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| EOG Resources Reports Fourth Quarter and Full-Year 2023 Results; Announces 2024 Capital Plan |
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| 4:15p ET February 22 '24 PR Newswire |
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EOG Resources, Inc. (EOG) today reported fourth quarter and full-year 2023 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 2023 3Q 2023 2Q 2023 1Q 2023 4Q2022 FY 2023 FY 2022
Total Revenue 6,357 6,212 5,573 6,044 6,719 24,186 25,702
Net Income 1,988 2,030 1,553 2,023 2,277 7,594 7,759
Net Income Per Share 3.42 3.48 2.66 3.45 3.87 13.00 13.22
Net Cash Provided by Operating Activities 3,104 2,704 2,277 3,255 3,444 11,340 11,093
Total Expenditures 1,634 1,803 1,664 1,717 1,535 6,818 5,610
Current and Long-Term Debt 3,799 3,806 3,814 3,820 5,078 3,799 5,078
Cash and Cash Equivalents 5,278 5,326 4,764 5,018 5,972 5,278 5,972
Debt-to-Total Capitalization 11.9% 12.1% 12.7% 13.1% 17.0% 11.9% 17.0%
Cash Operating Costs ($/Boe) 10.52 10.19 10.03 10.59 10.82 10.33 10.52
General and Administrative Costs ($/Boe) 2.03 1.75 1.61 1.71 1.87 1.78 1.72
Non - GAAP
Adjusted Net Income 1,783 2,007 1,457 1,578 1,941 6,825 8,080
Adjusted Net Income Per Share 3.07 3.44 2.49 2.69 3.30 11.69 13.76
CFO before Changes in Working Capital 2,989 3,038 2,563 2,559 3,091 11,149 12,252
Capital Expenditures 1,512 1,519 1,521 1,489 1,361 6,041 4,607
Free Cash Flow 1,477 1,519 1,042 1,070 1,730 5,108 7,645
Net Debt (1,479) (1,520) (950) (1,198) (894) (1,479) (894)
Net Debt-to-Total Capitalization (5.6%) (5.8%) (3.8%) (4.9%) (3.7%) (5.6%) (3.7%)
Cash Operating Costs ($/Boe)1 10.52 10.19 10.03 10.59 10.82 10.33 10.47
General and Administrative Costs ($/Boe)1 2.03 1.75 1.61 1.71 1.87 1.78 1.67
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Fourth Quarter Highlights
-- Earned adjusted net income of $1.8 billion, or $3.07 per share
-- Generated $1.5 billion of free cash flow
-- Declared regular quarterly dividend of $0.91 per share and repurchased $300 million of shares
-- Volumes and per-unit operating costs beat guidance midpoints
-- Entered into a 10-year Brent-linked gas sales agreement starting in January 2027
Full-Year 2023 Highlights and 2024 Capital Plan
-- Generated $5.1 billion of free cash flow and returned $4.4 billion to shareholders
-- Delivered oil and total volumes on target and reduced per-unit cash operating costs and DD&A
-- Announced $6.2 billion capital plan to grow oil production 3% and total production 7%
Volumes and Capital Expenditures
| 4Q 2023
4Q 2023 Guidance 3Q 2023 2Q 2023 1Q 2023 4Q 2022 FY 2023 FY 2022
Midpoint
Wellhead Volumes
Crude Oil and Condensate (MBod) 485.2 483.5 483.3 476.6 457.7 465.6 475.8 461.3
Natural Gas Liquids (MBbld) 235.8 234.0 231.1 215.7 212.2 189.0 223.8 197.7
Natural Gas (MMcfd) 1,831 1,785 1,704 1,668 1,639 1,527 1,711 1,495
Total Crude Oil Equivalent (MBoed) 1,026.2 1,015.0 998.5 970.3 943.0 909.1 984.8 908.2
Capital Expenditures ($MM) 1,512 1,500 1,519 1,521 1,489 1,361 6,041 4,607
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From EzraYacob, Chairman and Chief Executive Officer "EOG continues to deliver on its value proposition as demonstrated by our strong execution in 2023. Oil andtotal volumes were on target, capital expenditures on budget, and we further lowered operating costs. Each of the teams working across our multi-basin portfolio championed the EOG culture and played an important role in delivering another successful year.
"The ability to manage investment and pace of activity at the appropriate level for each of our plays was critical to our success in 2023. We lowered the overall cost basis of the company by balancing activity between foundational assets and emerging plays. Progress across our portfolio, including continued improvement in Delaware Basin productivity, successful delineation results in the Utica play, and advancements across several exploration areas, provides opportunity for further improvement going forward.
"EOG's operating results drove our financial performance. EOG earned strong return on capital, while generating $5.1 billion of free cash flow. Cash return to shareholders of $4.4 billion was well above our prior minimum 60% commitment and continues to be anchored by our sustainable, growing regular dividend. The financial strength of the company, including our cash flow generation capacity and our industry-leading balance sheet, allowed us to increase our regular dividend 10% and go-forward cash return commitment to a minimum 70% of annual free cash flow.
"EOG's business has never been better, and our financial position has never been stronger. Our 2024 plan demonstrates our consistent focus on improving the cost structure of our company. The depth of resource across our multi-basin portfolio of premium assets provides long-term visibility for high returns and strong free cash flow generation. Our confidence inEOG's ability to compete across sectors, create value for our shareholders, and be part of the long-term energy solution has never beenhigher."
Fourth Quarter 2023 Financial Performance
Prices
-- Crude oil andNGL prices decreased, partially offset by an increase in natural gas prices from 3Q
Volumes
-- Oil production of 485,200 Bopd was above the guidance midpoint and up from 3Q
-- NGL production was above the guidance midpoint and up 2% from 3Q
-- Natural gas production was above the high end of the guidance range and up 7% from 3Q
-- Total company equivalent production increased 3% from 3Q
Per-Unit Costs
-- Gathering & processing, G&A, and DD&A expenses increased in 4Q compared with 3Q, whileLOE and transportation costsdecreased
Hedges
-- Mark-to-market hedge gains increased 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 CashFlow
-- Cash flow from operations before changes in working capital was $3.0 billion
-- EOG incurred $1.5 billion of capital expenditures
-- This resulted in $1.5 billion of free cash flow
Cash Return and Working Capital
-- Paid $479 million in regular dividends
-- Paid $866 million in special dividends
-- Repurchased $300 million of stock
-- Changes in working capital and other items accounted for approximately $100 million of the increase in cash
Full-Year 2023 Financial Performance
Prices
-- Crude oil prices decreased 19%
-- NGL prices decreased 37%
-- Natural gas prices decreased 60%
Volumes
-- Crude oil production increased 3% to 475,800 Bopd
-- NGL production increased 13%
-- Natural gas production increased 14%
-- Total company equivalent production increased 8%
Per-Unit Costs
-- DD&A, transportation costs, and gathering & processing costs decreased in 2023, partially offset by higherLOE and G&A
Hedges
-- Lower commodity prices in 2023 were partially offset by net mark-to-market hedge gains and lower net cash payments to settle hedges than 2022
Free Cash Flow
-- Cash flow from operations before changes in working capital was $11.1 billion
-- EOG incurred $6.0 billion of capital expenditures
-- This resulted in $5.1 billion of free cash flow
Cash Return and Working Capital
-- Paid $1.9 billion in regular dividends
-- Paid $1.5 billion in special dividends
-- Repurchased $971 million of stock
-- Repaid $1.25 billion of debt upon maturity
Fourth Quarter 2023 Operating Performance; Cash Return
Lease and Well
-- QoQ: Generally flat
-- Guidance Midpoint: Lower primarily due to water handling costs and workovers
Transportation
-- QoQ: Generally flat
-- Guidance Midpoint: Lower primarily due to natural gas transportation
Gathering and Processing
-- QoQ: Increased primarily due to fuel costs
-- Guidance Midpoint: Generally flat
General and Administrative
-- QoQ: Increased primarily due to professional fees and employee-related expenses
-- Guidance Midpoint: Higher primarily due to professional fees and employee- related expenses
Depreciation, Depletion and Amortization
-- QoQ: Increased primarily due to well mix
-- Guidance Midpoint: Lower primarily due to the addition of lower cost reserves
Regular Dividend and Fourth Quarter Share Repurchases The Board of Directors today declared a dividend of $0.91 per share on EOG's common stock. The dividend will be payable April 30, 2024, to stockholders of record as of April 16, 2024. The indicated annual rate is $3.64 per share.
During the fourth quarter, the company repurchased 2.4 million shares for $300 million under its share repurchase authorization, at an average purchase price of $123 pershare.
For full-year 2023, the company repurchased 8.6 million shares for $971 million under its share repurchase authorization, at an average purchase price of $112 per share. EOG has $4.0 billion remaining on its current repurchase authorization.
2023 Reserves
Finding and Development Cost Finding and development cost, excluding price revisions, increased in 2023 to $7.20 per Boe, due to lower year-over-year revisions other than price and cost inflation. Proved developed finding cost, excluding price revisions, was $10.50 perBoe (GAAP) and$9.35 per Boe (Non-GAAP) in 2023.
For the 36th consecutive year, internal reserves estimates were within five percent of estimates independently prepared by DeGolyer and MacNaughton.
Reserve Replacement Total proved reserves increased 6% in 2023. Extensions and discoveries added 607 MMBoe of proved reserves in 2023. Revisions other than price increased proved reserves by 139 MMBoe. Net proved reserve additions from all sources, excluding price revisions, replaced 202% of 2023 total production.
2024 Capital Program and Brent-Linked Gas Sales Agreement
2024 Capital Program Total expenditures for 2024 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 allocates approximately $4.3 billion to drill and complete 600 net wells in EOG's domestic premium areas. Strong capital efficiency delivers 3% oil volume growth and 7% total volume growth, for ~$100 million lower year-over-year total direct investment in drilling and completion activity. The plan is anchored by steady year-over-year activity levels across most of EOG's premium plays, with a step up in activity in the Ohio Utica play.
The capital program also funds investment in environmental and infrastructure projects, including approximately $400 million in strategic infrastructure projects associated with EOG's Delaware Basin and Dorado assets. These projects are expected to provide several long-term benefits to the company, including margin improvement through higher price realizations and lower operating costs.
Brent-Linked Gas Sales Agreement EOG entered into a 10-year Brent-linked gas sales agreement. Starting in January 2027, the company will have sales volumes of 140K MMBtu per day linked to Brent crude oil prices with an additional 40K MMBtu per day linked to Brent crude oil prices or a US Gulf Coast gas index. This latest agreement complements existing agreements in providing additional pricing diversification for gas volumes sourced across several basins within EOG's multi-basin portfolio.
| Fourth Quarter 2023 Results vs Guidance
(Unaudited)
See "Endnotes" below for related discussion and definitions. 4Q 2023
4Q 2023 Guidance Variance 3Q 2023 2Q 2023 1Q 2023 4Q 2022
Midpoint
Crude Oil and Condensate Volumes (MBod)
United States 484.6 483.1 1.5 482.8 476.0 457.1 465.1
Trinidad 0.6 0.4 0.2 0.5 0.6 0.6 0.5
Other International 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Total 485.2 483.5 1.7 483.3 476.6 457.7 465.6
Natural Gas Liquids Volumes (MBbld)
Total 235.8 234.0 1.8 231.1 215.7 212.2 189.0
Natural Gas Volumes (MMcfd)
United States 1,653 1,615 38 1,562 1,513 1,475 1,378
Trinidad 178 170 8 142 155 164 149
Other International 0 0 0 0 0 0 0
Total 1,831 1,785 46 1,704 1,668 1,639 1,527
Total Crude Oil Equivalent Volumes (MBoed) 1,026.2 1,015.0 11.2 998.5 970.3 943.0 909.1
Total MMBoe 94.4 93.4 1.0 91.9 88.3 84.9 83.6
Benchmark Price
Oil (WTI) ($/Bbl) 78.33 82.18 73.75 76.11 82.63
Natural Gas (HH) ($/Mcf) 2.87 2.55 2.09 3.43 6.27
Crude Oil and Condensate - above (below) WTI3 ($/Bbl)
United States 2.28 2.00 0.28 1.43 1.23 1.16 3.05
Trinidad (9.12) (11.25) 2.13 (10.80) (8.87) (7.13) (7.42)
Natural Gas Liquids - Realizations as % of WTI
Total 28.5% 27.0% 1.5% 28.7% 28.3% 33.7% 34.6%
Natural Gas - above (below) NYMEX Henry Hub4 ($/Mcf)
United States (0.15) 0.15 (0.30) 0.04 (0.02) 0.04 (0.15)
Natural Gas Realizations5 ($/Mcf)
Trinidad 3.81 3.48 0.33 3.41 3.45 3.87 3.97
Total Expenditures (GAAP) ($MM) 1,634 1,803 1,664 1,717 1,535
Capital Expenditures (non-GAAP) ($MM) 1,512 1,500 12 1,519 1,521 1,489 1,361
Operating Unit Costs ($/Boe)
Lease and Well 4.00 4.20 (0.20) 4.02 3.94 4.23 4.23
Transportation Costs 2.60 2.65 (0.05) 2.61 2.67 2.78 2.83
Gathering and Processing 1.89 1.90 (0.01) 1.81 1.81 1.87 1.89
General and Administrative (GAAP) 2.03 1.90 0.13 1.75 1.61 1.71 1.87
General and Administrative (non-GAAP)1 2.03 1.90 0.13 1.75 1.61 1.71 1.87
Cash Operating Costs (GAAP) 10.52 10.65 (0.13) 10.19 10.03 10.59 10.82
Cash Operating Costs (non-GAAP) 10.52 10.65 (0.13) 10.19 10.03 10.59 10.82
Depreciation, Depletion and Amortization 9.85 10.00 (0.15) 9.78 9.81 9.40 10.50
Expenses ($MM)
Exploration and Dry Hole 41 45 (4) 43 47 51 48
Impairment (GAAP) 79 54 35 34 142
Impairment (excluding certain impairments (non-GAAP))6 60 100 (40) 31 35 34 111
Capitalized Interest 9 10 (1) 8 8 8 11
Net Interest 35 34 1 36 35 42 42
TOTI (% of Wellhead Revenue) (GAAP) 6.6% 7.5% (0.9%) 7.4% 7.8% 7.8% 7.8%
TOTI (% of Wellhead Revenue) (non-GAAP)1 6.6% 7.5% (0.9%) 7.4% 7.8% 7.8% 7.8%
Income Taxes
Effective Rate 21.6% 21.5% 0.1% 21.1% 21.9% 22.0% 20.4%
Current Tax Expense ($MM) 352 330 22 486 241 338 409
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| First Quarter and Full-Year 2024 Guidance7
(Unaudited) 1Q 2024 1Q 2024 FY 2024 FY 2024 2023 2022 2021
See "Endnotes" below for related discussion and definitions. Guidance Range Midpoint Guidance Range Midpoint Actual Actual Actual
Crude Oil and Condensate Volumes (MBod)
United States 483.0 - 489.0 486.0 485.0 - 490.0 487.5 475.2 460.7 443.4
Trinidad 0.1 - 0.5 0.3 0.5 - 1.5 1.0 0.6 0.6 1.5
Other International 0.0 - 0.0 0.0 0.0 - 0.0 0.0 0.0 0.0 0.1
Total 483.1 - 489.5 486.3 485.5 - 491.5 488.5 475.8 461.3 445.0
Natural Gas Liquids Volumes (MBbld)
Total 223.0 - 233.0 228.0 220.0 - 250.0 235.0 223.8 197.7 144.5
Natural Gas Volumes (MMcfd)
United States 1,625 - 1,675 1,650 1,630 - 1,830 1,730 1,551 1,315 1,210
Trinidad 170 - 200 185 210 - 240 225 160 180 217
Other International 0 - 0 0 0 - 0 0 0 0 9
Total 1,795 - 1,875 1,835 1,840 - 2,070 1,955 1,711 1,495 1,436
Crude Oil Equivalent Volumes (MBoed)
United States 976.8 - 1,001.2 989.0 976.7 - 1,045.0 1,010.9 957.5 877.5 789.6
Trinidad 28.4 - 33.8 31.1 35.5 - 41.5 38.5 27.3 30.7 37.7
Other International 0.0 - 0.0 0.0 0.0 - 0.0 0.0 0.0 0.0 1.6
Total 1,005.2 - 1,035.0 1,020.1 1,012.2 - 1,086.5 1,049.4 984.8 908.2 828.9
Benchmark Price
Oil (WTI) ($/Bbl) 77.61 94.23 67.96
Natural Gas (HH) ($/Mcf) 2.74 6.64 3.85
Crude Oil and Condensate - above (below) WTI3 ($/Bbl)
United States 0.75 - 2.25 1.50 0.40 - 2.40 1.40 1.57 2.99 0.58
Trinidad (10.10) - (8.60) (9.35) (11.40) - (9.40) (10.40) (9.03) (8.07) (11.70)
Natural Gas Liquids - Realizations as % of WTI
Total 27.0% - 37.0% 32.0% 26.0% - 36.0% 31.0% 29.7% 39.0% 50.5%
Natural Gas - above (below) NYMEX Henry Hub4 ($/Mcf)
United States (0.45) - 0.25 (0.10) (1.30) - 0.80 (0.25) (0.04) 0.63 1.03
Natural Gas Realizations5 ($/Mcf)
Trinidad 3.10 - 3.80 3.45 3.00 - 4.00 3.50 3.65 4.43 3.40
Total Expenditures (GAAP) ($MM) 6,818 5,610 4,255
Capital Expenditures8 (non-GAAP) ($MM) 1,650 - 1,750 1,700 6,000 - 6,400 6,200 6,041 4,607 3,755
Operating Unit Costs ($/Boe)
Lease and Well 3.95 - 4.45 4.20 3.80 - 4.50 4.15 4.05 4.02 3.75
Transportation Costs 2.50 - 2.80 2.65 2.45 - 2.85 2.65 2.66 2.91 2.85
Gathering and Processing 1.85 - 2.05 1.95 1.85 - 2.15 2.00 1.84 1.87 1.85
General and Administrative (GAAP) 1.70 - 2.00 1.85 1.70 - 1.95 1.83 1.78 1.72 1.69
General and Administrative (non-GAAP)1 1.78 1.67 1.69
Cash Operating Costs (GAAP) 10.00 - 11.30 10.65 9.80 - 11.45 10.63 10.33 10.52 10.14
Cash Operating Costs (non-GAAP) 10.33 10.47 10.14
Depreciation, Depletion and Amortization 10.90 - 11.90 11.40 10.00 - 11.00 10.50 9.72 10.69 12.07
Expenses ($MM)
Exploration and Dry Hole 30 - 70 50 175 - 225 200 182 204 225
Impairment (GAAP) 202 382 376
Impairment (excluding certain impairments (non-GAAP))6 30 - 110 70 160 - 240 200 160 269 361
Capitalized Interest 7 - 11 9 39 - 43 41 33 36 33
Net Interest 33 - 37 35 131 - 135 133 148 179 178
TOTI (% of Wellhead Revenue) (GAAP) 7.0% - 9.0% 8.0% 7.0% - 9.0% 8.0% 7.4% 7.0% 6.8%
TOTI (% of Wellhead Revenue) (non-GAAP)1 7.4% 7.5% 6.8%
Income Taxes
Effective Rate 20.0% - 25.0% 22.5% 20.0% - 25.0% 22.5% 21.6% 21.7% 21.4%
Current Tax Expense ($MM) 270 - 370 320 1,060 - 1,460 1,260 1,415 2,208 1,393
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Fourth Quarter and Full-Year 2023 Results Webcast Friday, February 23, 2024, 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) Third quarter 2022 TOTI (% of Wellhead Revenue) (non-GAAP) and General and Administrative Costs (non-GAAP) exclude a state severance tax refund and related consulting fees, respectively, as reflected in the accompanying Adjusted Net Income (Loss) reconciliationschedule.
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 (expense), interest expense and the impact of changes in the effective income tax rate.
3) 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.
4) EOG bases United States natural gas price differentials upon the natural gas price at Henry Hub, Louisiana, using the NYMEX Last DaySettle price for each of the applicable months.
5) The third quarter and full-year 2022 realized natural gas price for Trinidad includes a one-time pricing adjustment of $3.37/Mcf and$0.76/Mcf, respectively, for prior-period production following a contract amendment with the National Gas Company of Trinidad andTobago Limited (NGC).
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 toinvestors, 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 2024 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 orotherwise. 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 orforecast.
8) 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.
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| 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
G&A General and administrative expense
G&P Gathering and processing expense
GHG Greenhouse gas
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
Trans Transportation expense
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
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This press release 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 regardingEOG'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, safety matters or other ESG (environmental/social/governance) matters, pay and/or increaseregular 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 causeEOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, amongothers:
-- the timing, extent 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 recovery 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 inflationary 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 prevention 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;
-- the availability, cost, terms and timing of issuance or execution of mineral licenses and leases and governmental and other permits and rights-of- way, and EOG's ability to retain mineral licenses 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 and 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 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 policies and initiatives at the corporate and/or investor community levels and other potential developments related to climate change, such as (but not limited to) changes in consumer and industrial/commercial behavior, preferences and attitudes with respect to the generation and consumption of energy; increased availability of, and increased consumer and industrial/commercial demand for, competing energy sources (including alternative energy sources); technological advances with respect to the generation, transmission, storage and consumption of energy; alternative fuel requirements; energy conservation measures and emissions-related legislation; decreased demand for, and availability of, services and facilities related to the exploration for, and production of, crude oil, NGLs and natural gas; and negative perceptions of the oil and gas industry and, in turn, reputational risks associated with the exploration for, and production of, crude oil, NGLs and natural gas;
-- continuing political and social concerns relating to climate change and the greater potential for shareholder activism, governmental inquiries and enforcement actions and litigation and the resulting expenses and potential disruption to EOG's day-to-day operations;
-- the extent to which EOG is able to successfully and economically develop, implement and carry out its emissions and other ESG-related initiatives and achieve its related targets, 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, 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, including its impact on crude oil and natural gas demand, and weather-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 duration and 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;
-- acts of war and terrorism and responses to these acts; 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, 2023 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. Management believes these forward-looking, non-GAAP measures may be a useful tool for the investment community in comparingEOG's forecasted financialperformance 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 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, 2023 (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 atwww.sec.gov.
| Income Statements
In millions of USD, except share data (in millions) and per share data (Unaudited)
2022 2023
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 3,889 4,699 4,109 3,670 16,367 3,182 3,252 3,717 3,597 13,748
Natural Gas Liquids 681 777 693 497 2,648 490 409 501 484 1,884
Natural Gas 716 1,000 1,235 830 3,781 517 334 417 476 1,744
Gains (Losses) on Mark-to-Market Financial Commodity Derivative (2,820) (1,377) (18) 233 (3,982) 376 101 43 298 818
Contracts, Net
Gathering, Processing and Marketing 1,469 2,169 1,561 1,497 6,696 1,390 1,465 1,478 1,473 5,806
Gains (Losses) on Asset Dispositions, Net 25 97 (21) (27) 74 69 (9) 35 — 95
Other, Net 23 42 34 19 118 20 21 21 29 91
Total 3,983 7,407 7,593 6,719 25,702 6,044 5,573 6,212 6,357 24,186
Operating Expenses
Lease and Well 318 324 335 354 1,331 359 348 369 378 1,454
Transportation Costs 228 244 257 237 966 236 236 240 245 957
Gathering and Processing Costs 144 152 167 158 621 159 160 166 178 663
Exploration Costs 45 35 35 44 159 50 47 43 41 181
Dry Hole Costs 3 20 18 4 45 1 — — — 1
Impairments 55 91 94 142 382 34 35 54 79 202
Marketing Costs 1,283 2,127 1,621 1,504 6,535 1,361 1,456 1,383 1,509 5,709
Depreciation, Depletion and Amortization 847 911 906 878 3,542 798 866 898 930 3,492
General and Administrative 124 128 162 156 570 145 142 161 192 640
Taxes Other Than Income 390 472 334 389 1,585 329 313 341 301 1,284
Total 3,437 4,504 3,929 3,866 15,736 3,472 3,603 3,655 3,853 14,583
Operating Income 546 2,903 3,664 2,853 9,966 2,572 1,970 2,557 2,504 9,603
Other Income (Expense), Net (1) 27 40 48 114 65 51 52 66 234
Income Before Interest Expense and Income Taxes 545 2,930 3,704 2,901 10,080 2,637 2,021 2,609 2,570 9,837
Interest Expense, Net 48 48 41 42 179 42 35 36 35 148
Income Before Income Taxes 497 2,882 3,663 2,859 9,901 2,595 1,986 2,573 2,535 9,689
Income Tax Provision 107 644 809 582 2,142 572 433 543 547 2,095
Net Income 390 2,238 2,854 2,277 7,759 2,023 1,553 2,030 1,988 7,594
Dividends Declared per Common Share 1.7500 2.5500 2.2500 2.3250 8.8750 1.8250 0.8250 0.8250 2.4100 5.8850
Net Income Per Share
Basic 0.67 3.84 4.90 3.90 13.31 3.46 2.68 3.51 3.43 13.07
Diluted 0.67 3.81 4.86 3.87 13.22 3.45 2.66 3.48 3.42 13.00
Average Number of Common Shares
Basic 582 583 583 584 583 584 580 579 579 581
Diluted 586 588 587 588 587 587 584 583 581 584
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| Wellhead Volumes and Prices
(Unaudited)
2022 2023
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 449.4 463.5 464.6 465.1 460.7 457.1 476.0 482.8 484.6 475.2
Trinidad 0.7 0.6 0.5 0.5 0.6 0.6 0.6 0.5 0.6 0.6
Total 450.1 464.1 465.1 465.6 461.3 457.7 476.6 483.3 485.2 475.8
Average Crude Oil and Condensate Prices ($/Bbl) (B)
United States $ 96.02 $ 111.26 $ 96.05 $ 85.68 $ 97.22 $ 77.27 $ 74.98 $ 83.61 80.61 $ 79.18
Trinidad 83.82 98.29 84.98 75.21 86.16 68.98 64.88 71.38 69.21 68.58
Composite 96.00 111.25 96.04 85.67 97.21 77.26 74.97 83.60 80.60 79.17
Natural Gas Liquids Volumes (MBbld) (A)
United States 190.3 201.9 209.3 189.0 197.7 212.2 215.7 231.1 235.8 223.8
Total 190.3 201.9 209.3 189.0 197.7 212.2 215.7 231.1 235.8 223.8
Average Natural Gas Liquids Prices ($/Bbl) (B)
United States $ 39.77 $ 42.28 $ 36.02 $ 28.55 $ 36.70 $ 25.67 $ 20.85 $ 23.56 22.29 $ 23.07
Composite 39.77 42.28 36.02 28.55 36.70 25.67 20.85 23.56 22.29 23.07
Natural Gas Volumes (MMcfd) (A)
United States 1,249 1,324 1,306 1,378 1,315 1,475 1,513 1,562 1,653 1,551
Trinidad 209 204 163 149 180 164 155 142 178 160
Total 1,458 1,528 1,469 1,527 1,495 1,639 1,668 1,704 1,831 1,711
Average Natural Gas Prices ($/Mcf) (B)
United States $ 5.81 $ 7.77 $ 9.35 $ 6.12 $ 7.27 $ 3.47 $ 2.07 $ 2.59 2.72 $ 2.70
Trinidad (D) 3.36 3.42 7.45 3.97 4.43 3.87 3.45 3.41 3.81 3.65
Composite 5.46 7.19 9.14 5.91 6.93 3.51 2.20 2.66 2.82 2.79
Crude Oil Equivalent Volumes (MBoed) (C)
United States 847.8 886.1 891.6 883.8 877.5 915.0 943.8 974.2 995.8 957.5
Trinidad 35.5 34.6 27.6 25.3 30.7 28.0 26.5 24.3 30.4 27.3
Total 883.3 920.7 919.2 909.1 908.2 943.0 970.3 998.5 1,026.2 984.8
Total MMBoe (C) 79.5 83.8 84.6 83.6 331.5 84.9 88.3 91.9 94.4 359.4
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| (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 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, 2023).
(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.
(D) Includes positive revenue adjustment of $0.76 per Mcf ($0.09 per Mcf of EOG's composite wellhead natural gas price) for the twelve months ended December 31, 2022, related to a price adjustment per a provision of the natural gas sales contract with the National Gas Company of Trinidad and Tobago Limited and its subsidiary amended in July 2022 for natural gas sales during the period from September 2020 through June 2022.
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| Balance Sheets
In millions of USD (Unaudited)
2022 2023
MAR JUN SEP DEC MAR JUN SEP DEC
Current Assets
Cash and Cash Equivalents 4,009 3,073 5,272 5,972 5,018 4,764 5,326 5,278
Accounts Receivable, Net 3,213 3,735 3,343 2,774 2,455 2,263 2,927 2,716
Inventories 586 739 872 1,058 1,131 1,355 1,379 1,275
Assets from Price Risk Management Activities — 1 — — — — — 106
Income Taxes Receivable — — 93 97 — 1 — —
Other 671 605 621 574 580 523 626 560
Total 8,479 8,153 10,201 10,475 9,184 8,906 10,258 9,935
Property, Plant and Equipment
Oil and Gas Properties (Successful Efforts Method) 65,408 66,098 67,065 67,322 67,907 69,178 70,730 72,090
Other Property, Plant and Equipment 4,801 4,862 4,659 4,786 5,101 5,282 5,355 5,497
Total Property, Plant and Equipment 70,209 70,960 71,724 72,108 73,008 74,460 76,085 77,587
Less: Accumulated Depreciation, Depletion and Amortization (41,747) (42,113) (42,623) (42,679) (42,785) (43,550) (44,362) (45,290)
Total Property, Plant and Equipment, Net 28,462 28,847 29,101 29,429 30,223 30,910 31,723 32,297
Deferred Income Taxes 13 12 18 33 31 33 33 42
Other Assets 1,143 1,127 1,167 1,434 1,587 1,638 1,633 1,583
Total Assets 38,097 38,139 40,487 41,371 41,025 41,487 43,647 43,857
Current Liabilities
Accounts Payable 2,660 2,896 2,718 2,532 2,438 2,205 2,464 2,437
Accrued Taxes Payable 1,130 594 542 405 637 425 605 466
Dividends Payable 436 437 437 482 482 478 478 526
Liabilities from Price Risk Management Activities 260 79 243 169 31 22 22 —
Current Portion of Long-Term Debt 1,283 1,282 1,282 1,283 33 34 34 34
Current Portion of Operating Lease Liabilities 223 216 235 296 354 335 337 325
Other 272 264 289 346 253 232 285 286
Total 6,264 5,768 5,746 5,513 4,228 3,731 4,225 4,074
Long-Term Debt 3,816 3,809 3,802 3,795 3,787 3,780 3,772 3,765
Other Liabilities 2,191 2,067 2,573 2,574 2,620 2,581 2,698 2,526
Deferred Income Taxes 4,286 4,183 4,517 4,710 4,943 5,138 5,194 5,402
Commitments and Contingencies
Stockholders' Equity
Common Stock, $0.01 Par 206 206 206 206 206 206 206 206
Additional Paid in Capital 6,095 6,128 6,155 6,187 6,219 6,257 6,133 6,166
Accumulated Other Comprehensive Loss (13) (12) (6) (8) (8) (9) (7) (9)
Retained Earnings 15,283 16,028 17,563 18,472 19,423 20,497 22,047 22,634
Common Stock Held in Treasury (31) (38) (69) (78) (393) (694) (621) (907)
Total Stockholders' Equity 21,540 22,312 23,849 24,779 25,447 26,257 27,758 28,090
Total Liabilities and Stockholders' Equity 38,097 38,139 40,487 41,371 41,025 41,487 43,647 43,857
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| Cash Flow Statements
In millions of USD (Unaudited)
2022 2023
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 390 2,238 2,854 2,277 7,759 2,023 1,553 2,030 1,988 7,594
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization 847 911 906 878 3,542 798 866 898 930 3,492
Impairments 55 91 94 142 382 34 35 54 79 202
Stock-Based Compensation Expenses 35 30 34 34 133 34 35 57 51 177
Deferred Income Taxes (465) (102) 327 179 (61) 234 194 56 199 683
(Gains) Losses on Asset Dispositions, Net (25) (97) 21 27 (74) (69) 9 (35) — (95)
Other, Net 6 (16) (5) 15 — 4 2 (1) 22 27
Dry Hole Costs 3 20 18 4 45 1 — — — 1
Mark-to-Market Financial Commodity Derivative Contracts (Gains) Losses, Net 2,820 1,377 18 (233) 3,982 (376) (101) (43) (298) (818)
Net Cash Received from (Payments for) Settlements of Financial (296) (2,114) (847) (244) (3,501) (123) (30) 23 18 (112)
Commodity Derivative Contracts
Other, Net 2 19 12 12 45 (1) — (1) — (2)
Changes in Components of Working Capital and Other Assets and Liabilities
Accounts Receivable (878) (522) 392 661 (347) 338 137 (714) 201 (38)
Inventories (14) (157) (140) (223) (534) (77) (226) (28) 100 (231)
Accounts Payable 130 259 (88) (211) 90 (77) (231) 238 (49) (119)
Accrued Taxes Payable 613 (536) (53) (137) (113) 232 (212) 180 (139) 61
Other Assets (213) 71 (129) (93) (364) 52 43 (92) 36 39
Other Liabilities (2,250) 433 1,269 282 (266) 193 (47) 54 (16) 184
Changes in Components of Working Capital Associated with Investing Activities 68 143 90 74 375 35 250 28 (18) 295
Net Cash Provided by Operating Activities 828 2,048 4,773 3,444 11,093 3,255 2,277 2,704 3,104 11,340
Investing Cash Flows
Additions to Oil and Gas Properties (939) (1,349) (1,102) (1,229) (4,619) (1,305) (1,341) (1,379) (1,360) (5,385)
Additions to Other Property, Plant and Equipment (70) (75) (103) (133) (381) (319) (180) (139) (162) (800)
Proceeds from Sales of Assets 121 110 79 39 349 92 29 14 5 140
Other Investing Activities — (30) — — (30) — — — — —
Changes in Components of Working Capital Associated with Investing Activities (68) (143) (90) (74) (375) (35) (250) (28) 18 (295)
Net Cash Used in Investing Activities (956) (1,487) (1,216) (1,397) (5,056) (1,567) (1,742) (1,532) (1,499) (6,340)
Financing Cash Flows
Long-Term Debt Repayments — — — — — (1,250) — — — (1,250)
Dividends Paid (1,023) (1,486) (1,312) (1,327) (5,148) (1,067) (480) (494) (1,345) (3,386)
Treasury Stock Purchased (43) (15) (37) (23) (118) (317) (302) (109) (310) (1,038)
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan 4 13 — 11 28 — 9 1 10 20
Debt Issuance Costs — — — — — — (8) — — (8)
Repayment of Finance Lease Liabilities (10) (9) (8) (8) (35) (8) (8) (8) (8) (32)
Net Cash Used in Financing Activities (1,072) (1,497) (1,357) (1,347) (5,273) (2,642) (789) (610) (1,653) (5,694)
Effect of Exchange Rate Changes on Cash — — (1) — (1) — — — — —
Increase (Decrease) in Cash and Cash Equivalents (1,200) (936) 2,199 700 763 (954) (254) 562 (48) (694)
Cash and Cash Equivalents at Beginning of Period 5,209 4,009 3,073 5,272 5,209 5,972 5,018 4,764 5,326 5,972
Cash and Cash Equivalents at End of Period 4,009 3,073 5,272 5,972 5,972 5,018 4,764 5,326 5,278 5,278
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| 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.
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| Adjusted Net Income (Loss)
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 unrealized mark-to-market (gains) losses from these 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 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 Contracts, Net (298) 64 (234) (0.40)
Net Cash Received from Settlements of Financial Commodity Derivative Contracts (1) 18 (4) 14 0.02
Less: Losses on Asset Dispositions, Net — — — —
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 (Non-GAAP)
Basic 579
Diluted 581
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|
(1) Consistent with its customary practice, in calculating Adjusted Net Income (Loss) (non-GAAP), EOG adds to reported Net Income (Loss) (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.
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| Adjusted Net Income (Loss)
(Continued)
In millions of USD, except share data (in millions) and per share data (Unaudited)
3Q 2023
Before Income Tax After Diluted
Tax Impact Tax Earnings
per Share
Reported Net Income (GAAP) 2,573 (543) 2,030 3.48
Adjustments:
Gains on Mark-to-Market Financial Commodity Derivative Contracts, Net (43) 9 (34) (0.06)
Net Cash Received from Settlements of Financial Commodity Derivative Contracts (1) 23 (5) 18 0.03
Less: Gains on Asset Dispositions, Net (35) 7 (28) (0.05)
Add: Certain Impairments 23 (2) 21 0.04
Adjustments to Net Income (32) 9 (23) (0.04)
Adjusted Net Income (Non-GAAP) 2,541 (534) 2,007 3.44
Average Number of Common Shares (Non-GAAP)
Basic 579
Diluted 583
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|
(1) Consistent with its customary practice, in calculating Adjusted Net Income (Loss) (non-GAAP), EOG adds to reported Net Income (Loss) (GAAP) the total net cash received from settlements of financial commodity derivative contracts during such period. For the three months ended September 30, 2023, such amount was $23 million.
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| Adjusted Net Income (Loss)
(Continued)
In millions of USD, except share data (in millions) and per share data (Unaudited)
2Q 2023
Before Income Tax After Diluted
Tax Impact Tax Earnings
per Share
Reported Net Income (GAAP) 1,986 (433) 1,553 2.66
Adjustments:
Gains on Mark-to-Market Financial Commodity Derivative Contracts, Net (101) 22 (79) (0.14)
Net Cash Payments for Settlements of Financial Commodity Derivative Contracts (1) (30) 6 (24) (0.04)
Add: Losses on Asset Dispositions, Net 9 (2) 7 0.01
Adjustments to Net Income (122) 26 (96) (0.17)
Adjusted Net Income (Non-GAAP) 1,864 (407) 1,457 2.49
Average Number of Common Shares (Non-GAAP)
Basic 580
Diluted 584
| |
|
(1) Consistent with its customary practice, in calculating Adjusted Net Income (Loss) (non-GAAP), EOG subtracts from reported Net Income (Loss) (GAAP) the total net cash paid for settlements of financial commodity derivative contracts during such period. For the three months ended June 30, 2023, such amount was $30 million.
| |
| Adjusted Net Income (Loss)
(Continued)
In millions of USD, except share data (in millions) and per share data (Unaudited)
1Q 2023
Before Income Tax After Diluted
Tax Impact Tax Earnings
per Share
Reported Net Income (GAAP) 2,595 (572) 2,023 3.45
Adjustments:
Gains on Mark-to-Market Financial Commodity Derivative Contracts, Net (376) 81 (295) (0.51)
Net Cash Payments for Settlements of Financial Commodity Derivative Contracts (1) (123) 27 (96) (0.16)
Less: Gains on Asset Dispositions, Net (69) 15 (54) (0.09)
Adjustments to Net Income (568) 123 (445) (0.76)
Adjusted Net Income (Non-GAAP) 2,027 (449) 1,578 2.69
Average Number of Common Shares (Non-GAAP)
Basic 584
Diluted 587
| |
|
(1) Consistent with its customary practice, in calculating Adjusted Net Income (Loss) (non-GAAP), EOG subtracts from reported Net Income (Loss) (GAAP) the total net cash paid for settlements of financial commodity derivative contracts during such period. For the three months ended March 31, 2023, such amount was $123 million.
| |
| Adjusted Net Income (Loss)
(Continued)
In millions of USD, except share data (in millions) and per share data (Unaudited)
4Q 2022
Before Income Tax After Diluted
Tax Impact Tax Earnings
per Share
Reported Net Income (GAAP) 2,859 (582) 2,277 3.87
Adjustments:
Gains on Mark-to-Market Financial Commodity Derivative Contracts, Net (233) 57 (176) (0.31)
Net Cash Payments for Settlements of Financial Commodity Derivative Contracts (1) (244) 48 (196) (0.33)
Add: Losses on Asset Dispositions, Net 27 (6) 21 0.04
Add: Certain Impairments 31 (16) 15 0.03
Adjustments to Net Income (419) 83 (336) (0.57)
Adjusted Net Income (Non-GAAP) 2,440 (499) 1,941 3.30
Average Number of Common Shares (Non-GAAP)
Basic 584
Diluted 588
| |
|
(1) Consistent with its customary practice, in calculating Adjusted Net Income (Loss) (non-GAAP), EOG subtracts from reported Net Income (Loss) (GAAP) the total net cash paid for settlements of financial commodity derivative contracts during such period. For the three months ended December 31, 2022, such amount was $244 million.
| |
| Adjusted Net Income (Loss)
(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 Contracts, Net (818) 176 (642) (1.09)
Net Cash Payments for Settlements of Financial Commodity Derivative Contracts (1) (112) 24 (88) (0.15)
Less: Gains on Asset Dispositions, Net (95) 20 (75) (0.13)
Add: Certain Impairments 42 (6) 36 0.06
Adjustments to Net Income (983) 214 (769) (1.31)
Adjusted Net Income (Non-GAAP) 8,706 (1,881) 6,825 11.69
Average Number of Common Shares (Non-GAAP)
Basic 581
Diluted 584
| |
| (1) Consistent with its customary practice, in calculating Adjusted Net Income (Loss) (non-GAAP), EOG subtracts from reported Net Income (Loss) (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.
| |
| Adjusted Net Income (Loss)
(Continued)
In millions of USD, except share data (in millions) and per share data (Unaudited)
FY 2022
Before Income Tax After Diluted
Tax Impact Tax Earnings
per Share
Reported Net Income (GAAP) 9,901 (2,142) 7,759 13.22
Adjustments:
Losses on Mark-to-Market Financial Commodity Derivative Contracts, Net 3,982 (858) 3,124 5.32
Net Cash Payments for Settlements of Financial Commodity Derivative Contracts (1) (3,501) 755 (2,746) (4.68)
Less: Gains on Asset Dispositions, Net (74) 17 (57) (0.10)
Add: Certain Impairments 113 (31) 82 0.14
Less: Severance Tax Refund (115) 25 (90) (0.15)
Add: Severance Tax Consulting Fees 16 (3) 13 0.02
Less: Interest on Severance Tax Refund (7) 2 (5) (0.01)
Adjustments to Net Income 414 (93) 321 0.54
Adjusted Net Income (Non-GAAP) 10,315 (2,235) 8,080 13.76
Average Number of Common Shares (Non-GAAP)
Basic 583
Diluted 587
| |
| (1) Consistent with its customary practice, in calculating Adjusted Net Income (Loss) (non-GAAP), EOG subtracts from reported Net Income (Loss) (GAAP) the total net cash paid for settlements of financial commodity derivative contracts during such period. For the twelve months ended December 31, 2022, such amount was $3,501 million, of which $1,391 million was related to the early termination of certain contracts.
| |
| 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 2023 Net Income per Share (GAAP) 3.48
Realized Price
4Q 2023 Composite Average Wellhead Revenue per Boe 48.27
Less: 3Q 2023 Composite Average Wellhead Revenue per Boe (50.46)
Subtotal (2.19)
Multiplied by: 4Q 2023 Crude Oil Equivalent Volumes (MMBoe) 94.4
Total Change in Revenue (207)
Less: Income Tax Benefit (Provision) Imputed (based on 22%) 46
Change in Net Income (161)
Change in Diluted Earnings per Share (0.28)
Wellhead Volumes
4Q 2023 Crude Oil Equivalent Volumes (MMBoe) 94.4
Less: 3Q 2023 Crude Oil Equivalent Volumes (MMBoe) (91.9)
Subtotal 2.5
Multiplied by: 4Q 2023 Composite Average Margin per Boe (GAAP) (Including Total 23.07
Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent" schedule)
Change in Margin 58
Less: Income Tax Benefit (Provision) Imputed (based on 22%) (13)
Change in Net Income 45
Change in Diluted Earnings per Share 0.08
Certain Operating Costs per Boe
3Q 2023 Total Cash Operating Costs (GAAP) and Total DD&A per Boe 19.97
Less: 4Q 2023 Total Cash Operating Costs (GAAP) and Total DD&A per Boe (20.37)
Subtotal (0.40)
Multiplied by: 4Q 2023 Crude Oil Equivalent Volumes (MMBoe) 94.4
Change in Before-Tax Net Income (38)
Less: Income Tax Benefit (Provision) Imputed (based on 22%) 8
Change in Net Income (30)
Change in Diluted Earnings per Share (0.05)
| |
| 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 Derivative Contracts, Net
4Q 2023 Net Gains (Losses) on Mark-to-Market Financial Commodity Derivative Contracts 298
Less: Income Tax Benefit (Provision) (64)
After Tax - (a) 234
Less: 3Q 2023 Net Gains (Losses) on Mark-to-Market Financial Commodity Derivative Contracts 43
Less: Income Tax Benefit (Provision) (9)
After Tax - (b) 34
Change in Net Income - (a) - (b) 200
Change in Diluted Earnings per Share 0.34
Other (1) (0.15)
4Q 2023 Net Income per Share (GAAP) 3.42
4Q 2023 Average Number of Common Shares (GAAP) - Diluted 581
| |
| (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 2022 Net Income per Share (GAAP) 13.22
Realized Price
FY 2023 Composite Average Wellhead Revenue per Boe 48.34
Less: FY 2022 Composite Average Wellhead Revenue per Boe (68.77)
Subtotal (20.43)
Multiplied by: FY 2023 Crude Oil Equivalent Volumes (MMBoe) 359.4
Total Change in Revenue (7,343)
Less: Income Tax Benefit (Provision) Imputed (based on 22%) 1,615
Change in Net Income (5,728)
Change in Diluted Earnings per Share (9.81)
Wellhead Volumes
FY 2023 Crude Oil Equivalent Volumes (MMBoe) 359.4
Less: FY 2022 Crude Oil Equivalent Volumes (MMBoe) (331.5)
Subtotal 27.9
Multiplied by: FY 2023 Composite Average Margin per Boe (GAAP) (Including Total 23.24
Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent"
schedule)
Change in Margin 648
Less: Income Tax Benefit (Provision) Imputed (based on 22%) (143)
Change in Net Income 505
Change in Diluted Earnings per Share 0.86
Certain Operating Costs per Boe
FY 2022 Total Cash Operating Costs (GAAP) and Total DD&A per Boe 21.21
Less: FY 2023 Total Cash Operating Costs (GAAP) and Total DD&A per Boe (20.05)
Subtotal 1.16
Multiplied by: FY 2023 Crude Oil Equivalent Volumes (MMBoe) 359.4
Change in Before-Tax Net Income 417
Less: Income Tax Benefit (Provision) Imputed (based on 22%) (92)
Change in Net Income 325
Change in Diluted Earnings per Share 0.56
| |
| 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 Derivative Contracts, Net
FY 2023 Net Gains (Losses) on Mark-to-Market Financial Commodity Derivative Contracts 818
Less: Income Tax Benefit (Provision) (176)
After Tax - (a) 642
Less: FY 2022 Net Gains (Losses) on Mark-to-Market Commodity Derivative Contracts (3,982)
Less: Income Tax Benefit (Provision) 858
After Tax - (b) (3,124)
Change in Net Income - (a) - (b) 3,766
Change in Diluted Earnings per Share 6.45
Other (1) 1.72
FY 2023 Net Income per Share (GAAP) 13.00
FY 2023 Average Number of Common Shares (GAAP) - Diluted 584
| |
| (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 2023 Adjusted Net Income per Share (Non-GAAP) 3.44
Realized Price
4Q 2023 Composite Average Wellhead Revenue per Boe 48.27
Less: 3Q 2023 Composite Average Wellhead Revenue per Boe (50.46)
Subtotal (2.19)
Multiplied by: 4Q 2023 Crude Oil Equivalent Volumes (MMBoe) 94.4
Total Change in Revenue (207)
Less: Income Tax Benefit (Provision) Imputed (based on 22%) 46
Change in Net Income (161)
Change in Diluted Earnings per Share (0.28)
Wellhead Volumes
4Q 2023 Crude Oil Equivalent Volumes (MMBoe) 94.4
Less: 3Q 2023 Crude Oil Equivalent Volumes (MMBoe) (91.9)
Subtotal 2.5
Multiplied by: 4Q 2023 Composite Average Margin per Boe (Non-GAAP) (Including Total 23.27
Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil Equivalent"
schedule)
Change in Margin 58
Less: Income Tax Benefit (Provision) Imputed (based on 22%) (13)
Change in Net Income 45
Change in Diluted Earnings per Share 0.08
Certain Operating Costs per Boe
3Q 2023 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe 19.97
Less: 4Q 2023 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe (20.37)
Subtotal (0.40)
Multiplied by: 4Q 2023 Crude Oil Equivalent Volumes (MMBoe) 94.4
Change in Before-Tax Net Income (38)
Less: Income Tax Benefit (Provision) Imputed (based on 22%) 8
Change in Net Income (30)
Change in Diluted Earnings per Share (0.05)
| |
| 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 2023 Net Cash Received from (Payments for) Settlement of Financial Commodity Derivative Contracts 18
Less: Income Tax Benefit (Provision) (4)
After Tax - (a) 14
3Q 2023 Net Cash Received from (Payments for) Settlement of Financial Commodity Derivative Contracts 23
Less: Income Tax Benefit (Provision) (5)
After Tax - (b) 18
Change in Net Income - (a) - (b) (4)
Change in Diluted Earnings per Share (0.01)
Other (1) (0.11)
4Q 2023 Adjusted Net Income per Share (Non-GAAP) 3.07
4Q 2023 Average Number of Common Shares (Non-GAAP) - Diluted 581
| |
| (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 2022 Adjusted Net Income per Share (Non-GAAP) 13.76
Realized Price
FY 2023 Composite Average Wellhead Revenue per Boe 48.34
Less: FY 2022 Composite Average Wellhead Revenue per Boe (68.77)
Subtotal (20.43)
Multiplied by: FY 2023 Crude Oil Equivalent Volumes (MMBoe) 359.4
Total Change in Revenue (7,343)
Less: Income Tax Benefit (Provision) Imputed (based on 22%) 1,615
Change in Net Income (5,728)
Change in Diluted Earnings per Share (9.81)
Wellhead Volumes
FY 2023 Crude Oil Equivalent Volumes (MMBoe) 359.4
Less: FY 2022 Crude Oil Equivalent Volumes (MMBoe) (331.5)
Subtotal 27.9
Multiplied by: FY 2023 Composite Average Margin per Boe (Non-GAAP) 23.36
(Including Total Exploration Costs) (refer to "Revenues, Costs and Margins Per Barrel of Oil
Equivalent" schedule)
Change in Margin 652
Less: Income Tax Benefit (Provision) Imputed (based on 22%) (143)
Change in Net Income 509
Change in Diluted Earnings per Share 0.87
Certain Operating Costs per Boe
FY 2022 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe 21.16
Less: FY 2023 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe (20.05)
Subtotal 1.11
Multiplied by: FY 2023 Crude Oil Equivalent Volumes (MMBoe) 359.4
Change in Before-Tax Net Income 399
Less: Income Tax Benefit (Provision) Imputed (based on 22%) (88)
Change in Net Income 311
Change in Diluted Earnings per Share 0.53
| |
| 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 2023 Net Cash Received from (Payments for) Settlement of Financial Commodity Derivative Contracts (112)
Less: Income Tax Benefit (Provision) 24
After Tax - (a) (88)
FY 2022 Net Cash Received from (Payments for) Settlement of Financial Commodity Derivative Contracts (3,501)
Less: Income Tax Benefit (Provision) 755
After Tax - (b) (2,746)
Change in Net Income - (a) - (b) 2,658
Change in Diluted Earnings per Share 4.55
Other (1) 1.79
FY 2023 Adjusted Net Income per Share (Non-GAAP) 11.69
FY 2023 Average Number of Common Shares (Non-GAAP) - Diluted 584
| |
| (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.
2022 2023
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) 828 2,048 4,773 3,444 11,093 3,255 2,277 2,704 3,104 11,340
Adjustments:
Changes in Components of Working Capital
and Other Assets and Liabilities
Accounts Receivable 878 522 (392) (661) 347 (338) (137) 714 (201) 38
Inventories 14 157 140 223 534 77 226 28 (100) 231
Accounts Payable (130) (259) 88 211 (90) 77 231 (238) 49 119
Accrued Taxes Payable (613) 536 53 137 113 (232) 212 (180) 139 (61)
Other Assets 213 (71) 129 93 364 (52) (43) 92 (36) (39)
Other Liabilities 2,250 (433) (1,269) (282) 266 (193) 47 (54) 16 (184)
Changes in Components of Working Capital (68) (143) (90) (74) (375) (35) (250) (28) 18 (295)
Associated with Investing Activities
Cash Flow from Operations Before Changes in 3,372 2,357 3,432 3,091 12,252 2,559 2,563 3,038 2,989 11,149
Working Capital (Non-GAAP)
Cash Flow from Operations Before Changes in 3,372 2,357 3,432 3,091 12,252 2,559 2,563 3,038 2,989 11,149
Working Capital (Non-GAAP)
Less:
Total Capital Expenditures (Non-GAAP) (a) (1,009) (1,071) (1,166) (1,361) (4,607) (1,489) (1,521) (1,519) (1,512) (6,041)
Free Cash Flow (Non-GAAP) 2,363 1,286 2,266 1,730 7,645 1,070 1,042 1,519 1,477 5,108
(a) See below reconciliation of Total Expenditures (GAAP) to Total Capital Expenditures (Non-GAAP):
2022 2023
1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year
Total Expenditures (GAAP) 1,144 1,521 1,410 1,535 5,610 1,717 1,664 1,803 1,634 6,818
Less:
Asset Retirement Costs (27) (43) (139) (89) (298) (10) (26) (191) (30) (257)
Non-Cash Acquisition Costs of (58) (21) (28) (20) (127) (31) (28) (1) (39) (99)
Unproved Properties
Non-Cash Development Drilling — — — — — — (35) (50) (5) (90)
Acquisition Costs of Proved Properties (5) (351) (42) (21) (419) (4) (6) 1 (7) (16)
Acquisition Costs of Other Property, — — — — — (133) (1) — — (134)
Plant and Equipment
Exploration Costs (45) (35) (35) (44) (159) (50) (47) (43) (41) (181)
Total Capital Expenditures (Non-GAAP) 1,009 1,071 1,166 1,361 4,607 1,489 1,521 1,519 1,512 6,041
| |
| 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,
2023 2023 2023 2023 2022
Total Stockholders' Equity - (a) 28,090 27,758 26,257 25,447 24,779
Current and Long-Term Debt (GAAP) - (b) 3,799 3,806 3,814 3,820 5,078
Less: Cash (5,278) (5,326) (4,764) (5,018) (5,972)
Net Debt (Non-GAAP) - (c) (1,479) (1,520) (950) (1,198) (894)
Total Capitalization (GAAP) - (a) + (b) 31,889 31,564 30,071 29,267 29,857
Total Capitalization (Non-GAAP) - (a) + (c) 26,611 26,238 25,307 24,249 23,885
Debt-to-Total Capitalization (GAAP) - (b) / [(a) + (b)] 11.9% 12.1% 12.7% 13.1% 17.0%
Net Debt-to-Total Capitalization (Non-GAAP) - (c) / [(a) + (c)] -5.6% -5.8% -3.8% -4.9% -3.7%
| |
| Proved Reserves and Reserve Replacement Data
(Unaudited)
2023 Net Proved Reserves Reconciliation Summary United Trinidad Other Total
States International
Crude Oil and Condensate (MMBbl)
Beginning Reserves 1,659 2 — 1,661
Revisions 56 — — 56
Purchases in Place 1 — — 1
Extensions, Discoveries and Other Additions 219 — — 219
Sales in Place (7) — — (7)
Production (174) — — (174)
Ending Reserves 1,754 2 — 1,756
Natural Gas Liquids (MMBbl)
Beginning Reserves 1,145 — — 1,145
Revisions 26 — — 26
Purchases in Place 1 — — 1
Extensions, Discoveries and Other Additions 169 — — 169
Sales in Place (5) — — (5)
Production (82) — — (82)
Ending Reserves 1,254 — — 1,254
Natural Gas (Bcf)
Beginning Reserves 8,273 318 — 8,591
Revisions (327) 12 — (315)
Purchases in Place 3 — — 3
Extensions, Discoveries and Other Additions 1,287 29 — 1,316
Sales in Place (28) — — (28)
Production (578) (59) — (637)
Ending Reserves 8,630 300 — 8,930
Oil Equivalents (MMBoe)
Beginning Reserves 4,183 55 — 4,238
Revisions 28 1 — 29
Purchases in Place 2 — — 2
Extensions, Discoveries and Other Additions 602 5 — 607
Sales in Place (17) — — (17)
Production (351) (10) — (361)
Ending Reserves 4,447 51 — 4,498
Net Proved Developed Reserves (MMBoe)
At December 31, 2022 2,162 23 — 2,185
At December 31, 2023 2,322 27 — 2,349
2023 Exploration and Development Expenditures ($ Millions)
Acquisition Cost of Unproved Properties 207 — — 207
Exploration Costs 370 53 14 437
Development Costs 4,987 114 — 5,101
Total Drilling 5,564 167 14 5,745
Acquisition Cost of Proved Properties 16 — — 16
Asset Retirement Costs 241 3 13 257
Total Exploration and Development Expenditures 5,821 170 27 6,018
Gathering, Processing and Other 799 1 — 800
Total Expenditures 6,620 171 27 6,818
Proceeds from Sales in Place (70) (70) — (140)
Net Expenditures 6,550 101 27 6,678
Reserve Replacement Costs ($ / Boe) *
All-in Total, Net of Revisions 8.26 27.17 — 8.44
All-in Total, Excluding Revisions Due to Price 7.03 27.17 — 7.20
Reserve Replacement *
Drilling Only 172% 50% 0% 168%
All-in Total, Net of Revisions and Dispositions 175% 60% 0% 172%
All-in Total, Excluding Revisions Due to Price 207% 60% 0% 202%
All-in Total, Liquids 180% 0% 0% 180%
| |
|
* See following reconciliation schedule for calculation methodology
| |
| Reserve Replacement Cost Data
(Unaudited; in millions, except ratio data)
For the Twelve Months Ended December 31, 2023 United Trinidad Other Total
States International
Total Costs Incurred in Exploration and Development Activities (GAAP) 5,821 170 27 6,018
Less: Asset Retirement Costs (241) (3) (13) (257)
Non-Cash Acquisition Costs of Unproved Properties (99) — — (99)
Total Acquisition Costs of Proved Properties (16) — — (16)
Non-Cash Development Drilling (90) — — (90)
Exploration Expenses (166) (4) (11) (181)
Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) - (a) 5,209 163 3 5,375
Total Costs Incurred in Exploration and Development Activities (GAAP) 5,821 170 27 6,018
Less: Asset Retirement Costs (241) (3) (13) (257)
Non-Cash Acquisition Costs of Unproved Properties (99) — — (99)
Non-Cash Acquisition Costs of Proved Properties (6) — — (6)
Non-Cash Development Drilling (90) — — (90)
Exploration Expenses (166) (4) (11) (181)
Total Exploration and Development Expenditures (Non-GAAP) - (b) 5,219 163 3 5,385
Total Expenditures (GAAP) 6,620 171 27 6,818
Less: Asset Retirement Costs (241) (3) (13) (257)
Non-Cash Acquisition Costs of Unproved Properties (99) — — (99)
Non-Cash Acquisition Costs of Proved Properties (6) — — (6)
Non-Cash Development Drilling (90) — — (90)
Exploration Expenses (166) (4) (11) (181)
Total Cash Expenditures (Non-GAAP) 6,018 164 3 6,185
Net Proved Reserve Additions From All Sources - Oil Equivalents (MMBoe)
Revisions Due to Price - (c) (110) — — (110)
Revisions Other Than Price 138 1 — 139
Purchases in Place 2 — — 2
Extensions, Discoveries and Other Additions - (d) 602 5 — 607
Total Proved Reserve Additions - (e) 632 6 — 638
Sales in Place (17) — — (17)
Net Proved Reserve Additions From All Sources - (f) 615 6 — 621
Production - (g) 351 10 — 361
Reserve Replacement Costs ($ / Boe)
Total Drilling, Before Revisions - (a / d) 8.65 32.60 — 8.86
All-in Total, Net of Revisions - (b / e) 8.26 27.17 — 8.44
All-in Total, Excluding Revisions Due to Price - (b / (e - c)) 7.03 27.17 — 7.20
Reserve Replacement
Drilling Only - (d / g) 172% 50% 0% 168%
All-in Total, Net of Revisions and Dispositions - (f / g) 175% 60% 0% 172%
All-in Total, Excluding Revisions Due to Price - ((f - c) / g) 207% 60% 0% 202%
Reserve Replacement Cost Data
(Continued)
(Unaudited; in millions, except ratio data)
For the Twelve Months Ended December 31, 2023 United Trinidad Other Total
States International
Net Proved Reserve Additions From All Sources - Liquids (MMBbl)
Revisions 82 — — 82
Purchases in Place 2 — — 2
Extensions, Discoveries and Other Additions - (h) 388 — — 388
Total Proved Reserve Additions 472 — — 472
Sales in Place (12) — — (12)
Net Proved Reserve Additions From All Sources - (i) 460 — — 460
Production - (j) 256 — — 256
Reserve Replacement - Liquids
Drilling Only - (h / j) 152% 0% 0% 152%
All-in Total, Net of Revisions and Dispositions - (i / j) 180% 0% 0% 180%
| |
| Reserve Replacement Cost Data
(Continued)
(Unaudited; in millions, except ratio data)
For the Twelve Months Ended December 31, 2023
Proved Developed Reserve Replacement Costs ($ / Boe) Total
Total Costs Incurred in Exploration and Development Activities (GAAP) - (k) 6,018
Less: Asset Retirement Costs (257)
Acquisition Costs of Unproved Properties (207)
Acquisition Costs of Proved Properties (16)
Exploration Expenses (181)
Drillbit Exploration and Development Expenditures (Non-GAAP) - (l) 5,357
Total Proved Reserves - Extensions, Discoveries and Other Additions (MMBoe) 607
Add: Conversion of Proved Undeveloped Reserves to Proved Developed 360
Less: Proved Undeveloped Extensions and Discoveries (516)
Proved Developed Reserves - Extensions and Discoveries (MMBoe) 451
Total Proved Reserves - Revisions (MMBoe) 29
Less: Proved Undeveloped Reserves - Revisions 51
Proved Developed - Revisions Due to Price 42
Proved Developed Reserves - Revisions Other Than Price (MMBoe) 122
Proved Developed Reserves - Extensions and Discoveries Plus Revisions Other Than Price (MMBoe) - (m) 573
Proved Developed Reserve Replacement Costs Excluding Revisions Due to Price ($ / Boe) (GAAP) - (k / m) 10.50
Proved Developed Reserve Replacement Costs Excluding Revisions Due to Price ($ / Boe) (Non-GAAP) - (l / m) 9.35
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| 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. In addition, to further the comparability of the results of EOG's current-year capital investment program with those of EOG's peer companies and other companies in the industry, EOG now deducts Exploration Expenses, as illustrated below, in calculating Total Exploration and Development Expenditures for Drilling Only (Non-GAAP), Total Exploration and Development Expenditures (Non-GAAP), Total Cash Expenditures (Non-GAAP), Drillbit Exploration and Development Expenditures (Non-GAAP) and the related Reserve Replacement Costs metrics. Accordingly, Total Exploration and Development Expenditures for Drilling Only (Non-GAAP), Total Exploration and Development Expenditures (Non-GAAP), Total Cash Expenditures (Non-GAAP), Drillbit Exploration and Development Expenditures (Non-GAAP) and the related Reserve Replacement Costs metrics, in each case for fiscal year 2023 and 2022, have been calculated on such basis, and the calculations for each of the prior periods shown have been revised and conformed.
2023 2022 2021
Total Costs Incurred in Exploration and Development Activities (GAAP) 6,018 5,229 3,969
Less: Asset Retirement Costs (257) (298) (127)
Non-Cash Acquisition Costs of Unproved Properties (99) (127) (45)
Total Acquisition Costs of Proved Properties (16) (419) (100)
Non-Cash Development Drilling (90) — —
Exploration Expenses (181) (159) (154)
Total Exploration and Development Expenditures for Drilling Only (Non-GAAP) - (a) 5,375 4,226 3,543
Total Costs Incurred in Exploration and Development Activities (GAAP) - (b) 6,018 5,229 3,969
Less: Asset Retirement Costs (257) (298) (127)
Non-Cash Acquisition Costs of Unproved Properties (99) (127) (45)
Non-Cash Acquisition Costs of Proved Properties (6) (26) (5)
Non-Cash Development Drilling (90) — —
Exploration Expenses (181) (159) (154)
Total Exploration and Development Expenditures (Non-GAAP) - (c) 5,385 4,619 3,638
Net Proved Reserve Additions From All Sources - Oil Equivalents (MMBoe)
Revisions Due to Price - (d) (110) 11 194
Revisions Other Than Price 139 325 (308)
Purchases in Place 2 16 9
Extensions, Discoveries and Other Additions - (e) 607 560 952
Total Proved Reserve Additions - (f) 638 912 847
Sales in Place (17) (88) (11)
Net Proved Reserve Additions From All Sources 621 824 836
Production 361 333 309
Reserve Replacement Costs ($ / Boe)
Total Drilling, Before Revisions - (a / e) 8.86 7.55 3.72
All-in Total, Net of Revisions - (c / f) 8.44 5.06 4.30
All-in Total, Excluding Revisions Due to Price (GAAP) - (b / ( f - d)) 8.05 5.80 6.08
All-in Total, Excluding Revisions Due to Price (Non-GAAP) - (c / ( f - d)) 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
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| Definitions
$/Boe U.S. Dollars per barrel of oil equivalent
MMBoe Million barrels of oil equivalent
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SOURCE EOG Resources, Inc.
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