/Bbl)

75.72

77.61

94.23

Natural Gas (HH) ($/Mcf)

2.27

2.74

6.64

Crude Oil and Condensate – above (below) WTI1 ($/Bbl)

United States

1.70

1.57

2.99

Trinidad

(11.29)

(9.03)

(8.07)

Natural Gas Liquids – Realizations as % of WTI

Total

30.9 %

29.7 %

39.0 %

Natural Gas – above (below) NYMEX Henry Hub2 ($/Mcf)

United States

(0.28)

(0.04)

0.63

Natural Gas Realizations3 ($/Mcf)

Trinidad

3.65

3.65

4.43

Total Expenditures (GAAP) ($MM)

6,653

6,818

5,610

Capital Expenditures4 (non-GAAP) ($MM)

6,226

6,041

4,607

Operating Unit Costs ($/Boe)

Lease and Well

4.04

4.05

4.02

Gathering, Processing and Transportation Costs5

4.43

4.50

4.78

General and Administrative (GAAP)

1.72

1.78

1.72

General and Administrative (non-GAAP)6

1.70

1.78

1.67

Cash Operating Costs (GAAP)

10.19

10.33

10.52

Cash Operating Costs (non-GAAP)6

10.17

10.33

10.47

Depreciation, Depletion and Amortization

10.57

9.72

10.69

Expenses ($MM)

Exploration and Dry Hole

188

182

204

Impairment (GAAP)

391

202

382

Impairment (excluding certain impairments (non-GAAP))7

100

160

269

Capitalized Interest

45

33

36

Net Interest

138

148

179

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

(GAAP)

7.1 %

7.4 %

7.0 %

(non-GAAP)6

7.3 %

7.4 %

7.5 %

Income Taxes

Effective Rate

22.1 %

21.6 %

21.7 %

Current Tax Expense ($MM)

1,348

1,415

2,208

Additional Key Information

(Continued)

Endnotes

1)
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.

2)
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.

3)
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.

4)
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.

5)
Effective January 1, 2024, EOG combined Transportation Costs and Gathering and Processing Costs into one line item titled Gathering, Processing and Transportation Costs.  This presentation has been conformed for all periods presented and had no impact on previously reported Net Income.

6)
Cash Operating Costs consist of LOE, GP&T and G&A.  TOTI (% of revenues from sales of crude oil and condensate, NGLs and natural gas) (non-GAAP) and G&A (non-GAAP) for fiscal year 2024 and fiscal year 2022 exclude a state severance tax refund and related consulting fees, respectively, as reflected in the accompanying reconciliation schedules (see “Revenues, Costs and Margins Per Barrel of Oil Equivalent”).  The per-Boe impact of such consulting fees on G&A and total Cash Operating Costs for fiscal year 2024 and fiscal year 2022 was $(0.02) and $(0.05), respectively.

7)
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).

SOURCE EOG Resources, Inc.