EX-99.12exh99-1022426.htmPRESS RELEASE OF EOG RESOURCES, INC. Document
EXHIBIT 99.1
Table of Contents
Fourth Quarter 2025
Supplemental Financial and Operating Data
Page
Income Statements
12
Volumes and Prices
13
Balance Sheets
14
Cash Flow Statements
15
Non-GAAP Financial Measures
16
Adjusted Net Income
17
Net Income Per Share
21
Adjusted Net Income Per Share
23
Cash Flow from Operations and Free Cash Flow
25
Net Debt-to-Total Capitalization Ratio
27
Proved Reserves and Reserve Replacement Data
28
Reserve Replacement Cost Data
29
Revenues, Costs and Margins Per Barrel of Oil Equivalent
32
Additional Key Financial Information
36
11
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
12
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.
13
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.
14
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
15
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.
16
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).
17
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).
18
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.
19
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.
20
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.
21
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.
22
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.
23
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.
24
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
25
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.
26
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
%
27
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
28
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 $269 million of proved properties adjacent to EOG’s core acreage in the Eagle Ford play.
(2)Includes 678 MMBoe related to the Encino acquisition and 70 MMBoe related to the acquisition of proved properties adjacent to EOG’s core acreage in the Eagle ford play.
29
Reserve Replacement Cost Data
(Continued)
(Unaudited; in millions, except ratio data)
For the Twelve Months Ended December 31, 2025
Proved Developed Reserve Replacement Costs ($ / 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
30
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
31
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
32
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
33
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
34
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).
35
Additional Key Financial Information
(Unaudited)
See “Endnotes” below for related discussion and definitions.
2025 Actual
2024 Actual
2023 Actual
2022 Actual
2021 Actual
Crude Oil and Condensate Volumes (MBod)
United States
520.5
490.6
475.2
460.7
443.4
Trinidad
1.4
0.8
0.6
0.6
1.5
Other International
—
—
—
—
0.1
Total
521.9
491.4
475.8
461.3
445.0
Natural Gas Liquids Volumes (MBbld)
Total
288.2
245.9
223.8
197.7
144.5
Natural Gas Volumes (MMcfd)
United States
2,299
1,728
1,551
1,315
1,210
Trinidad
230
220
160
180
217
Other International1
4
—
—
—
9
Total
2,533
1,948
1,711
1,495
1,436
Crude Oil Equivalent Volumes (MBoed)
United States
1,191.8
1,024.5
957.5
877.5
789.6
Trinidad
39.8
37.6
27.3
30.7
37.7
Other International1
0.6
—
—
—
1.6
Total
1,232.2
1,062.1
984.8
908.2
828.9
Benchmark Price
Oil (WTI) ($/Bbl)
64.78
75.72
77.61
94.23
67.96
Natural Gas (HH) ($/Mcf)
3.43
2.27
2.74
6.64
3.85
Crude Oil and Condensate - above (below) WTI2 ($/Bbl)
United States
0.87
1.70
1.57
2.99
0.58
Trinidad
(7.19)
(11.29)
(9.03)
(8.07)
(11.70)
Other International1
0.36
—
—
—
—
Natural Gas Liquids - Realizations as % of WTI
Total
34.9
%
30.9
%
29.7
%
39.0
%
50.5
%
Natural Gas - above (below) NYMEX Henry Hub3 ($/Mcf)
United States
(0.49)
(0.28)
(0.04)
0.63
1.03
Natural Gas Realizations4 ($/Mcf)
Trinidad
3.78
3.65
3.65
4.43
3.40
Other International1
3.28
—
—
—
—
Total Expenditures (GAAP) ($MM)
13,703
6,653
6,818
5,610
4,255
Capital Expenditures5 (non-GAAP) ($MM)
6,294
6,226
6,041
4,607
3,755
Operating Unit Costs ($/Boe)
Lease and Well
3.72
4.04
4.05
4.02
3.75
Gathering, Processing and Transportation Costs6
4.74
4.43
4.50
4.78
4.70
General and Administrative (GAAP)
1.82
1.72
1.78
1.72
1.69
General and Administrative (non-GAAP)7
1.63
1.70
1.78
1.67
1.69
Cash Operating Costs (GAAP)
10.28
10.19
10.33
10.52
10.14
Cash Operating Costs (non-GAAP)7
10.09
10.17
10.33
10.47
10.14
Depreciation, Depletion and Amortization
9.92
10.57
9.72
10.69
12.07
Expenses ($MM)
Exploration and Dry Hole
285
188
182
204
225
Impairment (GAAP)
843
391
202
382
376
Impairment (excluding certain impairments (non-GAAP))8
186
100
160
269
361
Capitalized Interest
86
45
33
36
33
Net Interest
235
138
148
179
178
Net Interest (non-GAAP)9
229
—
—
—
—
TOTI (% of revenues from sales of crude oil and condensate, NGLs and natural gas)
(GAAP)
7.0
%
7.1
%
7.4
%
7.0
%
6.8
%
(non-GAAP)7
7.0
%
7.3
%
7.4
%
7.5
%
6.8
%
Income Taxes
Effective Rate
21.7
%
22.1
%
21.6
%
21.7
%
21.4
%
Current Tax Expense ($MM)
1,039
1,348
1,415
2,208
1,393
36
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).
37
Mentions · how they’re counted
| Category | Underlined | Word counter | Model’s count |
|---|---|---|---|
| AI AI, artificial intelligence, generative AI, machine learning, large language model, LLM | 0 | — | — |
| Layoffs layoffs, RIF, headcount reduction, workforce optimization, restructuring | 0 | — | — |
| Recession recession, downturn, contraction, slowdown | 0 | — | — |
| Tariffs tariff, trade war, trade barriers, trade restrictions, trade policy | 0 | — | — |
| Buybacks share repurchase, buyback program | 4 | — | — |
Underlines use the same word lists the scores use. AI, recession and tariffs follow Palanor’s word counter, so those counts match it exactly on the same text. Layoffs and buybacks use the terms the model was given. The model’s count is an estimate by meaning, not by string, so it can differ from the underlines.
Source: SEC EDGAR · public domain · Highlights by Palanor