Feb 27, 2025 SOURCE: PR NewsWire
EOG Resources Reports Fourth Quarter and Full-Year 2024 Results; Announces 2025 Capital Plan
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.
Key Financial Results
In millions of USD, except per-share, per-Boe and ratio data
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 ($/Boe) 10.15 10.15 10.11 10.37 10.52 10.19 10.33
Non - GAAP
Adjusted Net Income 1,535 1,644 1,807 1,626 1,783 6,612 6,825
Adjusted Net Income Per Share 2.74 2.89 3.16 2.82 3.07 11.62 11.69
CFO before Changes in Working Capital 2,635 2,988 3,042 2,928 2,989 11,593 11,149
Capital Expenditures 1,358 1,497 1,668 1,703 1,512 6,226 6,041
Free Cash Flow 1,277 1,491 1,374 1,225 1,477 5,367 5,108
Net Debt (2,340) (2,346) (1,647) (1,501) (1,479) (2,340) (1,479)
Net Debt-to-Total Capitalization (8.7 %) (8.6 %) (6.0 %) (5.5 %) (5.6 %) (8.7 %) (5.6 %)
Cash Operating Costs ($/Boe)1 10.15 10.05 10.11 10.37 10.52 10.17 10.33
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 $6.2 billion 2025 capital plan to grow oil production 3% and total production 6%
- EOG and Bapco Energies entered into a strategic participation agreement in Bahrain
Volumes and Capital Expenditures
4Q 2024 3Q 2024 2Q 2024 1Q 2024 4Q 2023 FY 2024 FY 2023
Guidance
4Q 2024 Midpoint
Volumes
Crude Oil and Condensate (MBod) 494.6 493.0 493.0 490.7 487.4 485.2 491.4 475.8
Natural Gas Liquids (MBbld) 252.5 260.0 254.3 244.8 231.7 235.8 245.9 223.8
Natural Gas (MMcfd) 2,092 2,075 1,970 1,872 1,858 1,831 1,948 1,711
Total Crude Oil Equivalent (MBoed) 1,095.7 1,098.9 1,075.7 1,047.5 1,028.8 1,026.2 1,062.1 984.8
Capital Expenditures ($MM) 1,358 1,330 1,497 1,668 1,703 1,512 6,226 6,041
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 $6.4 billion, including exploration and development drilling, facilities, leasehold acquisitions, capitalized interest, dry hole costs, and other property, plant and equipment, and excluding property acquisitions, asset retirement costs and non-cash exchanges and transactions. The capital program also excludes certain exploration costs incurred as operating expenses.
The disciplined capital program is anchored by steady year-over-year activity levels in the Delaware Basin, with a step up in activity in the Utica and Dorado plays. The plan delivers 3% oil volume growth and 6% total volume growth through the drilling and completion of 605 net wells across EOG's multi-basin portfolio of high return inventory.
The capital program also funds the completion of strategic infrastructure projects and international investment opportunities, including exploration projects in Trinidad and Bahrain.
EOG and Bapco Energies Entered Into a Strategic Participation Agreement in Bahrain
The companies will evaluate a natural gas exploration prospect with planned drilling activity in 2025. The transaction is subject to further government approvals.
Fourth Quarter 2024 Results vs Guidance
(Unaudited)
See "Endnotes" below for related discussion and definitions.
4Q 2024 4Q 2024 1Q 2024
Guidance Variance 3Q 2024 2Q 2024 4Q 2023
Midpoint
Crude Oil and Condensate Volumes (MBod)
United States 493.5 491.9 1.6 491.8 490.1 486.8 484.6
Trinidad 1.1 1.1 0.0 1.2 0.6 0.6 0.6
Total 494.6 493.0 1.6 493.0 490.7 487.4 485.2
Natural Gas Liquids Volumes (MBbld)
Total 252.5 260.0 (7.5) 254.3 244.8 231.7 235.8
Natural Gas Volumes (MMcfd)
United States 1,840 1,825 15 1,745 1,668 1,658 1,653
Trinidad 252 250 2 225 204 200 178
Total 2,092 2,075 17 1,970 1,872 1,858 1,831
Total Crude Oil Equivalent Volumes (MBoed) 1,095.7 1,098.9 (3.2) 1,075.7 1,047.5 1,028.8 1,026.2
Total MMBoe 100.8 101.1 (0.3) 99.0 95.3 93.6 94.4
Benchmark Price
Oil (WTI) ($/Bbl) 70.28 75.16 80.55 76.97 78.33
Natural Gas (HH) ($/Mcf) 2.79 2.16 1.89 2.24 2.87
Crude Oil and Condensate -above (below) WTI
4
($/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)
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 Hub
5
($/Mcf)
United States (0.40) (0.35) (0.05) (0.32) (0.32) (0.14) (0.15)
Natural Gas Realizations ($/Mcf)
Trinidad 3.86 3.65 0.21 3.68 3.48 3.54 3.81
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
Operating Unit Costs ($/Boe)
Lease and Well 3.91 4.20 (0.29) 3.96 4.09 4.23 4.00
Gathering, Processing and Transportation Costs(3) 4.37 4.45 (0.08) 4.50 4.44 4.41 4.49
General and Administrative (GAAP) 1.87 1.69 1.58 1.73 2.03
General and Administrative (non-GAAP)(1) 1.87 1.90 (0.03) 1.59 1.58 1.73 2.03
Cash Operating Costs (GAAP) 10.15 10.15 10.11 10.37 10.52
Cash Operating Costs (non-GAAP)(1) 10.15 10.55 (0.40) 10.05 10.11 10.37 10.52
Depreciation, Depletion and Amortization 10.11 10.35 (0.24) 10.42 10.32 11.47 9.85
Expenses ($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 ($MM) 454 495 (41) 240 341 312 352
First Quarter and Full-Year 2025 Guidance7
(Unaudited)
See "Endnotes" below for related discussion and definitions
1Q 2025 1Q 2025 FY 2025 FY 2025
Midpoint Midpoint 2024 Actual 2023 Actual 2022
Guidance Range Guidance Range
Actual
Crude Oil and Condensate Volumes (MBod)
United States 495.0 - 503.0 499.0 499.5 - 507.5 503.5 490.6 475.2 460.7
Trinidad 0.8 - 1.2 1.0 0.9 - 1.3 1.1 0.8 0.6 0.6
Total 495.8 - 504.2 500.0 500.4 - 508.8 504.6 491.4 475.8 461.3
Natural Gas Liquids Volumes (MBbld)
Total 233.0 - 245.0 239.0 249.0 - 261.0 255.0 245.9 223.8 197.7
Natural Gas Volumes (MMcfd)
United States 1,740 - 1,840 1,790 1,900 - 2,000 1,950 1,728 1,551 1,315
Trinidad 225 - 245 235 215 - 235 225 220 160 180
Total 1,965 - 2,085 2,025 2,115 - 2,235 2,175 1,948 1,711 1,495
Crude Oil Equivalent Volumes (MBoed)
United States 1,018.0 - 1,054.7 1,036.4 1,065.2 - 1,101.8 1,083.5 1,024.5 957.5 877.5
Trinidad 38.3 - 42.0 40.2 36.7 - 40.5 38.6 37.6 27.3 30.7
Total 1,056.3 - 1,096.7 1,076.5 1,101.9 - 1,142.3 1,122.1 1,062.1 984.8 908.2
Benchmark Price
Oil (WTI) ($/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 Hub
5
($/Mcf)
United States (0.70) - 0.00 (0.35) (1.35) - 0.65 (0.35) (0.28) (0.04) 0.63
Natural Gas Realizations
8
($/Mcf)
Trinidad 3.25 - 3.95 3.60 3.00 - 4.00 3.50 3.65 3.65 4.43
Total Expenditures (GAAP) ($MM) 6,653 6,818 5,610
Capital Expenditures
9
(non-GAAP) ($MM) 1,475 - 1,575 1,525 6,000 - 6,400 6,200 6,226 6,041 4,607
Operating Unit Costs ($/Boe)
Lease and Well 4.00 - 4.50 4.25 3.90 - 4.40 4.15 4.04 4.05 4.02
Gathering, Processing and Transportation Costs(3) 4.30 - 4.80 4.55 4.30 - 4.80 4.55 4.43 4.50 4.78
General and Administrative (GAAP) 1.75 - 2.05 1.90 1.65 - 1.95 1.80 1.72 1.78 1.72
General and Administrative (non-GAAP)(1) 1.70 1.78 1.67
Cash Operating Costs (GAAP) 10.05 - 11.35 10.70 9.85 - 11.15 10.50 10.19 10.33 10.52
Cash Operating Costs (non-GAAP)(1) 10.17 10.33 10.47
Depreciation, Depletion and Amortization 10.00 - 11.00 10.50 9.90 - 10.90 10.40 10.57 9.72 10.69
Expenses ($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 EOG
EOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States and Trinidad. To learn more visit www.eogresources.com.
Investor Contacts
Pearce Hammond 713-571-4684
Neel Panchal 713-571-4884
Shelby O'Connor 713-571-4560
Media Contact
Kimberly Ehmer 713-571-4676
Endnotes
1) Cash 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
Financial Commodity and Other
Derivative Contracts, Net
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
Net
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
Transportation Costs (A)
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
Amortization
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
Income Taxes
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)
Amortization
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
Provided by Operating Activities:
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)
Derivative Contracts (Gains) Losses, Net
Net Cash Received from (Payments for) (123) (30) 23 18 (112) 55 79 61 19 214
Settlements of Financial Commodity
Derivative Contracts
Other, Net (1) (1) (2)
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 35 250 28 (18) 295 (229) (127) 59 (85) (382)
Associated with Investing Activities
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
Associated with Investing Activities
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
Employee Stock Purchase Plan
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
Tax Impact Tax Earnings
per Share
Reported Net Income (GAAP) 1,624 (373) 1,251 2.23
Adjustments:
Losses on Mark-to-Market Financial Commodity and Other Derivative 65 (14) 51 0.10
Contracts, Net
Net Cash Received from Settlements of Financial Commodity Derivative 19 (4) 15 0.03
Contracts (1)
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
Tax Impact Tax Earnings
per Share
Reported Net Income (GAAP) 2,134 (461) 1,673 2.95
Adjustments:
Gains on Mark-to-Market Financial Commodity and Other Derivative (79) 17 (62) (0.11)
Contracts, Net
Net Cash Received from Settlements of Financial Commodity Derivative 61 (13) 48 0.08
Contracts (1)
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
Tax Impact Tax Earnings
per Share
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
Contracts, Net
Net Cash Received from Settlements of Financial Commodity Derivative 79 (17) 62 0.11
Contracts (1)
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
Tax Impact Tax Earnings
per Share
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)
Contracts, Net
Net Cash Received from Settlements of Financial Commodity Derivative 55 (12) 43 0.07
Contracts (1)
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
Tax Impact Tax Earnings
per Share
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)
Contracts, Net
Net Cash Received from Settlements of Financial Commodity Derivative 18 (4) 14 0.02
Contracts (1)
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
Tax Impact Tax Earnings
per Share
Reported Net Income (GAAP) 8,218 (1,815) 6,403 11.25
Adjustments:
Gains on Mark-to-Market Financial Commodity and Other Derivative (204) 44 (160) (0.28)
Contracts, Net
Net Cash Received from Settlements of Financial Commodity Derivative 214 (46) 168 0.30
Contracts (1)
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
Tax Impact Tax Earnings
per Share
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)
Contracts, Net
Net Cash Payments for Settlements of Financial Commodity Derivative (112) 24 (88) (0.15)
Contracts (1)
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
Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent"
schedule below)
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
Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent"
schedule below)
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
Contracts
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
Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent"
schedule below)
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
Contracts
Less: Income Tax Benefit (Provision) (4)
After Tax - (a) 15
3Q 2024 Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative 61
Contracts
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
(Including Total Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent"
schedule below)
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)
Unproved Properties
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)
Plant and Equipment
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,
2024 2024 2024 2024 2023
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 Trinidad Other Total
States International
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 Trinidad Other Total
States International
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
GAAP) - (a)
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 Trinidad Other Total
States International
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
GAAP) - (a)
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
Costs) (f)
Total Operating Cost (Non-GAAP) (excluding DD&A and Total Exploration 1,353 1,339 1,337 1,342 1,329
Costs) (g)
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
(j)
Total Operating Cost (Non-GAAP) (including Total Exploration Costs (Non- 2,454 2,428 2,406 2,479 2,360
GAAP)) - (k)
Total Wellhead Revenues less Total Operating Cost (GAAP) (including Total 1,601 1,977 2,069 1,894 2,178
Exploration Costs (GAAP))
Total Wellhead Revenues less Total Operating Cost (Non-GAAP) (including Total 1,855 1,956 2,104 1,896 2,197
Exploration Costs (Non-GAAP))
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
Costs) - [(e) / (a) - (f) / (a)]
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
[(e) / (a) - (h) / (a)]
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
(a) - (j) / (a)]
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
(g) / (a)]
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
[(e) / (a) - (i) / (a)]
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
(a) - (k) / (a)]
(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.
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SOURCE EOG Resources, Inc.
