HOUSTON, Feb. 27, 2025 /PRNewswire/ — EOG Resources, Inc. (EOG) today reported fourth quarter and full-year 2024 results. The attached supplemental financial tables and schedules for the reconciliation of non-GAAP measures to GAAP measures and related definitions, along with a related presentation, are also available on EOG’s website at http://investors.eogresources.com/investors.
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Key Financial Results |
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In millions of USD, except per-share, per-Boe and ratio data |
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|
GAAP |
4Q 2024 |
3Q 2024 |
2Q 2024 |
1Q 2024 |
4Q 2023 |
FY 2024 |
FY 2023 |
|||||||
|
Total Revenue |
5,585 |
5,965 |
6,025 |
6,123 |
6,357 |
23,698 |
24,186 |
|||||||
|
Net Income |
1,251 |
1,673 |
1,690 |
1,789 |
1,988 |
6,403 |
7,594 |
|||||||
|
Net Income Per Share |
2.23 |
2.95 |
2.95 |
3.10 |
3.42 |
11.25 |
13.00 |
|||||||
|
Net Cash Provided by Operating Activities |
2,763 |
3,588 |
2,889 |
2,903 |
3,104 |
12,143 |
11,340 |
|||||||
|
Total Expenditures |
1,446 |
1,573 |
1,682 |
1,952 |
1,634 |
6,653 |
6,818 |
|||||||
|
Current and Long-Term Debt |
4,752 |
3,776 |
3,784 |
3,791 |
3,799 |
4,752 |
3,799 |
|||||||
|
Cash and Cash Equivalents |
7,092 |
6,122 |
5,431 |
5,292 |
5,278 |
7,092 |
5,278 |
|||||||
|
Debt-to-Total Capitalization |
13.9 % |
11.3 % |
11.5 % |
11.7 % |
11.9 % |
13.9 % |
11.9 % |
|||||||
|
Cash Operating Costs ($/Boe) |
10.15 |
10.15 |
10.11 |
10.37 |
10.52 |
10.19 |
10.33 |
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|
Non – GAAP |
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|
Adjusted Net Income |
1,535 |
1,644 |
1,807 |
1,626 |
1,783 |
6,612 |
6,825 |
|||||||
|
Adjusted Net Income Per Share |
2.74 |
2.89 |
3.16 |
2.82 |
3.07 |
11.62 |
11.69 |
|||||||
|
CFO before Changes in Working Capital |
2,635 |
2,988 |
3,042 |
2,928 |
2,989 |
11,593 |
11,149 |
|||||||
|
Capital Expenditures |
1,358 |
1,497 |
1,668 |
1,703 |
1,512 |
6,226 |
6,041 |
|||||||
|
Free Cash Flow |
1,277 |
1,491 |
1,374 |
1,225 |
1,477 |
5,367 |
5,108 |
|||||||
|
Net Debt |
(2,340) |
(2,346) |
(1,647) |
(1,501) |
(1,479) |
(2,340) |
(1,479) |
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|
Net Debt-to-Total Capitalization |
(8.7 %) |
(8.6 %) |
(6.0 %) |
(5.5 %) |
(5.6 %) |
(8.7 %) |
(5.6 %) |
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|
Cash Operating Costs ($/Boe)1 |
10.15 |
10.05 |
10.11 |
10.37 |
10.52 |
10.17 |
10.33 |
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Fourth Quarter Highlights
– Earned adjusted net income of $1.5 billion, or $2.74 per share
– Generated $1.3 billion of free cash flow
– Declared regular quarterly dividend of $0.975 per share and repurchased $981 million of shares
– Oil and gas volumes, and total per-unit operating costs better than guidance midpoints
Full-Year 2024 Highlights and 2025 Capital Plan
– Generated $5.4 billion of free cash flow and returned $5.3 billion to shareholders
– Replaced 201% of 2024 production at a finding and development cost, excluding price revisions, of
$7.03 per Boe (GAAP) and $6.68 per Boe (Non-GAAP)
– Reduced average well costs 6% across multi-basin portfolio
– Announced $6.2 billion 2025 capital plan to grow oil production 3% and total production 6%
– EOG and Bapco Energies entered into a strategic participation agreement in Bahrain
Volumes and Capital Expenditures
|
Volumes |
4Q 2024 |
4Q 2024 |
3Q 2024 |
2Q 2024 |
1Q 2024 |
4Q 2023 |
FY 2024 |
FY 2023 |
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|
Crude Oil and Condensate (MBod) |
494.6 |
493.0 |
493.0 |
490.7 |
487.4 |
485.2 |
491.4 |
475.8 |
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|
Natural Gas Liquids (MBbld) |
252.5 |
260.0 |
254.3 |
244.8 |
231.7 |
235.8 |
245.9 |
223.8 |
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|
Natural Gas (MMcfd) |
2,092 |
2,075 |
1,970 |
1,872 |
1,858 |
1,831 |
1,948 |
1,711 |
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Total Crude Oil Equivalent (MBoed) |
1,095.7 |
1,098.9 |
1,075.7 |
1,047.5 |
1,028.8 |
1,026.2 |
1,062.1 |
984.8 |
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|
Capital Expenditures ($MM) |
1,358 |
1,330 |
1,497 |
1,668 |
1,703 |
1,512 |
6,226 |
6,041 |
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From Ezra Yacob, Chairman and Chief Executive Officer”2024 was another year of strong execution for EOG. Oil and total volumes were higher than our original plan, capital expenditures were on target, and we continued to lower cash operating costs. We improved productivity and base production performance through innovations in completion design and artificial lift automation. Along with better productivity, sustainable efficiency improvements from extended laterals and EOG’s in-house drilling motor program helped lower well costs 6%. Our comprehensive marketing strategy continued to deliver peer-leading U.S. price realizations, further maximizing margins across our portfolio. 2024 also marked another year of progress in the Utica and Dorado plays that resulted in consistent, strong results helping to support higher activity going forward.
“EOG’s operational execution supported the company’s exceptional financial performance and record cash return to shareholders in 2024. We generated $5.4 billion in free cash flow and returned $5.3 billion, or 98%, to shareholders. This robust cash return was anchored by our sustainable, growing regular dividend, which we increased by 7%, and included $3.2 billion in share repurchases. Since we initiated share repurchases in 2023, we have reduced our share count by approximately 5%. As we continue to optimize our capital structure, our strong cash flow generation and industry-leading balance sheet better position us to deliver shareholder value through the cycles.
“We are excited about 2025 where we have detailed a disciplined plan that builds on last year’s success and lays a foundation for the future. Our comprehensive investment approach, focused on returns and optimizing value from our diverse portfolio of multi-basin assets, coupled with our industry-leading exploration expertise, provide long-term visibility for high returns and strong free cash flow generation. EOG has never been better positioned to deliver long-term shareholder value and we remain focused on being among the highest return and lowest cost producers, committed to strong environmental performance and playing a significant role in the long-term future of energy.”
Fourth Quarter 2024 Financial Performance
Prices
– Crude oil prices decreased in 4Q compared with 3Q, partially offset by an increase in NGL and natural gas prices from 3Q
Volumes
– Oil production of 494,600 Bopd was above the midpoint of the guidance range and up from 3Q
– NGL production was below the midpoint of the guidance range and down from 3Q
– Natural gas production was above the midpoint of the guidance range and up 6% from 3Q
– Total company equivalent production was below the midpoint of the guidance range but increased 2% from 3Q
Per-Unit Costs
– LOE, GP&T, and DD&A expenses decreased in 4Q compared with 3Q, while G&A costs increased
Hedges
– Mark-to-market hedge losses decreased GAAP earnings per share in 4Q compared with 3Q
– Cash received to settle hedges decreased from 3Q, lowering adjusted non-GAAP earnings per share
Free Cash Flow
– Cash flow from operations before changes in working capital was $2.64 billion
– Incurred $1.36 billion of capital expenditures
– This resulted in $1.28 billion of free cash flow
Cash Return and Working Capital
– Paid $509 million in regular dividends
– Repurchased $981 million of stock
– Completed a $1.0 billion bond offering
Full-Year 2024 Financial Performance
Prices
– Crude oil prices decreased 2%
– NGL prices increased 1%
– Natural gas prices decreased 22%
Volumes
– Oil production increased 3% to 491,400 Bopd
– NGL production increased 10%
– Natural gas production increased 14%
– Total company equivalent production increased 8%
Per-Unit Costs
– Lower LOE, GP&T, and G&A costs were offset by higher DD&A expenses in 2024
Hedges
– Lower mark-to-market hedge gains contributed to lower GAAP earnings per share in 2024 compared with 2023
– Higher net cash received to settle hedges partially offset lower commodity prices in 2024
Free Cash Flow
– Cash flow from operations before changes in working capital was $11.6 billion
– Incurred $6.2 billion of capital expenditures
– This resulted in $5.4 billion of free cash flow
Cash Return and Working Capital
– Paid $2.1 billion in regular dividends
– Repurchased $3.2 billion of stock
– Completed a $1.0 billion bond offering
– Postponement of tax payments associated with severe weather tax relief accounted for approximately
$700 million of the increase from working capital and other items
Fourth Quarter 2024 Operating Performance and Cash Return
Lease and Well
– QoQ: Decreased primarily due to lower well service and labor costs
– Guidance Midpoint: Lower primarily due to lower workover expenses, labor and fuel costs
Gathering, Processing and Transportation Costs
– QoQ: Decreased primarily due to lower oil transportation expenses
– Guidance Midpoint: Lower primarily due to lower compression-related fuel cost
General and Administrative
– QoQ: Higher due to higher employee-related expenses and professional fees
– Guidance Midpoint: Lower due to lower employee-related expenses
Depreciation, Depletion and Amortization
– QoQ: Lower primarily due to the addition of lower cost reserves and positive reserve revisions
– Guidance Midpoint: Lower primarily due to the addition of lower cost reserves and positive reserve revisions
Regular Dividend and Fourth Quarter Share Repurchases
The Board of Directors today declared a dividend of $0.975 per share on EOG’s common stock. The dividend will be payable April 30, 2025, to stockholders of record as of April 16, 2025. The indicated annual rate is $3.90 per share, reflecting a 7% increase compared with 2024.
During the fourth quarter, the company repurchased 7.8 million shares for $981 million under its share repurchase authorization, at an average purchase price of $126 per share.
For full-year 2024, the company repurchased 25.8 million shares for $3.2 billion under its share repurchase authorization, at an average purchase price of $123 per share. EOG has $5.8 billion remaining on its current repurchase authorization.
2024 Reserves
Finding and Development Cost
Finding and development cost, excluding price revisions, decreased in 2024 to $6.68 per Boe, due to higher year-over-year well performance and cost reductions. Proved developed finding cost, excluding price revisions, was $8.71 per Boe (GAAP) and $8.04 per Boe (Non-GAAP) in 2024.
Reserve Replacement
Total proved reserves increased 6% in 2024. Extensions and discoveries added 580 MMBoe of proved reserves in 2024. Revisions other than price increased proved reserves by 215 MMBoe. Net proved reserve additions from all sources, excluding price revisions, replaced 201% of 2024 total production.
2025 Capital Program
Total expenditures for 2025 are expected to range from $6.0 to $6.4 billion, including exploration and development drilling, facilities, leasehold acquisitions, capitalized interest, dry hole costs, and other property, plant and equipment, and excluding property acquisitions, asset retirement costs and non-cash exchanges and transactions. The capital program also excludes certain exploration costs incurred as operating expenses.
The disciplined capital program is anchored by steady year-over-year activity levels in the Delaware Basin, with a step up in activity in the Utica and Dorado plays. The plan delivers 3% oil volume growth and 6% total volume growth through the drilling and completion of 605 net wells across EOG’s multi-basin portfolio of high return inventory.
The capital program also funds the completion of strategic infrastructure projects and international investment opportunities, including exploration projects in Trinidad and Bahrain.
EOG and Bapco Energies Entered Into a Strategic Participation Agreement in Bahrain
The companies will evaluate a natural gas exploration prospect with planned drilling activity in 2025. The transaction is subject to further government approvals.
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Fourth Quarter 2024 Results vs Guidance |
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(Unaudited) |
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See “Endnotes” below for related discussion and definitions. |
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4Q 2024 |
4Q 2024 Guidance |
Variance |
3Q 2024 |
2Q 2024 |
1Q 2024 |
4Q 2023 |
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Crude Oil and Condensate Volumes (MBod) |
||||||||||||||
|
United States |
493.5 |
491.9 |
1.6 |
491.8 |
490.1 |
486.8 |
484.6 |
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|
Trinidad |
1.1 |
1.1 |
0.0 |
1.2 |
0.6 |
0.6 |
0.6 |
|||||||
|
Total |
494.6 |
493.0 |
1.6 |
493.0 |
490.7 |
487.4 |
485.2 |
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|
Natural Gas Liquids Volumes (MBbld) |
||||||||||||||
|
Total |
252.5 |
260.0 |
(7.5) |
254.3 |
244.8 |
231.7 |
235.8 |
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|
Natural Gas Volumes (MMcfd) |
||||||||||||||
|
United States |
1,840 |
1,825 |
15 |
1,745 |
1,668 |
1,658 |
1,653 |
|||||||
|
Trinidad |
252 |
250 |
2 |
225 |
204 |
200 |
178 |
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|
Total |
2,092 |
2,075 |
17 |
1,970 |
1,872 |
1,858 |
1,831 |
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|
Total Crude Oil Equivalent Volumes (MBoed) |
1,095.7 |
1,098.9 |
(3.2) |
1,075.7 |
1,047.5 |
1,028.8 |
1,026.2 |
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|
Total MMBoe |
100.8 |
101.1 |
(0.3) |
99.0 |
95.3 |
93.6 |
94.4 |
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|
Benchmark Price |
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|
Oil (WTI) ($/Bbl) |
70.28 |
75.16 |
80.55 |
76.97 |
78.33 |
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|
Natural Gas (HH) ($/Mcf) |
2.79 |
2.16 |
1.89 |
2.24 |
2.87 |
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|
Crude Oil and Condensate – above (below) WTI4 ($/Bbl) |
||||||||||||||
|
United States |
1.40 |
1.75 |
(0.35) |
1.79 |
2.16 |
1.49 |
2.28 |
|||||||
|
Trinidad |
(9.81) |
(10.35) |
0.54 |
(12.01) |
(9.80) |
(9.47) |
(9.12) |
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|
Natural Gas Liquids – Realizations as % of WTI |
||||||||||||||
|
Total |
33.9 % |
32.0 % |
1.9 % |
29.8 % |
28.7 % |
31.6 % |
28.5 % |
|||||||
|
Natural Gas – above (below) NYMEX Henry Hub5 ($/Mcf) |
||||||||||||||
|
United States |
(0.40) |
(0.35) |
(0.05) |
(0.32) |
(0.32) |
(0.14) |
(0.15) |
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|
Natural Gas Realizations ($/Mcf) |
||||||||||||||
|
Trinidad |
3.86 |
3.65 |
0.21 |
3.68 |
3.48 |
3.54 |
3.81 |
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|
Total Expenditures (GAAP) ($MM) |
1,446 |
1,573 |
1,682 |
1,952 |
1,634 |
|||||||||
|
Capital Expenditures (non-GAAP) ($MM) |
1,358 |
1,330 |
28 |
1,497 |
1,668 |
1,703 |
1,512 |
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|
Operating Unit Costs ($/Boe) |
||||||||||||||
|
Lease and Well |
3.91 |
4.20 |
(0.29) |
3.96 |
4.09 |
4.23 |
4.00 |
|||||||
|
Gathering, Processing and Transportation Costs3 |
4.37 |
4.45 |
(0.08) |
4.50 |
4.44 |
4.41 |
4.49 |
|||||||
|
General and Administrative (GAAP) |
1.87 |
1.69 |
1.58 |
1.73 |
2.03 |
|||||||||
|
General and Administrative (non-GAAP)1 |
1.87 |
1.90 |
(0.03) |
1.59 |
1.58 |
1.73 |
2.03 |
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|
Cash Operating Costs (GAAP) |
10.15 |
10.15 |
10.11 |
10.37 |
10.52 |
|||||||||
|
Cash Operating Costs (non-GAAP)1 |
10.15 |
10.55 |
(0.40) |
10.05 |
10.11 |
10.37 |
10.52 |
|||||||
|
Depreciation, Depletion and Amortization |
10.11 |
10.35 |
(0.24) |
10.42 |
10.32 |
11.47 |
9.85 |
|||||||
|
Expenses ($MM) |
||||||||||||||
|
Exploration and Dry Hole |
60 |
60 |
0 |
43 |
39 |
46 |
41 |
|||||||
|
Impairment (GAAP) |
276 |
15 |
81 |
19 |
79 |
|||||||||
|
Impairment (excluding certain impairments (non-GAAP))6 |
23 |
120 |
(97) |
15 |
46 |
17 |
60 |
|||||||
|
Capitalized Interest |
13 |
11 |
2 |
12 |
10 |
10 |
9 |
|||||||
|
Net Interest |
38 |
33 |
5 |
31 |
36 |
33 |
35 |
|||||||
|
TOTI (% of Wellhead Revenue) (GAAP) |
6.8 % |
6.5 % |
7.5 % |
7.7 % |
6.6 % |
|||||||||
|
TOTI (% of Wellhead Revenue) (non-GAAP)1 |
6.8 % |
7.5 % |
(0.7 %) |
7.2 % |
7.5 % |
7.7 % |
6.6 % |
|||||||
|
Income Taxes |
||||||||||||||
|
Effective Rate |
23.0 % |
21.5 % |
1.5 % |
21.6 % |
21.7 % |
22.2 % |
21.6 % |
|||||||
|
Current Tax Expense ($MM) |
454 |
495 |
(41) |
240 |
341 |
312 |
352 |
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|
First Quarter and Full-Year 2025 Guidance7 |
|||||||||||||||||
|
(Unaudited) |
|||||||||||||||||
|
See “Endnotes” below for related discussion and definitions |
|||||||||||||||||
|
1Q 2025 |
1Q 2025 Midpoint |
FY 2025 |
FY 2025 Midpoint |
2024 Actual |
2023 Actual |
2022 Actual |
|||||||||||
|
Crude Oil and Condensate Volumes (MBod) |
|||||||||||||||||
|
United States |
495.0 – |
503.0 |
499.0 |
499.5 – |
507.5 |
503.5 |
490.6 |
475.2 |
460.7 |
||||||||
|
Trinidad |
0.8 – |
1.2 |
1.0 |
0.9 – |
1.3 |
1.1 |
0.8 |
0.6 |
0.6 |
||||||||
|
Total |
495.8 – |
504.2 |
500.0 |
500.4 – |
508.8 |
504.6 |
491.4 |
475.8 |
461.3 |
||||||||
|
Natural Gas Liquids Volumes (MBbld) |
|||||||||||||||||
|
Total |
233.0 – |
245.0 |
239.0 |
249.0 – |
261.0 |
255.0 |
245.9 |
223.8 |
197.7 |
||||||||
|
Natural Gas Volumes (MMcfd) |
|||||||||||||||||
|
United States |
1,740 – |
1,840 |
1,790 |
1,900 – |
2,000 |
1,950 |
1,728 |
1,551 |
1,315 |
||||||||
|
Trinidad |
225 – |
245 |
235 |
215 – |
235 |
225 |
220 |
160 |
180 |
||||||||
|
Total |
1,965 – |
2,085 |
2,025 |
2,115 – |
2,235 |
2,175 |
1,948 |
1,711 |
1,495 |
||||||||
|
Crude Oil Equivalent Volumes (MBoed) |
|||||||||||||||||
|
United States |
1,018.0 – |
1,054.7 |
1,036.4 |
1,065.2 – |
1,101.8 |
1,083.5 |
1,024.5 |
957.5 |
877.5 |
||||||||
|
Trinidad |
38.3 – |
42.0 |
40.2 |
36.7 – |
40.5 |
38.6 |
37.6 |
27.3 |
30.7 |
||||||||
|
Total |
1,056.3 – |
1,096.7 |
1,076.5 |
1,101.9 – |
1,142.3 |
1,122.1 |
1,062.1 |
984.8 |
908.2 |
||||||||
|
Benchmark Price |
|||||||||||||||||
|
Oil (WTI) ($/Bbl) |
75.72 |
77.61 |
94.23 |
||||||||||||||
|
Natural Gas (HH) ($/Mcf) |
2.27 |
2.74 |
6.64 |
||||||||||||||
|
Crude Oil and Condensate – above (below) WTI4 ($/Bbl) |
|||||||||||||||||
|
United States |
0.65 – |
2.15 |
1.40 |
0.20 – |
2.20 |
1.20 |
1.70 |
1.57 |
2.99 |
||||||||
|
Trinidad |
(12.95) – |
(11.45) |
(12.20) |
(8.10) – |
(6.10) |
(7.10) |
(11.29) |
(9.03) |
(8.07) |
||||||||
|
Natural Gas Liquids – Realizations as % of WTI |
|||||||||||||||||
|
Total |
30.0% – |
40.0 % |
35.0 % |
29.0% – |
39.0 % |
34.0 % |
30.9 % |
29.7 % |
39.0 % |
||||||||
|
Natural Gas – above (below) NYMEX Henry Hub5 ($/Mcf) |
|||||||||||||||||
|
United States |
(0.70) – |
0.00 |
(0.35) |
(1.35) – |
0.65 |
(0.35) |
(0.28) |
(0.04) |
0.63 |
||||||||
|
Natural Gas Realizations8 ($/Mcf) |
|||||||||||||||||
|
Trinidad |
3.25 – |
3.95 |
3.60 |
3.00 – |
4.00 |
3.50 |
3.65 |
3.65 |
4.43 |
||||||||
|
Total Expenditures (GAAP) ($MM) |
6,653 |
6,818 |
5,610 |
||||||||||||||
|
Capital Expenditures9 (non-GAAP) ($MM) |
1,475 – |
1,575 |
1,525 |
6,000 – |
6,400 |
6,200 |
6,226 |
6,041 |
4,607 |
||||||||
|
Operating Unit Costs ($/Boe) |
|||||||||||||||||
|
Lease and Well |
4.00 – |
4.50 |
4.25 |
3.90 – |
4.40 |
4.15 |
4.04 |
4.05 |
4.02 |
||||||||
|
Gathering, Processing and Transportation Costs3 |
4.30 – |
4.80 |
4.55 |
4.30 – |
4.80 |
4.55 |
4.43 |
4.50 |
4.78 |
||||||||
|
General and Administrative (GAAP) |
1.75 – |
2.05 |
1.90 |
1.65 – |
1.95 |
1.80 |
1.72 |
1.78 |
1.72 |
||||||||
|
General and Administrative (non-GAAP)1 |
1.70 |
1.78 |
1.67 |
||||||||||||||
|
Cash Operating Costs (GAAP) |
10.05 – |
11.35 |
10.70 |
9.85 – |
11.15 |
10.50 |
10.19 |
10.33 |
10.52 |
||||||||
|
Cash Operating Costs (non-GAAP)1 |
10.17 |
10.33 |
10.47 |
||||||||||||||
|
Depreciation, Depletion and Amortization |
10.00 – |
11.00 |
10.50 |
9.90 – |
10.90 |
10.40 |
10.57 |
9.72 |
10.69 |
||||||||
|
Expenses ($MM) |
|||||||||||||||||
|
Exploration and Dry Hole |
40 – |
80 |
60 |
210 – |
250 |
230 |
188 |
182 |
204 |
||||||||
|
Impairment (GAAP) |
391 |
202 |
382 |
||||||||||||||
|
Impairment (excluding certain impairments (non-GAAP))6 |
30 – |
110 |
70 |
240 – |
320 |
280 |
100 |
160 |
269 |
||||||||
|
Capitalized Interest |
10 – |
14 |
12 |
46 – |
50 |
48 |
45 |
33 |
36 |
||||||||
|
Net Interest |
46 – |
50 |
48 |
173 – |
177 |
175 |
138 |
148 |
179 |
||||||||
|
TOTI (% of Wellhead Revenue) (GAAP) |
7.0% – |
9.0 % |
8.0 % |
7.0% – |
9.0 % |
8.0 % |
7.1 % |
7.4 % |
7.0 % |
||||||||
|
TOTI (% of Wellhead Revenue) (non-GAAP)1 |
7.3 % |
7.4 % |
7.5 % |
||||||||||||||
|
Income Taxes |
|||||||||||||||||
|
Effective Rate |
20.0% – |
25.0 % |
22.5 % |
20.0% – |
25.0 % |
22.5 % |
22.1 % |
21.6 % |
21.7 % |
||||||||
|
Current Tax Expense ($MM) |
340 – |
440 |
390 |
1,350 – |
1,750 |
1,550 |
1,348 |
1,415 |
2,208 |
||||||||
Fourth Quarter and Full-Year 2024 Results Webcast
Friday, February 28, 2025, 9:00 a.m. Central time (10:00 a.m. Eastern time)
Webcast will be available on EOG’s website for one year.
http://investors.eogresources.com/Investors
About EOGEOG 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 ContactsPearce Hammond 713-571-4684
Neel Panchal 713-571-4884
Shelby O’Connor 713-571-4560
Media ContactKimberly Ehmer 713-571-4676
Endnotes
|
1) |
Cash Operating Costs consist of LOE, GP&T and G&A. TOTI (% of Wellhead Revenue) (non-GAAP) and G&A (non-GAAP) for each of 3Q 2024, fiscal year 2024 and fiscal year 2022 exclude a state severance tax refund and related consulting fees, respectively, as reflected in the accompanying reconciliation schedules (see “Revenues, Costs and Margins Per Barrel of Oil Equivalent”). The per-Boe impact of such consulting fees on G&A and total Cash Operating Costs for 3Q 2024, fiscal year 2024 and fiscal year 2022 was $(0.10), $(0.02) and $(0.05), respectively, as set forth in “Fourth Quarter 2024 Results vs Guidance” and “First Quarter and Full-Year 2025 Guidance” above. |
|
2) |
Includes gathering, processing and marketing revenue, gains (losses) on asset dispositions (for GAAP earnings per share only), other revenue, exploration, dry hole, impairments and marketing costs, taxes other than income, other income, interest expense and the impact of changes in the effective income tax rate. |
|
3) |
Effective January 1, 2024, EOG combined Transportation Costs and Gathering and Processing Costs into one line item titled Gathering, Processing and Transportation Costs. This presentation has been conformed for all periods presented and had no impact on previously reported Net Income. |
|
4) |
EOG bases United States and Trinidad crude oil and condensate price differentials upon the West Texas Intermediate crude oil price at Cushing, Oklahoma, using the simple average of the NYMEX settlement prices for each trading day within the applicable calendar month. |
|
5) |
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. |
|
6) |
In general, EOG excludes impairments which are (i) attributable to declines in commodity prices, (ii) related to sales of certain oil and gas properties or (iii) the result of certain other events or decisions (e.g., a periodic review of EOG’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). |
|
7) |
The forecast items for the first quarter and full year 2025 set forth above for EOG are based on currently available information and expectations as of the date of this press release. EOG undertakes no obligation, other than as required by applicable law, to update or revise this forecast, whether as a result of new information, subsequent events, anticipated or unanticipated circumstances or otherwise. This forecast, which should be read in conjunction with this press release and EOG’s related Current Report on Form 8-K filing, replaces and supersedes any previously issued guidance or forecast. |
|
8) |
The full-year 2022 realized natural gas price for Trinidad includes a one-time pricing adjustment of $0.76/Mcf for prior-period production following a contract amendment with the National Gas Company of Trinidad and Tobago Limited. |
|
9) |
The forecast includes expenditures for Exploration and Development Drilling, Facilities, Leasehold Acquisitions, Capitalized Interest, Dry Hole Costs and Other Property, Plant and Equipment. The forecast excludes Property Acquisitions, Asset Retirement Costs, Non-Cash Exchanges and Transactions and exploration costs incurred as operating expenses. |
|
Glossary |
|
|
Acq |
Acquisitions |
|
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 |
|
CFO |
Cash flow provided by operating activities before changes in working capital |
|
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 and statements regarding the plans and objectives of EOG’s management for future operations, are forward-looking statements. EOG typically uses words such as “expect,” “anticipate,” “estimate,” “project,” “strategy,” “intend,” “plan,” “target,” “aims,” “ambition,” “initiative,” “goal,” “may,” “will,” “focused on,” “should” and “believe” or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG’s future financial or operating results and returns or EOG’s ability to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control drilling, completion and operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, other environmental matters or safety matters, pay and/or increase regular and/or special dividends or repurchase shares are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that such assumptions are accurate or will prove to have been correct or that any of such expectations will be achieved (in full or at all) or will be achieved on the expected or anticipated timelines. Moreover, EOG’s forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG’s control. Important factors that could cause EOG’s actual results to differ materially from the expectations reflected in EOG’s forward-looking statements include, among others:
the timing, magnitude and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids (NGLs), natural gas and related commodities;
the extent to which EOG is successful in its efforts to acquire or discover additional reserves;
the extent to which EOG is successful in its efforts to (i) economically develop its acreage in, (ii) produce reserves and achieve anticipated production levels and rates of return from, (iii) decrease or otherwise control its drilling, completion and operating costs and capital expenditures related to, and (iv) maximize reserve recoveries from, its existing and future crude oil and natural gas exploration and development projects and associated potential and existing drilling locations;
the success of EOG’s cost-mitigation initiatives and actions in offsetting the impact of any inflationary or other pressures on EOG’s operating costs and capital expenditures;
the extent to which EOG is successful in its efforts to market its production of crude oil and condensate, NGLs and natural gas;
security threats, including cybersecurity threats and disruptions to our business and operations from breaches of our information technology systems, physical breaches of our facilities and other infrastructure or breaches of the information technology systems, facilities and infrastructure of third parties with which we transact business, and enhanced regulatory focus on the prevention of, and disclosure requirements relating to, cyber incidents;
the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, storage, transportation, refining, liquefaction and export facilities and equipment;
the availability, cost, terms and timing of issuance or execution of mineral licenses, concessions and leases and governmental and other permits and rights-of-way, and EOG’s ability to retain mineral licenses, concessions and leases;
the impact of, and changes in, government policies, laws and regulations, including climate change-related regulations, policies and initiatives (for example, with respect to air emissions); tax laws and regulations (including, but not limited to, carbon tax or other emissions-related legislation); environmental, health and safety laws and regulations relating to disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations affecting the leasing of acreage and permitting for oil and gas drilling and the calculation of royalty payments in respect of oil and gas production; laws and regulations imposing additional permitting and disclosure requirements, additional operating restrictions and conditions or restrictions on drilling and completion operations and on the transportation of crude oil, NGLs and natural gas; laws and regulations with respect to financial and other derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;
the impact of climate change-related legislation, policies and initiatives; climate change-related political, social and shareholder activism; and physical, transition and reputational risks and other potential developments related to climate change;
the extent to which EOG is able to successfully and economically develop, implement and carry out its emissions and other environmental or safety-related initiatives and achieve its related targets, goals, ambitions and initiatives;
EOG’s ability to effectively integrate acquired crude oil and natural gas properties into its operations, identify and resolve existing and potential issues with respect to such properties and accurately estimate reserves, production, drilling, completion and operating costs and capital expenditures with respect to such properties;
the extent to which EOG’s third-party-operated crude oil and natural gas properties are operated successfully, economically and in compliance with applicable laws and regulations;
competition in the oil and gas exploration and production industry for the acquisition of licenses, concessions, leases and properties;
the availability and cost of, and competition in the oil and gas exploration and production industry for, employees, labor and other personnel, facilities, equipment, materials (such as water, sand, fuel and tubulars) and services;
the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;
weather and natural disasters, including its impact on crude oil and natural gas demand, and related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, liquefaction, compression, storage, transportation, and export facilities;
the ability of EOG’s customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;
EOG’s ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;
the extent to which EOG is successful in its completion of planned asset dispositions;
the extent and effect of any hedging activities engaged in by EOG;
the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;
the economic and financial impact of epidemics, pandemics or other public health issues;
geopolitical factors and political conditions and developments around the world (such as the imposition of tariffs or trade or other economic sanctions, political instability and armed conflicts), including in the areas in which EOG operates;
the extent to 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, cash flow provided by operating activities before changes in working capital and return on capital employed, and certain related estimates regarding future performance, commodity prices and operating and financial results. Because we provide these measures on a forward-looking basis, we cannot reliably or reasonably predict certain of the necessary components of the most directly comparable forward-looking GAAP measures, such as future changes in working capital and future impairments. Accordingly, we are unable to present a quantitative reconciliation of such forward-looking, non-GAAP financial measures to the respective most directly comparable forward-looking GAAP financial measures without unreasonable efforts. The unavailable information could have a significant impact on our ultimate results. However, management believes these forward-looking, non-GAAP measures may be a useful tool for the investment community in comparing EOG’s forecasted financial performance to the forecasted financial performance of other companies in the industry. Any such forward-looking measures and estimates are intended to be illustrative only and are not intended to reflect the results that EOG will necessarily achieve for the period(s) presented; EOG’s actual results may differ materially from such measures and estimates.
Oil and Gas Reserves:The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose not only “proved” reserves (i.e., quantities of oil and gas that are estimated to be recoverable with a high degree of confidence), but also “probable” reserves (i.e., quantities of oil and gas that are as likely as not to be recovered) as well as “possible” reserves (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve or resource estimates provided in this press release or any accompanying disclosures that are not specifically designated as being estimates of proved reserves may include “potential” reserves, “resource potential” and/or other estimated reserves or estimated resources not necessarily calculated in accordance with, or contemplated by, the SEC’s latest reserve reporting guidelines. Investors are urged to consider closely the disclosure in EOG’s Annual Report on Form 10-K for the fiscal year ended December 31, 2024 (and any updates to such disclosure set forth in EOG’s subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K), available from EOG at P.O. Box 4362, Houston, Texas 77210-4362 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC’s website at www.sec.gov.
|
Table of Contents |
|
|
Fourth Quarter 2024 |
|
|
Supplemental Financial and Operating Data |
Page |
|
Income Statements |
15 |
|
Volumes and Prices |
17 |
|
Balance Sheets |
18 |
|
Cash Flow Statements |
19 |
|
Non-GAAP Financial Measures |
20 |
|
Adjusted Net Income |
21 |
|
Net Income Per Share |
28 |
|
Adjusted Net Income Per Share |
32 |
|
Cash Flow from Operations and Free Cash Flow |
36 |
|
Net Debt-to-Total Capitalization Ratio |
37 |
|
Proved Reserves and Reserve Replacement Data |
38 |
|
Reserve Replacement Cost Data |
39 |
|
Revenues, Costs and Margins Per Barrel of Oil Equivalent |
44 |
|
Income Statements |
||||||||||||
|
In millions of USD, except share data (in millions) and per share data (Unaudited) |
||||||||||||
|
2023 |
2024 |
|||||||||||
|
1st Qtr |
2nd Qtr |
3rd Qtr |
4th Qtr |
Year |
1st Qtr |
2nd Qtr |
3rd Qtr |
4th Qtr |
Year |
|||
|
Operating Revenues and Other |
||||||||||||
|
Crude Oil and Condensate |
3,182 |
3,252 |
3,717 |
3,597 |
13,748 |
3,480 |
3,692 |
3,488 |
3,261 |
13,921 |
||
|
Natural Gas Liquids |
490 |
409 |
501 |
484 |
1,884 |
513 |
515 |
524 |
554 |
2,106 |
||
|
Natural Gas |
517 |
334 |
417 |
476 |
1,744 |
382 |
303 |
372 |
494 |
1,551 |
||
|
Gains (Losses) on Mark-to-Market |
376 |
101 |
43 |
298 |
818 |
237 |
(47) |
79 |
(65) |
204 |
||
|
Gathering, Processing and Marketing |
1,390 |
1,465 |
1,478 |
1,473 |
5,806 |
1,459 |
1,519 |
1,481 |
1,341 |
5,800 |
||
|
Gains (Losses) on Asset Dispositions, |
69 |
(9) |
35 |
— |
95 |
26 |
20 |
(7) |
(23) |
16 |
||
|
Other, Net |
20 |
21 |
21 |
29 |
91 |
26 |
23 |
28 |
23 |
100 |
||
|
Total |
6,044 |
5,573 |
6,212 |
6,357 |
24,186 |
6,123 |
6,025 |
5,965 |
5,585 |
23,698 |
||
|
Operating Expenses |
||||||||||||
|
Lease and Well |
359 |
348 |
369 |
378 |
1,454 |
396 |
390 |
392 |
394 |
1,572 |
||
|
Gathering, Processing and |
395 |
396 |
406 |
423 |
1,620 |
413 |
423 |
445 |
441 |
1,722 |
||
|
Exploration Costs |
50 |
47 |
43 |
41 |
181 |
45 |
34 |
43 |
52 |
174 |
||
|
Dry Hole Costs |
1 |
— |
— |
— |
1 |
1 |
5 |
— |
8 |
14 |
||
|
Impairments |
34 |
35 |
54 |
79 |
202 |
19 |
81 |
15 |
276 |
391 |
||
|
Marketing Costs |
1,361 |
1,456 |
1,383 |
1,509 |
5,709 |
1,404 |
1,490 |
1,500 |
1,323 |
5,717 |
||
|
Depreciation, Depletion and |
798 |
866 |
898 |
930 |
3,492 |
1,074 |
984 |
1,031 |
1,019 |
4,108 |
||
|
General and Administrative |
145 |
142 |
161 |
192 |
640 |
162 |
151 |
167 |
189 |
669 |
||
|
Taxes Other Than Income |
329 |
313 |
341 |
301 |
1,284 |
338 |
337 |
283 |
291 |
1,249 |
||
|
Total |
3,472 |
3,603 |
3,655 |
3,853 |
14,583 |
3,852 |
3,895 |
3,876 |
3,993 |
15,616 |
||
|
Operating Income |
2,572 |
1,970 |
2,557 |
2,504 |
9,603 |
2,271 |
2,130 |
2,089 |
1,592 |
8,082 |
||
|
Other Income, Net |
65 |
51 |
52 |
66 |
234 |
62 |
66 |
76 |
70 |
274 |
||
|
Income Before Interest Expense and |
2,637 |
2,021 |
2,609 |
2,570 |
9,837 |
2,333 |
2,196 |
2,165 |
1,662 |
8,356 |
||
|
Interest Expense, Net |
42 |
35 |
36 |
35 |
148 |
33 |
36 |
31 |
38 |
138 |
||
|
Income Before Income Taxes |
2,595 |
1,986 |
2,573 |
2,535 |
9,689 |
2,300 |
2,160 |
2,134 |
1,624 |
8,218 |
||
|
Income Tax Provision |
572 |
433 |
543 |
547 |
2,095 |
511 |
470 |
461 |
373 |
1,815 |
||
|
Net Income |
2,023 |
1,553 |
2,030 |
1,988 |
7,594 |
1,789 |
1,690 |
1,673 |
1,251 |
6,403 |
||
|
Dividends Declared per Common Share |
1.8250 |
0.8250 |
0.8250 |
2.4100 |
5.8850 |
0.9100 |
0.9100 |
0.9100 |
0.9750 |
3.7050 |
||
|
Net Income Per Share |
||||||||||||
|
Basic |
3.46 |
2.68 |
3.51 |
3.43 |
13.07 |
3.11 |
2.97 |
2.97 |
2.25 |
11.31 |
||
|
Diluted |
3.45 |
2.66 |
3.48 |
3.42 |
13.00 |
3.10 |
2.95 |
2.95 |
2.23 |
11.25 |
||
|
Average Number of Common Shares |
||||||||||||
|
Basic |
584 |
580 |
579 |
579 |
581 |
575 |
569 |
564 |
557 |
566 |
||
|
Diluted |
587 |
584 |
583 |
581 |
584 |
577 |
572 |
568 |
561 |
569 |
||
|
(A) |
Effective January 1, 2024, EOG combined Transportation Costs and Gathering and Processing Costs into one line item titled Gathering, Processing and Transportation Costs. This presentation has been conformed for all periods presented and had no impact on previously reported Net Income. |
|
Volumes and Prices |
||||||||||||
|
(Unaudited) |
||||||||||||
|
2023 |
2024 |
|||||||||||
|
1st Qtr |
2nd Qtr |
3rd Qtr |
4th Qtr |
Year |
1st Qtr |
2nd Qtr |
3rd Qtr |
4th Qtr |
Year |
|||
|
Crude Oil and Condensate Volumes (MBbld) (A) |
||||||||||||
|
United States |
457.1 |
476.0 |
482.8 |
484.6 |
475.2 |
486.8 |
490.1 |
491.8 |
493.5 |
490.6 |
||
|
Trinidad |
0.6 |
0.6 |
0.5 |
0.6 |
0.6 |
0.6 |
0.6 |
1.2 |
1.1 |
0.8 |
||
|
Total |
457.7 |
476.6 |
483.3 |
485.2 |
475.8 |
487.4 |
490.7 |
493.0 |
494.6 |
491.4 |
||
|
Average Crude Oil and Condensate Prices ($/Bbl) (B) |
||||||||||||
|
United States |
$ 77.27 |
$ 74.98 |
$ 83.61 |
$ 80.61 |
$ 79.18 |
$ 78.46 |
$ 82.71 |
$ 76.95 |
$ 71.68 |
$ 77.42 |
||
|
Trinidad |
68.98 |
64.88 |
71.38 |
69.21 |
65.58 |
67.50 |
70.75 |
63.15 |
60.47 |
64.43 |
||
|
Composite |
77.26 |
74.97 |
83.60 |
80.60 |
79.17 |
78.45 |
82.69 |
76.92 |
71.66 |
77.40 |
||
|
Natural Gas Liquids Volumes (MBbld) (A) |
||||||||||||
|
United States |
212.2 |
215.7 |
231.1 |
235.8 |
223.8 |
231.7 |
244.8 |
254.3 |
252.5 |
245.9 |
||
|
Total |
212.2 |
215.7 |
231.1 |
235.8 |
223.8 |
231.7 |
244.8 |
254.3 |
252.5 |
245.9 |
||
|
Average Natural Gas Liquids Prices ($/Bbl) (B) |
||||||||||||
|
United States |
$ 25.67 |
$ 20.85 |
$ 23.56 |
$ 22.29 |
$ 23.07 |
$ 24.32 |
$ 23.11 |
$ 22.42 |
$ 23.85 |
$ 23.40 |
||
|
Composite |
25.67 |
20.85 |
23.56 |
22.29 |
23.07 |
24.32 |
23.11 |
22.42 |
23.85 |
23.40 |
||
|
Natural Gas Volumes (MMcfd) (A) |
||||||||||||
|
United States |
1,475 |
1,513 |
1,562 |
1,653 |
1,551 |
1,658 |
1,668 |
1,745 |
1,840 |
1,728 |
||
|
Trinidad |
164 |
155 |
142 |
178 |
160 |
200 |
204 |
225 |
252 |
220 |
||
|
Total |
1,639 |
1,668 |
1,704 |
1,831 |
1,711 |
1,858 |
1,872 |
1,970 |
2,092 |
1,948 |
||
|
Average Natural Gas Prices ($/Mcf) (B) |
||||||||||||
|
United States |
$ 3.47 |
$ 2.07 |
$ 2.59 |
$ 2.72 |
$ 2.70 |
$ 2.10 |
$ 1.57 |
$ 1.84 |
$ 2.39 |
$ 1.99 |
||
|
Trinidad |
3.87 |
3.45 |
3.41 |
3.81 |
3.65 |
3.54 |
3.48 |
3.68 |
3.86 |
3.65 |
||
|
Composite |
3.51 |
2.20 |
2.66 |
2.82 |
2.79 |
2.26 |
1.78 |
2.05 |
2.57 |
2.17 |
||
|
Crude Oil Equivalent Volumes (MBoed) (C) |
||||||||||||
|
United States |
915.0 |
943.8 |
974.2 |
995.8 |
957.5 |
994.7 |
1,013.0 |
1,037.1 |
1,052.7 |
1,024.5 |
||
|
Trinidad |
28.0 |
26.5 |
24.3 |
30.4 |
27.3 |
34.1 |
34.5 |
38.6 |
43.0 |
37.6 |
||
|
Total |
943.0 |
970.3 |
998.5 |
1,026.2 |
984.8 |
1,028.8 |
1,047.5 |
1,075.7 |
1,095.7 |
1,062.1 |
||
|
Total MMBoe (C) |
84.9 |
88.3 |
91.9 |
94.4 |
359.4 |
93.6 |
95.3 |
99.0 |
100.8 |
388.7 |
||
|
(A) |
Thousand barrels per day or million cubic feet per day, as applicable. |
|
(B) |
Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity and other derivative instruments (see Note 12 to the Consolidated Financial Statements in EOG’s Annual Report on Form 10-K for the year ended December 31, 2024). |
|
(C) |
Thousand barrels of oil equivalent per day or million barrels of oil equivalent, as applicable; includes crude oil and condensate, NGLs and natural gas. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas. MMBoe is calculated by multiplying the MBoed amount by the number of days in the period and then dividing that amount by one thousand. |
|
Balance Sheets |
||||||||||
|
In millions of USD (Unaudited) |
||||||||||
|
2023 |
2024 |
|||||||||
|
MAR |
JUN |
SEP |
DEC |
MAR |
JUN |
SEP |
DEC |
|||
|
Current Assets |
||||||||||
|
Cash and Cash Equivalents |
5,018 |
4,764 |
5,326 |
5,278 |
5,292 |
5,431 |
6,122 |
7,092 |
||
|
Accounts Receivable, Net |
2,455 |
2,263 |
2,927 |
2,716 |
2,688 |
2,657 |
2,545 |
2,650 |
||
|
Inventories |
1,131 |
1,355 |
1,379 |
1,275 |
1,154 |
1,069 |
1,038 |
985 |
||
|
Assets from Price Risk Management Activities |
— |
— |
— |
106 |
110 |
4 |
— |
— |
||
|
Other (A) |
580 |
524 |
626 |
560 |
684 |
642 |
460 |
503 |
||
|
Total |
9,184 |
8,906 |
10,258 |
9,935 |
9,928 |
9,803 |
10,165 |
11,230 |
||
|
Property, Plant and Equipment |
||||||||||
|
Oil and Gas Properties (Successful Efforts Method) |
67,907 |
69,178 |
70,730 |
72,090 |
73,356 |
74,615 |
75,887 |
77,091 |
||
|
Other Property, Plant and Equipment |
5,101 |
5,282 |
5,355 |
5,497 |
5,768 |
6,078 |
6,314 |
6,418 |
||
|
Total Property, Plant and Equipment |
73,008 |
74,460 |
76,085 |
77,587 |
79,124 |
80,693 |
82,201 |
83,509 |
||
|
Less: Accumulated Depreciation, Depletion and |
(42,785) |
(43,550) |
(44,362) |
(45,290) |
(46,047) |
(47,049) |
(48,075) |
(49,297) |
||
|
Total Property, Plant and Equipment, Net |
30,223 |
30,910 |
31,723 |
32,297 |
33,077 |
33,644 |
34,126 |
34,212 |
||
|
Deferred Income Taxes |
31 |
33 |
33 |
42 |
38 |
44 |
42 |
39 |
||
|
Other Assets |
1,587 |
1,638 |
1,633 |
1,583 |
1,753 |
1,733 |
1,818 |
1,705 |
||
|
Total Assets |
41,025 |
41,487 |
43,647 |
43,857 |
44,796 |
45,224 |
46,151 |
47,186 |
||
|
Current Liabilities |
||||||||||
|
Accounts Payable |
2,438 |
2,205 |
2,464 |
2,437 |
2,389 |
2,436 |
2,290 |
2,464 |
||
|
Accrued Taxes Payable |
637 |
425 |
605 |
466 |
786 |
600 |
855 |
1,007 |
||
|
Dividends Payable |
482 |
478 |
478 |
526 |
523 |
516 |
513 |
539 |
||
|
Liabilities from Price Risk Management Activities |
31 |
22 |
22 |
— |
— |
8 |
32 |
116 |
||
|
Current Portion of Long-Term Debt |
33 |
34 |
34 |
34 |
34 |
534 |
34 |
532 |
||
|
Current Portion of Operating Lease Liabilities |
354 |
335 |
337 |
325 |
318 |
303 |
338 |
315 |
||
|
Other |
253 |
232 |
285 |
286 |
223 |
231 |
344 |
381 |
||
|
Total |
4,228 |
3,731 |
4,225 |
4,074 |
4,273 |
4,628 |
4,406 |
5,354 |
||
|
Long-Term Debt |
3,787 |
3,780 |
3,772 |
3,765 |
3,757 |
3,250 |
3,742 |
4,220 |
||
|
Other Liabilities |
2,620 |
2,581 |
2,698 |
2,526 |
2,533 |
2,456 |
2,480 |
2,395 |
||
|
Deferred Income Taxes |
4,943 |
5,138 |
5,194 |
5,402 |
5,597 |
5,731 |
5,949 |
5,866 |
||
|
Commitments and Contingencies |
||||||||||
|
Stockholders’ Equity |
||||||||||
|
Common Stock, $0.01 Par |
206 |
206 |
206 |
206 |
206 |
206 |
206 |
206 |
||
|
Additional Paid in Capital |
6,219 |
6,257 |
6,133 |
6,166 |
6,188 |
6,219 |
6,058 |
6,090 |
||
|
Accumulated Other Comprehensive Loss |
(8) |
(9) |
(7) |
(9) |
(8) |
(8) |
(9) |
(4) |
||
|
Retained Earnings |
19,423 |
20,497 |
22,047 |
22,634 |
23,897 |
25,071 |
26,231 |
26,941 |
||
|
Common Stock Held in Treasury |
(393) |
(694) |
(621) |
(907) |
(1,647) |
(2,329) |
(2,912) |
(3,882) |
||
|
Total Stockholders’ Equity |
25,447 |
26,257 |
27,758 |
28,090 |
28,636 |
29,159 |
29,574 |
29,351 |
||
|
Total Liabilities and Stockholders’ Equity |
41,025 |
41,487 |
43,647 |
43,857 |
44,796 |
45,224 |
46,151 |
47,186 |
||
|
(A) |
Effective October 1, 2024, EOG combined Income Taxes Receivable into the Other line item. This presentation has been conformed for all periods presented and had no impact on previously reported Total Assets. |
|
Cash Flow Statements |
||||||||||||
|
In millions of USD (Unaudited) |
||||||||||||
|
2023 |
2024 |
|||||||||||
|
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 |
||||||||||||
|
Net Income |
2,023 |
1,553 |
2,030 |
1,988 |
7,594 |
1,789 |
1,690 |
1,673 |
1,251 |
6,403 |
||
|
Items Not Requiring (Providing) Cash |
||||||||||||
|
Depreciation, Depletion and Amortization |
798 |
866 |
898 |
930 |
3,492 |
1,074 |
984 |
1,031 |
1,019 |
4,108 |
||
|
Impairments |
34 |
35 |
54 |
79 |
202 |
19 |
81 |
15 |
276 |
391 |
||
|
Stock-Based Compensation Expenses |
34 |
35 |
57 |
51 |
177 |
45 |
45 |
58 |
51 |
199 |
||
|
Deferred Income Taxes |
234 |
194 |
56 |
199 |
683 |
199 |
128 |
220 |
(80) |
467 |
||
|
(Gains) Losses on Asset Dispositions, Net |
(69) |
9 |
(35) |
— |
(95) |
(26) |
(20) |
7 |
23 |
(16) |
||
|
Other, Net |
4 |
2 |
(1) |
22 |
27 |
9 |
3 |
2 |
3 |
17 |
||
|
Dry Hole Costs |
1 |
— |
— |
— |
1 |
1 |
5 |
— |
8 |
14 |
||
|
Mark-to-Market Financial Commodity and Other |
(376) |
(101) |
(43) |
(298) |
(818) |
(237) |
47 |
(79) |
65 |
(204) |
||
|
Net Cash Received from (Payments for) |
(123) |
(30) |
23 |
18 |
(112) |
55 |
79 |
61 |
19 |
214 |
||
|
Other, Net |
(1) |
— |
(1) |
— |
(2) |
— |
— |
— |
— |
— |
||
|
Changes in Components of Working Capital and |
||||||||||||
|
Accounts Receivable |
338 |
137 |
(714) |
201 |
(38) |
58 |
33 |
109 |
(99) |
101 |
||
|
Inventories |
(77) |
(226) |
(28) |
100 |
(231) |
117 |
75 |
30 |
37 |
259 |
||
|
Accounts Payable |
(77) |
(231) |
238 |
(49) |
(119) |
(58) |
29 |
(159) |
152 |
(36) |
||
|
Accrued Taxes Payable |
232 |
(212) |
180 |
(139) |
61 |
319 |
(185) |
256 |
151 |
541 |
||
|
Other Assets |
52 |
43 |
(92) |
36 |
39 |
(161) |
42 |
197 |
(34) |
44 |
||
|
Other Liabilities |
193 |
(47) |
54 |
(16) |
184 |
(71) |
(20) |
108 |
6 |
23 |
||
|
Changes in Components of Working Capital |
35 |
250 |
28 |
(18) |
295 |
(229) |
(127) |
59 |
(85) |
(382) |
||
|
Net Cash Provided by Operating Activities |
3,255 |
2,277 |
2,704 |
3,104 |
11,340 |
2,903 |
2,889 |
3,588 |
2,763 |
12,143 |
||
|
Investing Cash Flows |
||||||||||||
|
Additions to Oil and Gas Properties |
(1,305) |
(1,341) |
(1,379) |
(1,360) |
(5,385) |
(1,485) |
(1,357) |
(1,263) |
(1,248) |
(5,353) |
||
|
Additions to Other Property, Plant and Equipment |
(319) |
(180) |
(139) |
(162) |
(800) |
(350) |
(313) |
(239) |
(117) |
(1,019) |
||
|
Proceeds from Sales of Assets |
92 |
29 |
14 |
5 |
140 |
9 |
10 |
— |
4 |
23 |
||
|
Changes in Components of Working Capital |
(35) |
(250) |
(28) |
18 |
(295) |
229 |
127 |
(59) |
85 |
382 |
||
|
Net Cash Used in Investing Activities |
(1,567) |
(1,742) |
(1,532) |
(1,499) |
(6,340) |
(1,597) |
(1,533) |
(1,561) |
(1,276) |
(5,967) |
||
|
Financing Cash Flows |
||||||||||||
|
Long-Term Debt Borrowings |
— |
— |
— |
— |
— |
— |
— |
— |
985 |
985 |
||
|
Long-Term Debt Repayments |
(1,250) |
— |
— |
— |
(1,250) |
— |
— |
— |
— |
— |
||
|
Dividends Paid |
(1,067) |
(480) |
(494) |
(1,345) |
(3,386) |
(525) |
(520) |
(533) |
(509) |
(2,087) |
||
|
Treasury Stock Purchased |
(317) |
(302) |
(109) |
(310) |
(1,038) |
(759) |
(699) |
(795) |
(993) |
(3,246) |
||
|
Proceeds from Stock Options Exercised and |
— |
9 |
1 |
10 |
20 |
— |
11 |
— |
11 |
22 |
||
|
Debt Issuance Costs |
— |
(8) |
— |
— |
(8) |
— |
— |
— |
(2) |
(2) |
||
|
Repayment of Finance Lease Liabilities |
(8) |
(8) |
(8) |
(8) |
(32) |
(8) |
(9) |
(8) |
(8) |
(33) |
||
|
Net Cash Used in Financing Activities |
(2,642) |
(789) |
(610) |
(1,653) |
(5,694) |
(1,292) |
(1,217) |
(1,336) |
(516) |
(4,361) |
||
|
Effect of Exchange Rate Changes on Cash |
— |
— |
— |
— |
— |
— |
– |
– |
(1) |
(1) |
||
|
Increase (Decrease) in Cash and Cash Equivalents |
(954) |
(254) |
562 |
(48) |
(694) |
14 |
139 |
691 |
970 |
1,814 |
||
|
Cash and Cash Equivalents at Beginning of Period |
5,972 |
5,018 |
4,764 |
5,326 |
5,972 |
5,278 |
5,292 |
5,431 |
6,122 |
5,278 |
||
|
Cash and Cash Equivalents at End of Period |
5,018 |
4,764 |
5,326 |
5,278 |
5,278 |
5,292 |
5,431 |
6,122 |
7,092 |
7,092 |
||
|
Non-GAAP Financial Measures |
||
|
To supplement the presentation of its financial results prepared in accordance with generally accepted accounting principles in the United States of America (GAAP), EOG’s quarterly earnings releases and related conference calls, accompanying investor presentation slides and presentation slides for investor conferences contain certain financial measures that are not prepared or presented in accordance with GAAP. These non-GAAP financial measures may include, but are not limited to, Adjusted Net Income (Loss), Cash Flow from Operations Before Changes in Working Capital, Free Cash Flow, Net Debt and related statistics. |
||
|
A reconciliation of each of these measures to their most directly comparable GAAP financial measure and related discussion is included in the tables on the following pages and can also be found in the “Reconciliations & Guidance” section of the “Investors” page of the EOG website at www.eogresources.com. |
||
|
As further discussed in the tables on the following pages, EOG believes these measures may be useful to investors who follow the practice of some industry analysts who make certain adjustments to GAAP measures (for example, to exclude non-recurring items) to facilitate comparisons to others in EOG’s industry, and who utilize non-GAAP measures in their calculations of certain statistics (for example, return on capital employed and return on equity) used to evaluate EOG’s performance. |
||
|
EOG believes that the non-GAAP measures presented, when viewed in combination with its financial results prepared in accordance with GAAP, provide a more complete understanding of the factors and trends affecting the company’s performance. As is discussed in the tables on the following pages, EOG uses these non-GAAP measures for purposes of (i) comparing EOG’s financial performance with the financial performance of other companies in the industry and (ii) analyzing EOG’s financial performance across periods. |
||
|
The non-GAAP measures presented should not be considered in isolation, and should not be considered as a substitute for, or as an alternative to, EOG’s reported Net Income (Loss), Long-Term Debt (including Current Portion of Long-Term Debt), Net Cash Provided by Operating Activities and other financial results calculated in accordance with GAAP. The non-GAAP measures presented should be read in conjunction with EOG’s consolidated financial statements prepared in accordance with GAAP. |
||
|
In addition, because not all companies use identical calculations, EOG’s presentation of non-GAAP measures may not be comparable to, and may be calculated differently from, similarly titled measures disclosed by other companies, including its peer companies. EOG may also change the calculation of one or more of its non-GAAP measures from time to time – for example, to account for changes in its business and operations or to more closely conform to peer company or industry analysts’ practices. |
||
|
Direct ATROR |
||
|
The calculation of EOG’s direct after-tax rate of return (ATROR) is based on EOG’s net estimated recoverable reserves for a particular well(s) or play, the estimated net present value of the future net cash flows from such reserves (for which EOG utilizes certain assumptions regarding future commodity prices and operating costs) and EOG’s direct net costs incurred in drilling or acquiring such well(s). As such, EOG’s direct ATROR for a particular well(s) or play cannot be calculated from EOG’s consolidated financial statements. |
|
Adjusted Net 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)), and to make certain other adjustments to exclude non-recurring and certain other items as further described below. EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings to match hedge realizations to production settlement months and make certain other adjustments to exclude non-recurring and certain other items. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. |
||||||||
|
4Q 2024 |
||||||||
|
Before |
Income Tax |
After |
Diluted |
|||||
|
Reported Net Income (GAAP) |
1,624 |
(373) |
1,251 |
2.23 |
||||
|
Adjustments: |
||||||||
|
Losses on Mark-to-Market Financial Commodity and Other Derivative |
65 |
(14) |
51 |
0.10 |
||||
|
Net Cash Received from Settlements of Financial Commodity Derivative |
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 |
Income Tax |
After |
Diluted |
|||||
|
Reported Net Income (GAAP) |
2,134 |
(461) |
1,673 |
2.95 |
||||
|
Adjustments: |
||||||||
|
Gains on Mark-to-Market Financial Commodity and Other Derivative |
(79) |
17 |
(62) |
(0.11) |
||||
|
Net Cash Received from Settlements of Financial Commodity Derivative |
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) |
||||||||
|
2Q 2024 |
||||||||
|
Before |
Income Tax |
After |
Diluted |
|||||
|
Reported Net Income (GAAP) |
2,160 |
(470) |
1,690 |
2.95 |
||||
|
Adjustments: |
||||||||
|
Losses on Mark-to-Market Financial Commodity and Other Derivative |
47 |
(10) |
37 |
0.07 |
||||
|
Net Cash Received from Settlements of Financial Commodity Derivative |
79 |
(17) |
62 |
0.11 |
||||
|
Less: Gains on Asset Dispositions, Net |
(20) |
5 |
(15) |
(0.03) |
||||
|
Add: Certain Impairments |
35 |
(2) |
33 |
0.06 |
||||
|
Adjustments to Net Income |
141 |
(24) |
117 |
0.21 |
||||
|
Adjusted Net Income (Non-GAAP) |
2,301 |
(494) |
1,807 |
3.16 |
||||
|
Average Number of Common Shares |
||||||||
|
Basic |
569 |
|||||||
|
Diluted |
572 |
|||||||
|
(1) |
Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG adds to reported Net Income (GAAP) the total net cash received from settlements of financial commodity derivative contracts during such period. For the three months ended June 30, 2024, such amount was $79 million. |
|
Adjusted Net Income (Continued) |
||||||||
|
In millions of USD, except share data (in millions) and per share data (Unaudited) |
||||||||
|
1Q 2024 |
||||||||
|
Before |
Income Tax |
After |
Diluted |
|||||
|
Reported Net Income (GAAP) |
2,300 |
(511) |
1,789 |
3.10 |
||||
|
Adjustments: |
||||||||
|
Gains on Mark-to-Market Financial Commodity and Other Derivative |
(237) |
51 |
(186) |
(0.31) |
||||
|
Net Cash Received from Settlements of Financial Commodity Derivative |
55 |
(12) |
43 |
0.07 |
||||
|
Less: Gains on Asset Dispositions, Net |
(26) |
4 |
(22) |
(0.04) |
||||
|
Add: Certain Impairments |
2 |
— |
2 |
— |
||||
|
Adjustments to Net Income |
(206) |
43 |
(163) |
(0.28) |
||||
|
Adjusted Net Income (Non-GAAP) |
2,094 |
(468) |
1,626 |
2.82 |
||||
|
Average Number of Common Shares |
||||||||
|
Basic |
575 |
|||||||
|
Diluted |
577 |
|||||||
|
(1) |
Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG adds to reported Net Income (GAAP) the total net cash received from settlements of financial commodity derivative contracts during such period. For the three months ended March 31, 2024, such amount was $55 million. |
|
Adjusted Net Income (Continued) |
||||||||
|
In millions of USD, except share data (in millions) and per share data (Unaudited) |
||||||||
|
4Q 2023 |
||||||||
|
Before |
Income Tax |
After |
Diluted |
|||||
|
Reported Net Income (GAAP) |
2,535 |
(547) |
1,988 |
3.42 |
||||
|
Adjustments: |
||||||||
|
Gains on Mark-to-Market Financial Commodity Derivative |
(298) |
64 |
(234) |
(0.40) |
||||
|
Net Cash Received from Settlements of Financial Commodity Derivative |
18 |
(4) |
14 |
0.02 |
||||
|
Add: Certain Impairments |
19 |
(4) |
15 |
0.03 |
||||
|
Adjustments to Net Income |
(261) |
56 |
(205) |
(0.35) |
||||
|
Adjusted Net Income (Non-GAAP) |
2,274 |
(491) |
1,783 |
3.07 |
||||
|
Average Number of Common Shares |
||||||||
|
Basic |
579 |
|||||||
|
Diluted |
581 |
|||||||
|
(1) |
Consistent with its customary practice, in calculating Adjusted Net Income (non-GAAP), EOG adds to reported Net Income (GAAP) the total net cash received from settlements of financial commodity derivative contracts during such period. For the three months ended December 31, 2023, such amount was $18 million. |
|
Adjusted Net Income (Continued) |
||||||||
|
In millions of USD, except share data (in millions) and per share data (Unaudited) |
||||||||
|
FY 2024 |
||||||||
|
Before |
Income Tax |
After |
Diluted |
|||||
|
Reported Net Income (GAAP) |
8,218 |
(1,815) |
6,403 |
11.25 |
||||
|
Adjustments: |
||||||||
|
Gains on Mark-to-Market Financial Commodity and Other Derivative |
(204) |
44 |
(160) |
(0.28) |
||||
|
Net Cash Received from Settlements of Financial Commodity Derivative |
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 |
Income Tax |
After |
Diluted |
|||||
|
Reported Net Income (GAAP) |
9,689 |
(2,095) |
7,594 |
13.00 |
||||
|
Adjustments: |
||||||||
|
Gains on Mark-to-Market Financial Commodity Derivative |
(818) |
176 |
(642) |
(1.09) |
||||
|
Net Cash Payments for Settlements of Financial Commodity Derivative |
(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) |
||||
|
3Q 2024 Net Income per Share (GAAP) – Diluted |
2.95 |
|||
|
Realized Price |
||||
|
4Q 2024 Composite Average Wellhead Revenue per Boe |
42.74 |
|||
|
Less: 3Q 2024 Composite Average Wellhead Revenue per Boe |
(44.31) |
|||
|
Subtotal |
(1.57) |
|||
|
Multiplied by: 4Q 2024 Crude Oil Equivalent Volumes (MMBoe) |
100.8 |
|||
|
Total Change in Revenue |
(158) |
|||
|
Add: Income Tax Benefit (Provision) Imputed (based on 22%) |
35 |
|||
|
Change in Net Income |
(123) |
|||
|
Change in Diluted Earnings per Share |
(0.22) |
|||
|
Volumes |
||||
|
4Q 2024 Crude Oil Equivalent Volumes (MMBoe) |
100.8 |
|||
|
Less: 3Q 2024 Crude Oil Equivalent Volumes (MMBoe) |
(99.0) |
|||
|
Subtotal |
1.8 |
|||
|
Multiplied by: 4Q 2024 Composite Average Margin per Boe (GAAP) (Including Total |
15.88 |
|||
|
Change in Margin |
29 |
|||
|
Less: Income Tax Benefit (Provision) Imputed (based on 22%) |
(6) |
|||
|
Change in Net Income |
23 |
|||
|
Change in Diluted Earnings per Share |
0.04 |
|||
|
Certain Operating Costs per Boe |
||||
|
3Q 2024 Total Cash Operating Costs (GAAP) and Total DD&A per Boe |
20.57 |
|||
|
Less: 4Q 2024 Total Cash Operating Costs (GAAP) and Total DD&A per Boe |
(20.26) |
|||
|
Subtotal |
0.31 |
|||
|
Multiplied by: 4Q 2024 Crude Oil Equivalent Volumes (MMBoe) |
100.8 |
|||
|
Change in Before-Tax Net Income |
31 |
|||
|
Less: Income Tax Benefit (Provision) Imputed (based on 22%) |
(7) |
|||
|
Change in Net Income |
24 |
|||
|
Change in Diluted Earnings per Share |
0.04 |
|||
|
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 |
||||
|
4Q 2024 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts |
(65) |
|||
|
Less: Income Tax Benefit (Provision) |
14 |
|||
|
After Tax – (a) |
(51) |
|||
|
Less: 3Q 2024 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts |
79 |
|||
|
Less: Income Tax Benefit (Provision) |
(17) |
|||
|
After Tax – (b) |
62 |
|||
|
Change in Net Income – (a) – (b) |
(113) |
|||
|
Change in Diluted Earnings per Share |
(0.20) |
|||
|
Other (1) |
(0.38) |
|||
|
4Q 2024 Net Income per Share (GAAP) – Diluted |
2.23 |
|||
|
4Q 2024 Average Number of Common Shares – Diluted |
561 |
|||
|
(1) |
Includes gathering, processing and marketing revenue, gains (losses) on asset dispositions, other revenue, exploration, dry hole, impairments and marketing costs, taxes other than income, other income (expense), interest expense and the impact of changes in the effective income tax rate. |
|
Net Income per Share |
||||
|
In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited) |
||||
|
FY 2023 Net Income per Share (GAAP) |
13.00 |
|||
|
Realized Price |
||||
|
FY 2024 Composite Average Wellhead Revenue per Boe |
45.22 |
|||
|
Less: FY 2023 Composite Average Wellhead Revenue per Boe |
(48.34) |
|||
|
Subtotal |
(3.12) |
|||
|
Multiplied by: FY 2024 Crude Oil Equivalent Volumes (MMBoe) |
388.7 |
|||
|
Total Change in Revenue |
(1,213) |
|||
|
Add: Income Tax Benefit (Provision) Imputed (based on 22%) |
267 |
|||
|
Change in Net Income |
(946) |
|||
|
Change in Diluted Earnings per Share |
(1.66) |
|||
|
Volumes |
||||
|
FY 2024 Crude Oil Equivalent Volumes (MMBoe) |
388.7 |
|||
|
Less: FY 2023 Crude Oil Equivalent Volumes (MMBoe) |
(359.4) |
|||
|
Subtotal |
29.3 |
|||
|
Multiplied by: FY 2024 Composite Average Margin per Boe (GAAP) (Including Total |
19.40 |
|||
|
Change in Margin |
568 |
|||
|
Add: Income Tax Benefit (Provision) Imputed (based on 22%) |
(125) |
|||
|
Change in Net Income |
443 |
|||
|
Change in Diluted Earnings per Share |
0.78 |
|||
|
Certain Operating Costs per Boe |
||||
|
FY 2023 Total Cash Operating Costs (GAAP) and Total DD&A per Boe |
20.05 |
|||
|
Less: FY 2024 Total Cash Operating Costs (GAAP) and Total DD&A per Boe |
(20.76) |
|||
|
Subtotal |
(0.71) |
|||
|
Multiplied by: FY 2024 Crude Oil Equivalent Volumes (MMBoe) |
388.7 |
|||
|
Change in Before-Tax Net Income |
(276) |
|||
|
Add: Income Tax Benefit (Provision) Imputed (based on 22%) |
61 |
|||
|
Change in Net Income |
(215) |
|||
|
Change in Diluted Earnings per Share |
(0.38) |
|||
|
Net Income Per Share (Continued) |
||||
|
In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited) |
||||
|
Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative Contracts, Net |
||||
|
FY 2024 Net Gains (Losses) on Mark-to-Market Financial Commodity and Other Derivative |
204 |
|||
|
Less: Income Tax Benefit (Provision) |
(44) |
|||
|
After Tax – (a) |
160 |
|||
|
Less: FY 2023 Net Gains (Losses) on Mark-to-Market Commodity and Other Derivative Contracts |
818 |
|||
|
Less: Income Tax Benefit (Provision) |
(176) |
|||
|
After Tax – (b) |
642 |
|||
|
Change in Net Income – (a) – (b) |
(482) |
|||
|
Change in Diluted Earnings per Share |
(0.85) |
|||
|
Other (1) |
0.36 |
|||
|
FY 2024 Net Income per Share (GAAP) – Diluted |
11.25 |
|||
|
FY 2024 Average Number of Common Shares – Diluted |
569 |
|||
|
(1) |
Includes gathering, processing and marketing revenue, gains (losses) on asset dispositions, other revenue, exploration, dry hole, impairments and marketing costs, taxes other than income, other income (expense), interest expense and the impact of changes in the effective income tax rate. |
|
Adjusted Net Income Per Share |
||||
|
In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited) |
||||
|
3Q 2024 Adjusted Net Income per Share (Non-GAAP) – Diluted |
2.89 |
|||
|
Realized Price |
||||
|
4Q 2024 Composite Average Wellhead Revenue per Boe |
42.74 |
|||
|
Less: 3Q 2024 Composite Average Wellhead Revenue per Boe |
(44.31) |
|||
|
Subtotal |
(1.57) |
|||
|
Multiplied by: 4Q 2024 Crude Oil Equivalent Volumes (MMBoe) |
100.8 |
|||
|
Total Change in Revenue |
(158) |
|||
|
Add: Income Tax Benefit (Provision) Imputed (based on 22%) |
35 |
|||
|
Change in Net Income |
(123) |
|||
|
Change in Diluted Earnings per Share |
(0.22) |
|||
|
Volumes |
||||
|
4Q 2024 Crude Oil Equivalent Volumes (MMBoe) |
100.8 |
|||
|
Less: 3Q 2024 Crude Oil Equivalent Volumes (MMBoe) |
(99.0) |
|||
|
Subtotal |
1.8 |
|||
|
Multiplied by: 4Q 2024 Composite Average Margin per Boe (Non-GAAP) (Including Total |
18.40 |
|||
|
Change in Margin |
33 |
|||
|
Add: Income Tax Benefit (Provision) Imputed (based on 22%) |
(7) |
|||
|
Change in Net Income |
26 |
|||
|
Change in Diluted Earnings per Share |
0.05 |
|||
|
Certain Operating Costs per Boe |
||||
|
3Q 2024 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe |
20.47 |
|||
|
Less: 4Q 2024 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe |
(20.26) |
|||
|
Subtotal |
0.21 |
|||
|
Multiplied by: 4Q 2024 Crude Oil Equivalent Volumes (MMBoe) |
100.8 |
|||
|
Change in Before-Tax Net Income |
21 |
|||
|
Add: Income Tax Benefit (Provision) Imputed (based on 22%) |
(5) |
|||
|
Change in Net Income |
16 |
|||
|
Change in Diluted Earnings per Share |
0.03 |
|||
|
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 |
||||
|
4Q 2024 Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative |
19 |
|||
|
Less: Income Tax Benefit (Provision) |
(4) |
|||
|
After Tax – (a) |
15 |
|||
|
3Q 2024 Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative |
61 |
|||
|
Less: Income Tax Benefit (Provision) |
(13) |
|||
|
After Tax – (b) |
48 |
|||
|
Change in Net Income – (a) – (b) |
(33) |
|||
|
Change in Diluted Earnings per Share |
(0.06) |
|||
|
Other (1) |
0.05 |
|||
|
4Q 2024 Adjusted Net Income per Share (Non-GAAP) |
2.74 |
|||
|
4Q 2024 Average Number of Common Shares – Diluted |
561 |
|||
|
(1) |
Includes gathering, processing and marketing revenue, other revenue, exploration, dry hole, impairments and marketing costs, taxes other than income, other income (expense), interest expense and the impact of changes in the effective income tax rate. |
|
Adjusted Net Income per Share |
|||
|
In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited) |
|||
|
FY 2023 Adjusted Net Income per Share (Non-GAAP) |
11.69 |
||
|
Realized Price |
|||
|
FY 2024 Composite Average Wellhead Revenue per Boe |
45.22 |
||
|
Less: FY 2023 Composite Average Wellhead Revenue per Boe |
(48.34) |
||
|
Subtotal |
(3.12) |
||
|
Multiplied by: FY 2024 Crude Oil Equivalent Volumes (MMBoe) |
388.7 |
||
|
Total Change in Revenue |
(1,213) |
||
|
Add: Income Tax Benefit (Provision) Imputed (based on 22%) |
267 |
||
|
Change in Net Income |
(946) |
||
|
Change in Diluted Earnings per Share |
(1.66) |
||
|
Volumes |
|||
|
FY 2024 Crude Oil Equivalent Volumes (MMBoe) |
388.7 |
||
|
Less: FY 2023 Crude Oil Equivalent Volumes (MMBoe) |
(359.4) |
||
|
Subtotal |
29.3 |
||
|
Multiplied by: FY 2024 Composite Average Margin per Boe (Non-GAAP) |
20.09 |
||
|
Change in Margin |
589 |
||
|
Less: Income Tax Benefit (Provision) Imputed (based on 22%) |
(130) |
||
|
Change in Net Income |
459 |
||
|
Change in Diluted Earnings per Share |
0.81 |
||
|
Certain Operating Costs per Boe |
|||
|
FY 2023 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe |
20.05 |
||
|
Less: FY 2024 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe |
(20.74) |
||
|
Subtotal |
(0.69) |
||
|
Multiplied by: FY 2024 Crude Oil Equivalent Volumes (MMBoe) |
388.7 |
||
|
Change in Before-Tax Net Income |
(268) |
||
|
Add: Income Tax Benefit (Provision) Imputed (based on 22%) |
59 |
||
|
Change in Net Income |
(209) |
||
|
Change in Diluted Earnings per Share |
(0.37) |
||
|
Adjusted Net Income Per Share (Continued) |
|||
|
In millions of USD, except share data (in millions), per share data, production volume data and per Boe data (Unaudited) |
|||
|
Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts |
|||
|
FY 2024 Net Cash Received from (Payments for) Settlement of Financial Commodity Derivative Contracts |
214 |
||
|
Less: Income Tax Benefit (Provision) |
(46) |
||
|
After Tax – (a) |
168 |
||
|
FY 2023 Net Cash Received from (Payments for) Settlement of Financial Commodity Derivative Contracts |
(112) |
||
|
Less: Income Tax Benefit (Provision) |
24 |
||
|
After Tax – (b) |
(88) |
||
|
Change in Net Income – (a) – (b) |
256 |
||
|
Change in Diluted Earnings per Share |
0.45 |
||
|
Other (1) |
0.70 |
||
|
FY 2024 Adjusted Net Income per Share (Non-GAAP) |
11.62 |
||
|
FY 2024 Average Number of Common Shares (Non-GAAP) – Diluted |
569 |
||
|
(1) |
Includes gathering, processing and marketing revenue, other revenue, exploration, dry hole, impairments and marketing costs, taxes other than income, other income (expense), interest expense and the impact of changes in the effective income tax rate. |
|
Cash Flow from Operations and Free Cash Flow |
||||||||||||
|
In millions of USD (Unaudited) |
||||||||||||
|
The following tables reconcile Net Cash Provided by Operating Activities (GAAP) to Cash Flow from Operations Before Changes in Working Capital (Non-GAAP). EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust Net Cash Provided by Operating Activities for Changes in Components of Working Capital and Other Assets and Liabilities, Changes in Components of Working Capital Associated with Investing Activities and certain other adjustments to exclude non-recurring and certain other items as further described below. EOG defines Free Cash Flow (Non-GAAP) for a given period as Cash Flow from Operations Before Changes in Working Capital (Non-GAAP) (see below reconciliation) for such period less the Total Capital Expenditures (Non-GAAP) during such period, as is illustrated below. EOG management uses this information for comparative purposes within the industry. |
||||||||||||
|
2023 |
2024 |
|||||||||||
|
1st Qtr |
2nd Qtr |
3rd Qtr |
4th Qtr |
Year |
1st Qtr |
2nd Qtr |
3rd Qtr |
4th Qtr |
Year |
|||
|
Net Cash Provided by Operating Activities (GAAP) |
3,255 |
2,277 |
2,704 |
3,104 |
11,340 |
2,903 |
2,889 |
3,588 |
2,763 |
12,143 |
||
|
Adjustments: |
||||||||||||
|
Changes in Components of Working Capital and Other Assets and Liabilities |
||||||||||||
|
Accounts Receivable |
(338) |
(137) |
714 |
(201) |
38 |
(58) |
(33) |
(109) |
99 |
(101) |
||
|
Inventories |
77 |
226 |
28 |
(100) |
231 |
(117) |
(75) |
(30) |
(37) |
(259) |
||
|
Accounts Payable |
77 |
231 |
(238) |
49 |
119 |
58 |
(29) |
159 |
(152) |
36 |
||
|
Accrued Taxes Payable |
(232) |
212 |
(180) |
139 |
(61) |
(319) |
185 |
(256) |
(151) |
(541) |
||
|
Other Assets |
(52) |
(43) |
92 |
(36) |
(39) |
161 |
(42) |
(197) |
34 |
(44) |
||
|
Other Liabilities |
(193) |
47 |
(54) |
16 |
(184) |
71 |
20 |
(108) |
(6) |
(23) |
||
|
Changes in Components of Working Capital Associated with Investing Activities |
(35) |
(250) |
(28) |
18 |
(295) |
229 |
127 |
(59) |
85 |
382 |
||
|
Cash Flow from Operations Before Changes in Working Capital (Non-GAAP) |
2,559 |
2,563 |
3,038 |
2,989 |
11,149 |
2,928 |
3,042 |
2,988 |
2,635 |
11,593 |
||
|
Less: |
||||||||||||
|
Total Capital Expenditures (Non-GAAP) (a) |
(1,489) |
(1,521) |
(1,519) |
(1,512) |
(6,041) |
(1,703) |
(1,668) |
(1,497) |
(1,358) |
(6,226) |
||
|
Free Cash Flow (Non-GAAP) |
1,070 |
1,042 |
1,519 |
1,477 |
5,108 |
1,225 |
1,374 |
1,491 |
1,277 |
5,367 |
||
|
(a) See below reconciliation of Total Expenditures (GAAP) to Total Capital Expenditures (Non-GAAP): |
||||||||||||
|
2023 |
2024 |
|||||||||||
|
1st Qtr |
2nd Qtr |
3rd Qtr |
4th Qtr |
Year |
1st Qtr |
2nd Qtr |
3rd Qtr |
4th Qtr |
Year |
|||
|
Total Expenditures (GAAP) |
1,717 |
1,664 |
1,803 |
1,634 |
6,818 |
1,952 |
1,682 |
1,573 |
1,446 |
6,653 |
||
|
Less: |
||||||||||||
|
Asset Retirement Costs |
(10) |
(26) |
(191) |
(30) |
(257) |
(21) |
60 |
(11) |
(26) |
2 |
||
|
Non-Cash Development Drilling |
— |
(35) |
(50) |
(5) |
(90) |
— |
— |
— |
— |
— |
||
|
Non-Cash Acquisition Costs of |
(31) |
(28) |
(1) |
(39) |
(99) |
(31) |
(34) |
(17) |
(3) |
(85) |
||
|
Acquisition Costs of Proved Properties |
(4) |
(6) |
1 |
(7) |
(16) |
(21) |
(5) |
— |
(7) |
(33) |
||
|
Acquisition Costs of Other Property, |
(133) |
(1) |
— |
— |
(134) |
(131) |
(1) |
(5) |
— |
(137) |
||
|
Exploration Costs |
(50) |
(47) |
(43) |
(41) |
(181) |
(45) |
(34) |
(43) |
(52) |
(174) |
||
|
Total Capital Expenditures (Non-GAAP) |
1,489 |
1,521 |
1,519 |
1,512 |
6,041 |
1,703 |
1,668 |
1,497 |
1,358 |
6,226 |
||
|
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, |
September 30, |
June 30, |
March 31, |
December 31, |
||||||
|
Total Stockholders’ Equity – (a) |
29,351 |
29,574 |
29,159 |
28,636 |
28,090 |
|||||
|
Current and Long-Term Debt (GAAP) – (b) |
4,752 |
3,776 |
3,784 |
3,791 |
3,799 |
|||||
|
Less: Cash |
(7,092) |
(6,122) |
(5,431) |
(5,292) |
(5,278) |
|||||
|
Net Debt (Non-GAAP) – (c) |
(2,340) |
(2,346) |
(1,647) |
(1,501) |
(1,479) |
|||||
|
Total Capitalization (GAAP) – (a) + (b) |
34,103 |
33,350 |
32,943 |
32,427 |
31,889 |
|||||
|
Total Capitalization (Non-GAAP) – (a) + (c) |
27,011 |
27,228 |
27,512 |
27,135 |
26,611 |
|||||
|
Debt-to-Total Capitalization (GAAP) – (b) / [(a) + (b)] |
13.9 % |
11.3 % |
11.5 % |
11.7 % |
11.9 % |
|||||
|
Net Debt-to-Total Capitalization (Non-GAAP) – (c) / [(a) + (c)] |
-8.7 % |
-8.6 % |
-6.0 % |
-5.5 % |
-5.6 % |
|||||
|
Proved Reserves and Reserve Replacement Data |
||||||||
|
(Unaudited) |
||||||||
|
2024 Net Proved Reserves Reconciliation Summary |
United States |
Trinidad |
Other International |
Total |
||||
|
Crude Oil and Condensate (MMBbl) |
||||||||
|
Beginning Reserves |
1,754 |
2 |
— |
1,756 |
||||
|
Revisions |
71 |
— |
— |
71 |
||||
|
Purchases in Place |
3 |
— |
— |
3 |
||||
|
Extensions, Discoveries and Other Additions |
228 |
— |
— |
228 |
||||
|
Sales in Place |
(8) |
— |
— |
(8) |
||||
|
Production |
(180) |
— |
— |
(180) |
||||
|
Ending Reserves |
1,868 |
2 |
— |
1,870 |
||||
|
Natural Gas Liquids (MMBbl) |
||||||||
|
Beginning Reserves |
1,254 |
— |
— |
1,254 |
||||
|
Revisions |
31 |
— |
— |
31 |
||||
|
Purchases in Place |
2 |
— |
— |
2 |
||||
|
Extensions, Discoveries and Other Additions |
164 |
— |
— |
164 |
||||
|
Sales in Place |
(3) |
— |
— |
(3) |
||||
|
Production |
(90) |
— |
— |
(90) |
||||
|
Ending Reserves |
1,358 |
— |
— |
1,358 |
||||
|
Natural Gas (Bcf) |
||||||||
|
Beginning Reserves |
8,630 |
300 |
— |
8,930 |
||||
|
Revisions |
(202) |
2 |
— |
(200) |
||||
|
Purchases in Place |
10 |
— |
— |
10 |
||||
|
Extensions, Discoveries and Other Additions |
1,098 |
23 |
— |
1,121 |
||||
|
Sales in Place |
(14) |
— |
— |
(14) |
||||
|
Production |
(644) |
(81) |
— |
(725) |
||||
|
Ending Reserves |
8,878 |
244 |
— |
9,122 |
||||
|
Oil Equivalents (MMBoe) |
||||||||
|
Beginning Reserves |
4,447 |
51 |
— |
4,498 |
||||
|
Revisions |
68 |
1 |
— |
69 |
||||
|
Purchases in Place |
6 |
— |
— |
6 |
||||
|
Extensions, Discoveries and Other Additions |
576 |
4 |
— |
580 |
||||
|
Sales in Place |
(14) |
— |
— |
(14) |
||||
|
Production |
(377) |
(14) |
— |
(391) |
||||
|
Ending Reserves |
4,706 |
42 |
— |
4,748 |
||||
|
Net Proved Developed Reserves (MMBoe) |
||||||||
|
At December 31, 2023 |
2,322 |
27 |
— |
2,349 |
||||
|
At December 31, 2024 |
2,542 |
24 |
— |
2,566 |
||||
|
2024 Exploration and Development Expenditures ($ Millions) |
||||||||
|
Acquisition Cost of Unproved Properties |
229 |
— |
1 |
230 |
||||
|
Exploration Costs |
286 |
115 |
28 |
429 |
||||
|
Development Costs |
4,820 |
124 |
— |
4,944 |
||||
|
Total Drilling |
5,335 |
239 |
29 |
5,603 |
||||
|
Acquisition Cost of Proved Properties |
33 |
— |
— |
33 |
||||
|
Asset Retirement Costs |
(37) |
8 |
27 |
(2) |
||||
|
Total Exploration and Development Expenditures |
5,331 |
247 |
56 |
5,634 |
||||
|
Gathering, Processing and Other |
1,017 |
2 |
— |
1,019 |
||||
|
Total Expenditures |
6,348 |
249 |
56 |
6,653 |
||||
|
Proceeds from Sales in Place |
(23) |
— |
— |
(23) |
||||
|
Net Expenditures |
6,325 |
249 |
56 |
6,630 |
||||
|
Reserve Replacement Costs ($ / Boe) * |
||||||||
|
All-in Total, Net of Revisions |
7.85 |
47.00 |
— |
8.17 |
||||
|
All-in Total, Excluding Revisions Due to Price |
6.41 |
47.00 |
— |
6.68 |
||||
|
Reserve Replacement * |
||||||||
|
Drilling Only |
153 % |
29 % |
0 % |
148 % |
||||
|
All-in Total, Net of Revisions and Dispositions |
169 % |
36 % |
0 % |
164 % |
||||
|
All-in Total, Excluding Revisions Due to Price |
207 % |
36 % |
0 % |
201 % |
||||
|
All-in Total, Liquids |
181 % |
0 % |
0 % |
181 % |
||||
|
* See following reconciliation schedule for calculation methodology |
||||||||
|
Reserve Replacement Cost Data |
||||||||
|
(Unaudited; in millions, except ratio data) |
||||||||
|
For the Twelve Months Ended December 31, 2024 |
United States |
Trinidad |
Other International |
Total |
||||
|
Total Costs Incurred in Exploration and Development Activities (GAAP) |
5,331 |
247 |
56 |
5,634 |
||||
|
Less: Asset Retirement Costs |
37 |
(8) |
(27) |
2 |
||||
|
Non-Cash Acquisition Costs of Unproved Properties |
(85) |
— |
— |
(85) |
||||
|
Total Acquisition Costs of Proved Properties |
(33) |
— |
— |
(33) |
||||
|
Exploration Expenses |
(154) |
(4) |
(16) |
(174) |
||||
|
Total Exploration and Development Expenditures for Drilling Only (Non- |
5,096 |
235 |
13 |
5,344 |
||||
|
Total Costs Incurred in Exploration and Development Activities (GAAP) |
5,331 |
247 |
56 |
5,634 |
||||
|
Less: Asset Retirement Costs |
37 |
(8) |
(27) |
2 |
||||
|
Non-Cash Acquisition Costs of Unproved Properties |
(85) |
— |
— |
(85) |
||||
|
Non-Cash Acquisition Costs of Proved Properties |
(24) |
— |
— |
(24) |
||||
|
Exploration Expenses |
(154) |
(4) |
(16) |
(174) |
||||
|
Total Exploration and Development Expenditures (Non-GAAP) – (b) |
5,105 |
235 |
13 |
5,353 |
||||
|
Total Expenditures (GAAP) |
6,348 |
249 |
56 |
6,653 |
||||
|
Less: Asset Retirement Costs |
37 |
(8) |
(27) |
2 |
||||
|
Non-Cash Acquisition Costs of Unproved Properties |
(85) |
— |
— |
(85) |
||||
|
Non-Cash Acquisition Costs of Proved Properties |
(24) |
— |
— |
(24) |
||||
|
Exploration Expenses |
(154) |
(4) |
(16) |
(174) |
||||
|
Total Cash Expenditures (Non-GAAP) |
6,122 |
237 |
13 |
6,372 |
||||
|
Net Proved Reserve Additions From All Sources – Oil Equivalents (MMBoe) |
||||||||
|
Revisions Due to Price – (c) |
(146) |
— |
— |
(146) |
||||
|
Revisions Other Than Price |
214 |
1 |
— |
215 |
||||
|
Purchases in Place |
6 |
— |
— |
6 |
||||
|
Extensions, Discoveries and Other Additions – (d) |
576 |
4 |
— |
580 |
||||
|
Total Proved Reserve Additions – (e) |
650 |
5 |
— |
655 |
||||
|
Sales in Place |
(14) |
— |
— |
(14) |
||||
|
Net Proved Reserve Additions From All Sources – (f) |
636 |
5 |
— |
641 |
||||
|
Production – (g) |
377 |
14 |
— |
391 |
||||
|
Reserve Replacement Costs ($ / Boe) |
||||||||
|
Total Drilling, Before Revisions – (a / d) |
8.85 |
58.75 |
— |
9.21 |
||||
|
All-in Total, Net of Revisions – (b / e) |
7.85 |
47.00 |
— |
8.17 |
||||
|
All-in Total, Excluding Revisions Due to Price – (b / (e – c)) |
6.41 |
47.00 |
— |
6.68 |
||||
|
Reserve Replacement |
||||||||
|
Drilling Only – (d / g) |
153 % |
29 % |
0 % |
148 % |
||||
|
All-in Total, Net of Revisions and Dispositions – (f / g) |
169 % |
36 % |
0 % |
164 % |
||||
|
All-in Total, Excluding Revisions Due to Price – ((f – c) / g) |
207 % |
36 % |
0 % |
201 % |
||||
|
Reserve Replacement Cost Data (Continued) |
||||||||
|
(Unaudited; in millions, except ratio data) |
||||||||
|
For the Twelve Months Ended December 31, 2024 |
United States |
Trinidad |
Other International |
Total |
||||
|
Net Proved Reserve Additions From All Sources – Liquids (MMBbl) |
||||||||
|
Revisions |
102 |
— |
— |
102 |
||||
|
Purchases in Place |
5 |
— |
— |
5 |
||||
|
Extensions, Discoveries and Other Additions – (h) |
392 |
— |
— |
392 |
||||
|
Total Proved Reserve Additions |
499 |
— |
— |
499 |
||||
|
Sales in Place |
(11) |
— |
— |
(11) |
||||
|
Net Proved Reserve Additions From All Sources – (i) |
488 |
— |
— |
488 |
||||
|
Production – (j) |
270 |
— |
— |
270 |
||||
|
Reserve Replacement – Liquids |
||||||||
|
Drilling Only – (h / j) |
145 % |
0 % |
0 % |
145 % |
||||
|
All-in Total, Net of Revisions and Dispositions – (i / j) |
181 % |
0 % |
0 % |
181 % |
||||
|
Reserve Replacement Cost Data (Continued) |
||
|
(Unaudited; in millions, except ratio data) |
||
|
For the Twelve Months Ended December 31, 2024 |
||
|
Proved Developed Reserve Replacement Costs ($ / Boe) |
Total |
|
|
Total Costs Incurred in Exploration and Development Activities (GAAP) – (k) |
5,634 |
|
|
Less: Asset Retirement Costs |
2 |
|
|
Acquisition Costs of Unproved Properties |
(230) |
|
|
Acquisition Costs of Proved Properties |
(33) |
|
|
Exploration Expenses |
(174) |
|
|
Drillbit Exploration and Development Expenditures (Non-GAAP) – (l) |
5,199 |
|
|
Total Proved Reserves – Extensions, Discoveries and Other Additions (MMBoe) |
580 |
|
|
Add: Conversion of Proved Undeveloped Reserves to Proved Developed |
370 |
|
|
Less: Proved Undeveloped Extensions and Discoveries |
(479) |
|
|
Proved Developed Reserves – Extensions and Discoveries (MMBoe) |
471 |
|
|
Total Proved Reserves – Revisions (MMBoe) |
69 |
|
|
Less: Proved Undeveloped Reserves – Revisions |
66 |
|
|
Proved Developed – Revisions Due to Price |
41 |
|
|
Proved Developed Reserves – Revisions Other Than Price (MMBoe) |
176 |
|
|
Proved Developed Reserves – Extensions and Discoveries Plus Revisions Other Than Price (MMBoe) – (m) |
647 |
|
|
Proved Developed Reserve Replacement Costs Excluding Revisions Due to Price ($ / Boe) (GAAP) – (k / m) |
8.71 |
|
|
Proved Developed Reserve Replacement Costs Excluding Revisions Due to Price ($ / Boe) (Non-GAAP) – (l / m) |
8.04 |
|
Reserve Replacement Cost Data |
||||||||
|
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. |
||||||||
|
2024 |
2023 |
2022 |
2021 |
|||||
|
Total Costs Incurred in Exploration and Development Activities (GAAP) |
5,634 |
6,018 |
5,229 |
3,969 |
||||
|
Less: Asset Retirement Costs |
2 |
(257) |
(298) |
(127) |
||||
|
Non-Cash Acquisition Costs of Unproved Properties |
(85) |
(99) |
(127) |
(45) |
||||
|
Total Acquisition Costs of Proved Properties |
(33) |
(16) |
(419) |
(100) |
||||
|
Non-Cash Development Drilling |
— |
(90) |
— |
— |
||||
|
Exploration Expenses |
(174) |
(181) |
(159) |
(154) |
||||
|
Total Exploration and Development Expenditures for Drilling Only (Non- |
5,344 |
5,375 |
4,226 |
3,543 |
||||
|
Total Costs Incurred in Exploration and Development Activities (GAAP) – (b) |
5,634 |
6,018 |
5,229 |
3,969 |
||||
|
Less: Asset Retirement Costs |
2 |
(257) |
(298) |
(127) |
||||
|
Non-Cash Acquisition Costs of Unproved Properties |
(85) |
(99) |
(127) |
(45) |
||||
|
Non-Cash Acquisition Costs of Proved Properties |
(24) |
(6) |
(26) |
(5) |
||||
|
Non-Cash Development Drilling |
— |
(90) |
— |
— |
||||
|
Exploration Expenses |
(174) |
(181) |
(159) |
(154) |
||||
|
Total Exploration and Development Expenditures (Non-GAAP) – (c) |
5,353 |
5,385 |
4,619 |
3,638 |
||||
|
Net Proved Reserve Additions From All Sources – Oil Equivalents (MMBoe) |
||||||||
|
Revisions Due to Price – (d) |
(146) |
(110) |
11 |
194 |
||||
|
Revisions Other Than Price |
215 |
139 |
325 |
(308) |
||||
|
Purchases in Place |
6 |
2 |
16 |
9 |
||||
|
Extensions, Discoveries and Other Additions – (e) |
580 |
607 |
560 |
952 |
||||
|
Total Proved Reserve Additions – (f) |
655 |
638 |
912 |
847 |
||||
|
Sales in Place |
(14) |
(17) |
(88) |
(11) |
||||
|
Net Proved Reserve Additions From All Sources |
641 |
621 |
824 |
836 |
||||
|
Production |
391 |
361 |
333 |
309 |
||||
|
Reserve Replacement Costs ($ / Boe) |
||||||||
|
Total Drilling, Before Revisions – (a / e) |
9.21 |
8.86 |
7.55 |
3.72 |
||||
|
All-in Total, Net of Revisions – (c / f) |
8.17 |
8.44 |
5.06 |
4.30 |
||||
|
All-in Total, Excluding Revisions Due to Price (GAAP) – (b / ( f – d)) |
7.03 |
8.05 |
5.80 |
6.08 |
||||
|
All-in Total, Excluding Revisions Due to Price (Non-GAAP) – (c / ( f – d)) |
6.68 |
7.20 |
5.13 |
5.57 |
||||
|
Reserve Replacement Cost Data (Continued) |
||||||
|
In millions of USD, except reserves and ratio data (Unaudited) |
||||||
|
2020 |
2019 |
2018 |
||||
|
Total Costs Incurred in Exploration and Development Activities (GAAP) |
3,718 |
6,628 |
6,420 |
|||
|
Less: Asset Retirement Costs |
(117) |
(186) |
(70) |
|||
|
Non-Cash Acquisition Costs of Unproved Properties |
(197) |
(98) |
(291) |
|||
|
Total Acquisition Costs of Proved Properties |
(135) |
(380) |
(124) |
|||
|
Exploration Expenses |
(146) |
(140) |
(149) |
|||
|
Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) – (a) |
3,123 |
5,824 |
5,786 |
|||
|
Total Costs Incurred in Exploration and Development Activities (GAAP) – (b) |
3,718 |
6,628 |
6,420 |
|||
|
Less: Asset Retirement Costs |
(117) |
(186) |
(70) |
|||
|
Non-Cash Acquisition Costs of Unproved Properties |
(197) |
(98) |
(291) |
|||
|
Non-Cash Acquisition Costs of Proved Properties |
(15) |
(52) |
(71) |
|||
|
Exploration Expenses |
(146) |
(140) |
(149) |
|||
|
Total Exploration and Development Expenditures (Non-GAAP) – (c) |
3,243 |
6,152 |
5,839 |
|||
|
Net Proved Reserve Additions From All Sources – Oil Equivalents (MMBoe) |
||||||
|
Revisions Due to Price – (d) |
(278) |
(60) |
35 |
|||
|
Revisions Other Than Price |
(89) |
— |
(40) |
|||
|
Purchases in Place |
10 |
17 |
12 |
|||
|
Extensions, Discoveries and Other Additions – (e) |
564 |
750 |
670 |
|||
|
Total Proved Reserve Additions – (f) |
207 |
707 |
677 |
|||
|
Sales in Place |
(31) |
(5) |
(11) |
|||
|
Net Proved Reserve Additions From All Sources |
176 |
702 |
666 |
|||
|
Production |
285 |
301 |
265 |
|||
|
Reserve Replacement Costs ($ / Boe) |
||||||
|
Total Drilling, Before Revisions – (a / e) |
5.54 |
7.77 |
8.64 |
|||
|
All-in Total, Net of Revisions – (c / f) |
15.67 |
8.70 |
8.62 |
|||
|
All-in Total, Excluding Revisions Due to Price (GAAP) – (b / ( f – d)) |
7.67 |
8.64 |
10.00 |
|||
|
All-in Total, Excluding Revisions Due to Price (Non-GAAP) – (c / ( f – d)) |
6.69 |
8.02 |
9.10 |
|||
|
Definitions |
|
|
$/Boe |
U.S. Dollars per barrel of oil equivalent |
|
MMBoe |
Million barrels of oil equivalent |
|
Revenues, Costs and Margins Per Barrel of Oil Equivalent |
||||||||||
|
In millions of USD, except Boe and per Boe amounts (Unaudited) |
||||||||||
|
EOG believes this presentation may be useful to investors who follow the practice of some industry analysts who review certain components and/or groups of components of revenues, costs and/or margins per barrel of oil equivalent (Boe). Certain of these components are adjusted for non-recurring and certain other items, as further discussed below. EOG management uses this information for purposes of comparing its financial performance with the financial performance of other companies in the industry. |
||||||||||
|
4Q 2024 |
3Q 2024 |
2Q 2024 |
1Q 2024 |
4Q 2023 |
||||||
|
Volume – Million Barrels of Oil Equivalent – (a) |
100.8 |
99.0 |
95.3 |
93.6 |
94.4 |
|||||
|
Total Operating Revenues and Other (b) |
5,585 |
5,965 |
6,025 |
6,123 |
6,357 |
|||||
|
Total Operating Expenses (c) |
3,993 |
3,876 |
3,895 |
3,852 |
3,853 |
|||||
|
Operating Income (d) |
1,592 |
2,089 |
2,130 |
2,271 |
2,504 |
|||||
|
Wellhead Revenues |
||||||||||
|
Crude Oil and Condensate |
3,261 |
3,488 |
3,692 |
3,480 |
3,597 |
|||||
|
Natural Gas Liquids |
554 |
524 |
515 |
513 |
484 |
|||||
|
Natural Gas |
494 |
372 |
303 |
382 |
476 |
|||||
|
Total Wellhead Revenues – (e) |
4,309 |
4,384 |
4,510 |
4,375 |
4,557 |
|||||
|
Operating Costs |
||||||||||
|
Lease and Well |
394 |
392 |
390 |
396 |
378 |
|||||
|
Gathering, Processing and Transportation Costs (1) |
441 |
445 |
423 |
413 |
423 |
|||||
|
General and Administrative (GAAP) |
189 |
167 |
151 |
162 |
192 |
|||||
|
Less: Severance Tax Consulting Fees |
— |
(10) |
— |
— |
— |
|||||
|
General and Administrative (Non-GAAP) (3) |
189 |
157 |
151 |
162 |
192 |
|||||
|
Taxes Other Than Income (GAAP) |
291 |
283 |
337 |
338 |
301 |
|||||
|
Add: Severance Tax Refund |
— |
31 |
— |
— |
— |
|||||
|
Taxes Other Than Income (Non-GAAP) (4) |
291 |
314 |
337 |
338 |
301 |
|||||
|
Interest Expense, Net |
38 |
31 |
36 |
33 |
35 |
|||||
|
Total Operating Cost (GAAP) (excluding DD&A and Total Exploration |
1,353 |
1,318 |
1,337 |
1,342 |
1,329 |
|||||
|
Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration |
1,353 |
1,339 |
1,337 |
1,342 |
1,329 |
|||||
|
Depreciation, Depletion and Amortization (DD&A) |
1,019 |
1,031 |
984 |
1,074 |
930 |
|||||
|
Total Operating Cost (GAAP) (excluding Total Exploration Costs) – (h) |
2,372 |
2,349 |
2,321 |
2,416 |
2,259 |
|||||
|
Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) – (i) |
2,372 |
2,370 |
2,321 |
2,416 |
2,259 |
|||||
|
Exploration Costs |
52 |
43 |
34 |
45 |
41 |
|||||
|
Dry Hole Costs |
8 |
— |
5 |
1 |
— |
|||||
|
Impairments |
276 |
15 |
81 |
19 |
79 |
|||||
|
Total Exploration Costs (GAAP) |
336 |
58 |
120 |
65 |
120 |
|||||
|
Less: Certain Impairments (2) |
(254) |
— |
(35) |
(2) |
(19) |
|||||
|
Total Exploration Costs (Non-GAAP) |
82 |
58 |
85 |
63 |
101 |
|||||
|
Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) – |
2,708 |
2,407 |
2,441 |
2,481 |
2,379 |
|||||
|
Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non- |
2,454 |
2,428 |
2,406 |
2,479 |
2,360 |
|||||
|
Total Wellhead Revenues less Total Operating Cost (GAAP) (including Total |
1,601 |
1,977 |
2,069 |
1,894 |
2,178 |
|||||
|
Total Wellhead Revenues less Total Operating Cost (Non-GAAP) (including Total |
1,855 |
1,956 |
2,104 |
1,896 |
2,197 |
|||||
|
Revenues, Costs and Margins Per Barrel of Oil Equivalent (Continued) |
||||||||||
|
In millions of USD, except Boe and per Boe amounts (Unaudited) |
||||||||||
|
4Q 2024 |
3Q 2024 |
2Q 2024 |
1Q 2024 |
4Q 2023 |
||||||
|
Per Barrel of Oil Equivalent (Boe) Calculations (GAAP) |
||||||||||
|
Composite Average Operating Revenues and Other per Boe – (b) / (a) |
55.41 |
60.25 |
63.22 |
65.42 |
67.34 |
|||||
|
Composite Average Operating Expenses per Boe – (c) / (a) |
39.62 |
39.15 |
40.87 |
41.16 |
40.81 |
|||||
|
Composite Average Operating Income per Boe – (d) / (a) |
15.79 |
21.10 |
22.35 |
24.26 |
26.53 |
|||||
|
Composite Average Wellhead Revenue per Boe – (e) / (a) |
42.74 |
44.31 |
47.31 |
46.73 |
48.27 |
|||||
|
Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) – (f) / (a) |
13.42 |
13.32 |
14.03 |
14.33 |
14.08 |
|||||
|
Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) – [(e) / (a) – (f) / (a)] |
29.32 |
30.99 |
33.28 |
32.40 |
34.19 |
|||||
|
Total Operating Cost per Boe (excluding Total Exploration Costs) – (h) / (a) |
23.53 |
23.74 |
24.35 |
25.80 |
23.93 |
|||||
|
Composite Average Margin per Boe (excluding Total Exploration Costs) – [(e) / (a) – (h) / (a)] |
19.21 |
20.57 |
22.96 |
20.93 |
24.34 |
|||||
|
Total Operating Cost per Boe (including Total Exploration Costs) – (j) / (a) |
26.86 |
24.33 |
25.61 |
26.49 |
25.20 |
|||||
|
Composite Average Margin per Boe (including Total Exploration Costs) – [(e) / (a) – (j) / (a)] |
15.88 |
19.98 |
21.70 |
20.24 |
23.07 |
|||||
|
Per Barrel of Oil Equivalent (Boe) Calculations (Non-GAAP) |
||||||||||
|
Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) – (g) / (a) |
13.42 |
13.53 |
14.03 |
14.33 |
14.08 |
|||||
|
Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) – [(e) / (a) – (g) / (a)] |
29.32 |
30.78 |
33.28 |
32.40 |
34.19 |
|||||
|
Total Operating Cost per Boe (excluding Total Exploration Costs) – (i) / (a) |
23.53 |
23.95 |
24.35 |
25.80 |
23.93 |
|||||
|
Composite Average Margin per Boe (excluding Total Exploration Costs) – [(e) / (a) – (i) / (a)] |
19.21 |
20.36 |
22.96 |
20.93 |
24.34 |
|||||
|
Total Operating Cost per Boe (including Total Exploration Costs) – (k) / (a) |
24.34 |
24.54 |
25.24 |
26.47 |
25.00 |
|||||
|
Composite Average Margin per Boe (including Total Exploration Costs) – [(e) / (a) – (k) / (a)] |
18.40 |
19.77 |
22.07 |
20.26 |
23.27 |
|||||
|
Revenues, Costs and Margins Per Barrel of Oil Equivalent (Continued) |
||||||||||
|
In millions of USD, except Boe and per Boe amounts (Unaudited) |
||||||||||
|
2024 |
2023 |
2022 |
2021 |
|||||||
|
Volume – Million Barrels of Oil Equivalent – (a) |
388.7 |
359.4 |
331.5 |
302.5 |
||||||
|
Total Operating Revenues and Other (b) |
23,698 |
24,186 |
25,702 |
18,642 |
||||||
|
Total Operating Expenses (c) |
15,616 |
14,583 |
15,736 |
12,540 |
||||||
|
Operating Income (Loss) (d) |
8,082 |
9,603 |
9,966 |
6,102 |
||||||
|
Wellhead Revenues |
||||||||||
|
Crude Oil and Condensate |
13,921 |
13,748 |
16,367 |
11,125 |
||||||
|
Natural Gas Liquids |
2,106 |
1,884 |
2,648 |
1,812 |
||||||
|
Natural Gas |
1,551 |
1,744 |
3,781 |
2,444 |
||||||
|
Total Wellhead Revenues – (e) |
17,578 |
17,376 |
22,796 |
15,381 |
||||||
|
Operating Costs |
||||||||||
|
Lease and Well |
1,572 |
1,454 |
1,331 |
1,135 |
||||||
|
Gathering, Processing and Transportation Costs (1) |
1,722 |
1,620 |
1,587 |
1,422 |
||||||
|
General and Administrative (GAAP) |
669 |
640 |
570 |
511 |
||||||
|
Less: Severance Tax Consulting Fees |
(10) |
— |
(16) |
— |
||||||
|
General and Administrative (Non-GAAP) (3) |
659 |
640 |
554 |
511 |
||||||
|
Taxes Other Than Income (GAAP) |
1,249 |
1,284 |
1,585 |
1,047 |
||||||
|
Add: Severance Tax Refund |
31 |
— |
115 |
— |
||||||
|
Taxes Other Than Income (Non-GAAP) (4) |
1,280 |
1,284 |
1,700 |
1,047 |
||||||
|
Interest Expense, Net |
138 |
148 |
179 |
178 |
||||||
|
Total Operating Cost (GAAP) (excluding DD&A and Total Exploration Costs) – (f) |
5,350 |
5,146 |
5,252 |
4,293 |
||||||
|
Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration Costs) – (g) |
5,371 |
5,146 |
5,351 |
4,293 |
||||||
|
Depreciation, Depletion and Amortization (DD&A) |
4,108 |
3,492 |
3,542 |
3,651 |
||||||
|
Total Operating Cost (GAAP) (excluding Total Exploration Costs) – (h) |
9,458 |
8,638 |
8,794 |
7,944 |
||||||
|
Total Operating Cost (Non-GAAP) (excluding Total Exploration Costs) – (i) |
9,479 |
8,638 |
8,893 |
7,944 |
||||||
|
Exploration Costs |
174 |
181 |
159 |
154 |
||||||
|
Dry Hole Costs |
14 |
1 |
45 |
71 |
||||||
|
Impairments |
391 |
202 |
382 |
376 |
||||||
|
Total Exploration Costs (GAAP) |
579 |
384 |
586 |
601 |
||||||
|
Less: Certain Impairments (2) |
(291) |
(42) |
(113) |
(15) |
||||||
|
Total Exploration Costs (Non-GAAP) |
288 |
342 |
473 |
586 |
||||||
|
Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) – (j) |
10,037 |
9,022 |
9,380 |
8,545 |
||||||
|
Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non-GAAP)) – (k) |
9,767 |
8,980 |
9,366 |
8,530 |
||||||
|
Total Wellhead Revenues less Total Operating Cost (GAAP) (including Total Exploration Costs (GAAP)) |
7,541 |
8,354 |
13,416 |
6,836 |
||||||
|
Total Wellhead Revenues less Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non-GAAP)) |
7,811 |
8,396 |
13,430 |
6,851 |
||||||
|
Revenues, Costs and Margins Per Barrel of Oil Equivalent (Continued) |
||||||||||
|
In millions of USD, except Boe and per Boe amounts (Unaudited) |
||||||||||
|
2024 |
2023 |
2022 |
2021 |
|||||||
|
Per Barrel of Oil Equivalent (Boe) Calculations (GAAP) |
||||||||||
|
Composite Average Operating Revenues and Other per Boe – (b) / (a) |
60.97 |
67.30 |
77.53 |
61.63 |
||||||
|
Composite Average Operating Expenses per Boe – (c) / (a) |
40.18 |
40.58 |
47.47 |
41.46 |
||||||
|
Composite Average Operating Income (Loss) per Boe – (d) / (a) |
20.79 |
26.72 |
30.06 |
20.17 |
||||||
|
Composite Average Wellhead Revenue per Boe – (e) / (a) |
45.22 |
48.34 |
68.77 |
50.84 |
||||||
|
Total Operating Cost per Boe (excluding DD&A and Total Exploration Costs) – (f) / (a) |
13.76 |
14.31 |
15.84 |
14.19 |
||||||
|
Composite Average Margin per Boe (excluding DD&A and Total Exploration |
31.46 |
34.03 |
52.93 |
36.65 |
||||||
|
Total Operating Cost per Boe (excluding Total Exploration Costs) – (h) / (a) |
24.33 |
24.03 |
26.53 |
26.26 |
||||||
|
Composite Average Margin per Boe (excluding Total Exploration Costs) – |
20.89 |
24.31 |
42.24 |
24.58 |
||||||
|
Total Operating Cost per Boe (including Total Exploration Costs) – (j) / (a) |
25.82 |
25.10 |
28.30 |
28.25 |
||||||
|
Composite Average Margin per Boe (including Total Exploration Costs) – [(e) / |
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) |
13.82 |
14.31 |
16.14 |
14.19 |
||||||
|
Composite Average Margin per Boe (excluding DD&A and Total Exploration Costs) – [(e) / (a) – |
31.40 |
34.03 |
52.63 |
36.65 |
||||||
|
Total Operating Cost per Boe (excluding Total Exploration Costs) – (i) / (a) |
24.39 |
24.03 |
26.83 |
26.26 |
||||||
|
Composite Average Margin per Boe (excluding Total Exploration Costs) – |
20.83 |
24.31 |
41.94 |
24.58 |
||||||
|
Total Operating Cost per Boe (including Total Exploration Costs) – (k) / (a) |
25.13 |
24.98 |
28.26 |
28.20 |
||||||
|
Composite Average Margin per Boe (including Total Exploration Costs) – [(e) / |
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) |
In general, EOG excludes impairments which are (i) attributable to declines in commodity prices, (ii) related to sales of certain oil and gas properties or (iii) the result of certain other events or decisions (e.g., a periodic review of EOG’s oil and gas properties or other assets). EOG believes excluding these impairments from total exploration costs is appropriate and provides useful information to investors, as such impairments were caused by factors outside of EOG’s control (versus, for example, impairments that are due to EOG’s proved oil and gas properties not being as productive as it originally estimated). |
|
(3) |
EOG believes excluding the above-referenced items from General and Administrative Costs is appropriate and provides useful information to investors, as EOG views such items as non-recurring. |
|
(4) |
EOG believes excluding the above-referenced items from Taxes Other Than Income is appropriate and provides useful information to investors, as EOG views such items as non-recurring. |
SOURCE EOG Resources, Inc.