[[{“value”:”
HOUSTON, Feb. 22, 2024 /PRNewswire/ — 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
4Q 2022
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
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 $6.2 billion capital plan to grow oil production 3% and total production 7%
Volumes and Capital Expenditures
4Q 2023
4Q 2023
Guidance
Midpoint
3Q 2023
2Q 2023
1Q 2023
4Q 2022
FY 2023
FY 2022
Wellhead Volumes
Crude Oil and Condensate (MBod)
485.2
483.5
483.3
476.6
457.7
465.6
475.8
461.3
Natural Gas Liquids (MBbld)
235.8
234.0
231.1
215.7
212.2
189.0
223.8
197.7
Natural Gas (MMcfd)
1,831
1,785
1,704
1,668
1,639
1,527
1,711
1,495
Total Crude Oil Equivalent (MBoed)
1,026.2
1,015.0
998.5
970.3
943.0
909.1
984.8
908.2
Capital Expenditures ($MM)
1,512
1,500
1,519
1,521
1,489
1,361
6,041
4,607
From Ezra Yacob, Chairman and Chief Executive Officer
“EOG continues to deliver on its value proposition as demonstrated by our strong execution in 2023. Oil and total 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 in EOG’s ability to compete across sectors, create value for our shareholders, and be part of the long-term energy solution has never been higher.”
Fourth Quarter 2023 Financial Performance
Prices
Crude oil and NGL 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, while LOE and transportation costs decreased
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 Cash Flow
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 higher LOE 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 per share.
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 per Boe (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 $400 million in strategic infrastructure projects associated with EOG’s Delaware Basin and Dorado assets. These projects are expected to provide several long-term benefits to the company, including margin improvement through higher price realizations and lower operating costs.
Brent-Linked Gas Sales Agreement
EOG entered into a 10-year Brent-linked gas sales agreement. Starting in January 2027, the company will have sales volumes of 140K MMBtu per day linked to Brent crude oil prices with an additional 40K MMBtu per day linked to Brent crude oil prices or a US Gulf Coast gas index. This latest agreement complements existing agreements in providing additional pricing diversification for gas volumes sourced across several basins within EOG’s multi-basin portfolio.
Fourth Quarter 2023 Results vs Guidance
(Unaudited)
See “Endnotes” below for related discussion and definitions.
4Q 2023
4Q 2023
Guidance
Midpoint
Variance
3Q 2023
2Q 2023
1Q 2023
4Q 2022
Crude Oil and Condensate Volumes (MBod)
United States
484.6
483.1
1.5
482.8
476.0
457.1
465.1
Trinidad
0.6
0.4
0.2
0.5
0.6
0.6
0.5
Other International
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Total
485.2
483.5
1.7
483.3
476.6
457.7
465.6
Natural Gas Liquids Volumes (MBbld)
Total
235.8
234.0
1.8
231.1
215.7
212.2
189.0
Natural Gas Volumes (MMcfd)
United States
1,653
1,615
38
1,562
1,513
1,475
1,378
Trinidad
178
170
8
142
155
164
149
Other International
0
0
0
0
0
0
0
Total
1,831
1,785
46
1,704
1,668
1,639
1,527
Total Crude Oil Equivalent Volumes (MBoed)
1,026.2
1,015.0
11.2
998.5
970.3
943.0
909.1
Total MMBoe
94.4
93.4
1.0
91.9
88.3
84.9
83.6
Benchmark Price
Oil (WTI) ($/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 ($MM)
352
330
22
486
241
338
409
First Quarter and Full-Year 2024 Guidance7
(Unaudited)
See “Endnotes” below for related discussion and definitions.
1Q 2024
Guidance Range
1Q 2024
Midpoint
FY 2024
Guidance Range
FY 2024
Midpoint
2023
Actual
2022
Actual
2021
Actual
Crude Oil and Condensate Volumes (MBod)
United States
483.0
–
489.0
486.0
485.0
–
490.0
487.5
475.2
460.7
443.4
Trinidad
0.1
–
0.5
0.3
0.5
–
1.5
1.0
0.6
0.6
1.5
Other International
0.0
–
0.0
0.0
0.0
–
0.0
0.0
0.0
0.0
0.1
Total
483.1
–
489.5
486.3
485.5
–
491.5
488.5
475.8
461.3
445.0
Natural Gas Liquids Volumes (MBbld)
Total
223.0
–
233.0
228.0
220.0
–
250.0
235.0
223.8
197.7
144.5
Natural Gas Volumes (MMcfd)
United States
1,625
–
1,675
1,650
1,630
–
1,830
1,730
1,551
1,315
1,210
Trinidad
170
–
200
185
210
–
240
225
160
180
217
Other International
0
–
0
0
0
–
0
0
0
0
9
Total
1,795
–
1,875
1,835
1,840
–
2,070
1,955
1,711
1,495
1,436
Crude Oil Equivalent Volumes (MBoed)
United States
976.8
–
1,001.2
989.0
976.7
–
1,045.0
1,010.9
957.5
877.5
789.6
Trinidad
28.4
–
33.8
31.1
35.5
–
41.5
38.5
27.3
30.7
37.7
Other International
0.0
–
0.0
0.0
0.0
–
0.0
0.0
0.0
0.0
1.6
Total
1,005.2
–
1,035.0
1,020.1
1,012.2
–
1,086.5
1,049.4
984.8
908.2
828.9
Benchmark Price
Oil (WTI) ($/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
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) reconciliation schedule.
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 Day Settle 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 and Tobago 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 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 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 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 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
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
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 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, safety matters or other ESG (environmental/social/governance) 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, 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 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 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 at www.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
Contracts, Net
(2,820)
(1,377)
(18)
233
(3,982)
376
101
43
298
818
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
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
(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.
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
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
Commodity Derivative Contracts
(296)
(2,114)
(847)
(244)
(3,501)
(123)
(30)
23
18
(112)
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
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 (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
Tax
Income Tax
Impact
After
Tax
Diluted
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
(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.
Adjusted Net Income (Loss)
(Continued)
In millions of USD, except share data (in millions) and per share data (Unaudited)
3Q 2023
Before
Tax
Income Tax
Impact
After
Tax
Diluted
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
(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.
Adjusted Net Income (Loss)
(Continued)
In millions of USD, except share data (in millions) and per share data (Unaudited)
2Q 2023
Before
Tax
Income Tax
Impact
After
Tax
Diluted
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
Tax
Income Tax
Impact
After
Tax
Diluted
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
Tax
Income Tax
Impact
After
Tax
Diluted
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
Tax
Income Tax
Impact
After
Tax
Diluted
Earnings
per Share
Reported Net Income (GAAP)
9,689
(2,095)
7,594
13.00
Adjustments:
Gains on Mark-to-Market Financial Commodity Derivative Contracts, Net
(818)
176
(642)
(1.09)
Net Cash Payments for Settlements of Financial Commodity Derivative Contracts (1)
(112)
24
(88)
(0.15)
Less: Gains on Asset Dispositions, Net
(95)
20
(75)
(0.13)
Add: Certain Impairments
42
(6)
36
0.06
Adjustments to Net Income
(983)
214
(769)
(1.31)
Adjusted Net Income (Non-GAAP)
8,706
(1,881)
6,825
11.69
Average Number of Common Shares (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
Tax
Income Tax
Impact
After
Tax
Diluted
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
Exploration Costs) (refer to “Revenues, Costs and Margins Per Barrel of Oil Equivalent” schedule)
23.07
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
Exploration Costs) (refer to “Revenues, Costs and Margins Per Barrel of Oil Equivalent”
schedule)
23.24
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
Exploration Costs) (refer to “Revenues, Costs and Margins Per Barrel of Oil Equivalent”
schedule)
23.27
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)
(Including Total Exploration Costs) (refer to “Revenues, Costs and Margins Per Barrel of Oil
Equivalent” schedule)
23.36
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
Associated with Investing Activities
(68)
(143)
(90)
(74)
(375)
(35)
(250)
(28)
18
(295)
Cash Flow from Operations Before Changes in
Working Capital (Non-GAAP)
3,372
2,357
3,432
3,091
12,252
2,559
2,563
3,038
2,989
11,149
Cash Flow from Operations Before Changes in
Working Capital (Non-GAAP)
3,372
2,357
3,432
3,091
12,252
2,559
2,563
3,038
2,989
11,149
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
Unproved Properties
(58)
(21)
(28)
(20)
(127)
(31)
(28)
(1)
(39)
(99)
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,
Plant and Equipment
–
–
–
–
–
(133)
(1)
–
–
(134)
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,
2023
September 30,
2023
June 30,
2023
March 31,
2023
December 31,
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
States
Trinidad
Other
International
Total
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
States
Trinidad
Other
International
Total
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
States
Trinidad
Other
International
Total
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
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
Definitions
$/Boe
U.S. Dollars per barrel of oil equivalent
MMBoe
Million barrels of oil equivalent
View original content:https://www.prnewswire.com/news-releases/eog-resources-reports-fourth-quarter-and-full-year-2023-results-announces-2024-capital-plan-302069260.html
SOURCE EOG Resources, Inc.
The post EOG Resources Reports Fourth Quarter and Full-Year 2023 Results; Announces 2024 Capital Plan appeared first on Energy News Beat.
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