HOUSTON, Nov. 2, 2023 /PRNewswire/ — EOG Resources, Inc. (EOG) today reported third quarter 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.
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Key Financial Results |
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In millions of USD, except per-share, per-Boe and ratio data |
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|
GAAP |
3Q 2023 |
2Q 2023 |
1Q 2023 |
4Q 2022 |
3Q 2022 |
|
|
Total Revenue |
6,212 |
5,573 |
6,044 |
6,719 |
7,593 |
|
|
Net Income |
2,030 |
1,553 |
2,023 |
2,277 |
2,854 |
|
|
Net Income Per Share |
3.48 |
2.66 |
3.45 |
3.87 |
4.86 |
|
|
Net Cash Provided by Operating Activities |
2,704 |
2,277 |
3,255 |
3,444 |
4,773 |
|
|
Total Expenditures |
1,803 |
1,664 |
1,717 |
1,535 |
1,410 |
|
|
Current and Long-Term Debt |
3,806 |
3,814 |
3,820 |
5,078 |
5,084 |
|
|
Cash and Cash Equivalents |
5,326 |
4,764 |
5,018 |
5,972 |
5,272 |
|
|
Debt-to-Total Capitalization |
12.1 % |
12.7 % |
13.1 % |
17.0 % |
17.6 % |
|
|
Cash Operating Costs ($/Boe) |
10.19 |
10.03 |
10.59 |
10.82 |
10.89 |
|
|
General and Administrative Costs ($/Boe) |
1.75 |
1.61 |
1.71 |
1.87 |
1.92 |
|
|
Non – GAAP |
||||||
|
Adjusted Net Income |
2,007 |
1,457 |
1,578 |
1,941 |
2,179 |
|
|
Adjusted Net Income Per Share |
3.44 |
2.49 |
2.69 |
3.30 |
3.71 |
|
|
CFO before Changes in Working Capital |
3,038 |
2,563 |
2,559 |
3,091 |
3,432 |
|
|
Capital Expenditures |
1,519 |
1,521 |
1,489 |
1,361 |
1,166 |
|
|
Free Cash Flow |
1,519 |
1,042 |
1,070 |
1,730 |
2,266 |
|
|
Net Debt |
(1,520) |
(950) |
(1,198) |
(894) |
(188) |
|
|
Net Debt-to-Total Capitalization |
(5.8 %) |
(3.8 %) |
(4.9 %) |
(3.7 %) |
(0.8 %) |
|
|
Cash Operating Costs ($/Boe)1 |
10.19 |
10.03 |
10.59 |
10.82 |
10.70 |
|
|
General and Administrative Costs ($/Boe)1 |
1.75 |
1.61 |
1.71 |
1.87 |
1.73 |
|
Third Quarter Highlights
Increased 2024+ cash return commitment to minimum 70 percent of annual free cash flow
Increased regular quarterly dividend by 10 percent to $0.91 per share, a $3.64 per share indicated annual rate
Declared special dividend of $1.50 per share
Repurchased $61 million of shares during the third quarter
Earned adjusted net income of $2.0 billion, or $3.44 per share
Generated $1.5 billion of free cash flow
Volumes, capital expenditures, and per-unit operating costs better than guidance midpoints
Updated full-year guidance to reflect higher volumes and lower per-unit operating costs
Volumes and Capital Expenditures
|
Wellhead Volumes |
3Q 2023 |
||||||
|
3Q 2023 |
Guidance |
2Q 2023 |
1Q 2023 |
4Q 2022 |
3Q 2022 |
||
|
Crude Oil and Condensate (MBod) |
483.3 |
472.9 |
476.6 |
457.7 |
465.6 |
465.1 |
|
|
Natural Gas Liquids (MBbld) |
231.1 |
223.0 |
215.7 |
212.2 |
189.0 |
209.3 |
|
|
Natural Gas (MMcfd) |
1,704 |
1,660 |
1,668 |
1,639 |
1,527 |
1,469 |
|
|
Total Crude Oil Equivalent (MBoed) |
998.5 |
972.6 |
970.3 |
943.0 |
909.1 |
919.2 |
|
|
Capital Expenditures ($MM) |
1,519 |
1,660 |
1,521 |
1,489 |
1,361 |
1,166 |
|
From Ezra Yacob, Chairman and Chief Executive Officer”EOG delivered strong third quarter results due to our employees’ outstanding execution in our foundational Delaware Basin and Eagle Ford assets as well as continued progress across our emerging plays. Production volumes, capital expenditures, and per-unit operating costs were each better than expected. As a result, we have updated our full-year guidance to reflect higher volumes and lower per-unit operating costs.
“Substantial cash flow generation this year supported both our industry-leading regular dividend of $1.9 billion and an additional cash return of more than $2.1 billion through special dividends and share repurchases. EOG’s total cash return to shareholders of $4.1 billion represents approximately 75% of our estimated full-year 2023 free cash flow.
“Going forward we are committing more cash to our shareholders. The increase in EOG’s cash return commitment to a minimum 70% of annual free cash flow reflects EOG’s financial strength and is consistent with our free cash flow priorities, which remain focused on creating long-term shareholder value.
“The 10% increase in our regular dividend demonstrates our confidence in EOG’s future and our ability to support the higher dividend throughout commodity price cycles. Strong results quarter after quarter reflect continued improvement across EOG’s low-cost, multi-basin portfolio, and our commitment to a sustainable, growing dividend is further supported by an industry-leading balance sheet. EOG is in a better position than ever to deliver value for our shareholders and play a significant role in the long-term future of energy.”
Third Quarter 2023 Financial Performance
Prices
Crude oil, NGL, and natural gas prices increased in 3Q compared with 2Q
Volumes
Total 3Q oil production of 483,300 Bopd was above the high end of the guidance range and up 1% from 2Q
NGL production was above the high end of the guidance range and up 7% from 2Q
Natural gas production was at the high end of the guidance range and up 2% from 2Q
Total company equivalent production increased 3% from 2Q
Per-Unit Costs
LOE and G&A costs increased in 3Q compared with 2Q, while transportation and DD&A expenses decreased. Gathering and processing costs remained flat.
Hedges
Mark-to-market hedge gains decreased, lowering GAAP earnings per share in 3Q compared with 2Q
Cash received to settle hedges increased 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 $494 million in regular dividends
Repurchased $61 million of stock
Changes in working capital and other items accounted for approximately $400 million of the decrease in cash
Third Quarter 2023 Operating Performance
Lease and Well
QoQ: Increased primarily due to workovers, fuel-related expenses, and water handling costs
Guidance Midpoint: Lower primarily due to employee-related costs and fuel-related expenses
Transportation
QoQ: Decreased primarily due to lower natural gas transportation expenses
Guidance Midpoint: Lower primarily due to oil transportation expenses
Gathering and Processing
QoQ: Flat
Guidance Midpoint: Lower primarily due to fuel costs
General and Administrative
QoQ: Increased primarily due to employee-related expenses
Guidance Midpoint: Lower primarily due to employee-related expenses
Depreciation, Depletion and Amortization
QoQ: Generally flat
Guidance Midpoint: Lower primarily due to the addition of low-cost reserves
Regular Dividend and Additional Cash Return
Regular Dividend Increased 10% to $3.64 per Share Indicated Annual RateThe Board of Directors today declared a dividend of $0.91 per share on EOG’s common stock. The dividend will be payable January 31, 2024, to stockholders of record as of January 17, 2024. The new dividend represents an indicated annual rate of $3.64 per share, a 10% increase from the previous level. EOG has never suspended or reduced its regular dividend.
Declared $1.50 per Share Special DividendThe Board of Directors also today declared a special dividend of $1.50 per share on EOG’s common stock. The special dividend will be payable December 29, 2023, to stockholders of record as of December 15, 2023. EOG has now committed to return $1.5 billion to shareholders in 2023 through special dividends.
Third Quarter Share RepurchasesDuring the third quarter, the company repurchased 0.5 million shares for $61 million under its share repurchase authorization, at an average purchase price of $123 per share.
Year-to-date, the company repurchased 6.2 million shares for $671 million under its share repurchase authorization, at an average purchase price of $108 per share. EOG has $4.3 billion remaining on its current repurchase authorization.
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Third Quarter 2023 Results vs Guidance |
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(Unaudited) |
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See “Endnotes” below for related discussion and definitions. |
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|
3Q 2023 |
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|
3Q 2023 |
Guidance |
Variance |
2Q 2023 |
1Q 2023 |
4Q 2022 |
3Q 2022 |
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|
Crude Oil and Condensate Volumes (MBod) |
|||||||||
|
United States |
482.8 |
472.5 |
10.3 |
476.0 |
457.1 |
465.1 |
464.6 |
||
|
Trinidad |
0.5 |
0.4 |
0.1 |
0.6 |
0.6 |
0.5 |
0.5 |
||
|
Other International |
0.0 |
0.0 |
0.0 |
0.0 |
0.0 |
0.0 |
0.0 |
||
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Total |
483.3 |
472.9 |
10.4 |
476.6 |
457.7 |
465.6 |
465.1 |
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Natural Gas Liquids Volumes (MBbld) |
|||||||||
|
Total |
231.1 |
223.0 |
8.1 |
215.7 |
212.2 |
189.0 |
209.3 |
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|
Natural Gas Volumes (MMcfd) |
|||||||||
|
United States |
1,562 |
1,530 |
32 |
1,513 |
1,475 |
1,378 |
1,306 |
||
|
Trinidad |
142 |
130 |
12 |
155 |
164 |
149 |
163 |
||
|
Other International |
0 |
0 |
0 |
0 |
0 |
0 |
0 |
||
|
Total |
1,704 |
1,660 |
44 |
1,668 |
1,639 |
1,527 |
1,469 |
||
|
Total Crude Oil Equivalent Volumes (MBoed) |
998.5 |
972.6 |
25.9 |
970.3 |
943.0 |
909.1 |
919.2 |
||
|
Total MMBoe |
91.9 |
89.5 |
2.4 |
88.3 |
84.9 |
83.6 |
84.6 |
||
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Benchmark Price |
|||||||||
|
Oil (WTI) ($/Bbl) |
82.18 |
73.75 |
76.11 |
82.63 |
91.64 |
||||
|
Natural Gas (HH) ($/Mcf) |
2.55 |
2.09 |
3.43 |
6.27 |
8.18 |
||||
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Crude Oil and Condensate – above (below) WTI3 ($/Bbl) |
|||||||||
|
United States |
1.43 |
1.00 |
0.43 |
1.23 |
1.16 |
3.05 |
4.41 |
||
|
Trinidad |
(10.80) |
(10.00) |
(0.80) |
(8.87) |
(7.13) |
(7.42) |
(6.66) |
||
|
Natural Gas Liquids – Realizations as % of WTI |
|||||||||
|
Total |
28.7 % |
28.0 % |
0.7 % |
28.3 % |
33.7 % |
34.6 % |
39.3 % |
||
|
Natural Gas – above (below) NYMEX Henry Hub4 ($/Mcf) |
|||||||||
|
United States |
0.04 |
(0.05) |
0.09 |
(0.02) |
0.04 |
(0.15) |
1.17 |
||
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Natural Gas Realizations5 ($/Mcf) |
|||||||||
|
Trinidad |
3.41 |
3.35 |
0.06 |
3.45 |
3.87 |
3.97 |
7.45 |
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Total Expenditures (GAAP) ($MM) |
1,803 |
1,664 |
1,717 |
1,535 |
1,410 |
||||
|
Capital Expenditures (non-GAAP) ($MM) |
1,519 |
1,660 |
(141) |
1,521 |
1,489 |
1,361 |
1,166 |
||
|
Operating Unit Costs ($/Boe) |
|||||||||
|
Lease and Well |
4.02 |
4.20 |
(0.18) |
3.94 |
4.23 |
4.23 |
3.96 |
||
|
Transportation Costs |
2.61 |
2.70 |
(0.09) |
2.67 |
2.78 |
2.83 |
3.04 |
||
|
Gathering and Processing |
1.81 |
1.90 |
(0.09) |
1.81 |
1.87 |
1.89 |
1.97 |
||
|
General and Administrative (GAAP) |
1.75 |
1.90 |
(0.15) |
1.61 |
1.71 |
1.87 |
1.92 |
||
|
General and Administrative (non-GAAP)1 |
1.75 |
1.90 |
(0.15) |
1.61 |
1.71 |
1.87 |
1.73 |
||
|
Cash Operating Costs (GAAP) |
10.19 |
10.70 |
(0.51) |
10.03 |
10.59 |
10.82 |
10.89 |
||
|
Cash Operating Costs (non-GAAP) |
10.19 |
10.70 |
(0.51) |
10.03 |
10.59 |
10.82 |
10.70 |
||
|
Depreciation, Depletion and Amortization |
9.78 |
9.90 |
(0.12) |
9.81 |
9.40 |
10.50 |
10.71 |
||
|
Expenses ($MM) |
|||||||||
|
Exploration and Dry Hole |
43 |
65 |
(22) |
47 |
51 |
48 |
53 |
||
|
Impairment (GAAP) |
54 |
35 |
34 |
142 |
94 |
||||
|
Impairment (excluding certain impairments (non-GAAP))6 |
31 |
100 |
(69) |
35 |
34 |
111 |
48 |
||
|
Capitalized Interest |
8 |
10 |
(2) |
8 |
8 |
11 |
11 |
||
|
Net Interest |
36 |
34 |
2 |
35 |
42 |
42 |
41 |
||
|
TOTI (% of Wellhead Revenue) (GAAP) |
7.4 % |
8.5 % |
(1.1 %) |
7.8 % |
7.8 % |
7.8 % |
5.5 % |
||
|
TOTI (% of Wellhead Revenue) (non-GAAP)1 |
7.4 % |
8.5 % |
(1.1 %) |
7.8 % |
7.8 % |
7.8 % |
7.4 % |
||
|
Income Taxes |
|||||||||
|
Effective Rate |
21.1 % |
21.5 % |
(0.4 %) |
21.9 % |
22.0 % |
20.4 % |
22.1 % |
||
|
Current Tax (Benefit) / Expense ($MM) |
486 |
345 |
141 |
241 |
338 |
409 |
481 |
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|
Fourth Quarter and Full-Year 2023 Guidance7 |
||||||||||||
|
(Unaudited) |
||||||||||||
|
See “Endnotes” below for related discussion and definitions. |
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|
4Q 2023 Guidance Range |
4Q 2023 Midpoint |
FY 2023 Guidance Range |
FY 2023 Midpoint |
2022 Actual |
2021 Actual |
2020 Actual |
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|
Crude Oil and Condensate Volumes (MBod) |
||||||||||||
|
United States |
479.1 |
– |
487.1 |
483.1 |
473.5 |
– |
476.5 |
475.0 |
460.7 |
443.4 |
408.1 |
|
|
Trinidad |
0.2 |
– |
0.6 |
0.4 |
0.3 |
– |
0.5 |
0.4 |
0.6 |
1.5 |
1.0 |
|
|
Other International |
0.0 |
– |
0.0 |
0.0 |
0.0 |
– |
0.0 |
0.0 |
0.0 |
0.1 |
0.1 |
|
|
Total |
479.3 |
– |
487.7 |
483.5 |
473.8 |
– |
477.0 |
475.4 |
461.3 |
445.0 |
409.2 |
|
|
Natural Gas Liquids Volumes (MBbld) |
||||||||||||
|
Total |
230.0 |
– |
238.0 |
234.0 |
222.3 |
– |
224.3 |
223.3 |
197.7 |
144.5 |
136.0 |
|
|
Natural Gas Volumes (MMcfd) |
||||||||||||
|
United States |
1,590 |
– |
1,640 |
1,615 |
1,515 |
– |
1,575 |
1,545 |
1,315 |
1,210 |
1,040 |
|
|
Trinidad |
155 |
– |
185 |
170 |
140 |
– |
170 |
155 |
180 |
217 |
180 |
|
|
Other International |
0 |
– |
0 |
0 |
0 |
– |
0 |
0 |
0 |
9 |
32 |
|
|
Total |
1,745 |
– |
1,825 |
1,785 |
1,655 |
– |
1,745 |
1,700 |
1,495 |
1,436 |
1,252 |
|
|
Crude Oil Equivalent Volumes (MBoed) |
||||||||||||
|
United States |
974.1 |
– |
998.4 |
986.3 |
948.3 |
– |
963.3 |
955.8 |
877.5 |
789.6 |
717.5 |
|
|
Trinidad |
26.0 |
– |
31.4 |
28.7 |
23.6 |
– |
28.8 |
26.2 |
30.7 |
37.7 |
30.9 |
|
|
Other International |
0.0 |
– |
0.0 |
0.0 |
0.0 |
– |
0.0 |
0.0 |
0.0 |
1.6 |
5.4 |
|
|
Total |
1,000.1 |
– |
1,029.8 |
1,015.0 |
971.9 |
– |
992.1 |
982.0 |
908.2 |
828.9 |
753.8 |
|
|
Benchmark Price |
||||||||||||
|
Oil (WTI) ($/Bbl) |
94.23 |
67.96 |
39.40 |
|||||||||
|
Natural Gas (HH) ($/Mcf) |
6.64 |
3.85 |
2.08 |
|||||||||
|
Crude Oil and Condensate – above (below) WTI3 ($/Bbl) |
||||||||||||
|
United States |
1.25 |
– |
2.75 |
2.00 |
1.33 |
– |
1.73 |
1.53 |
2.99 |
0.58 |
(0.75) |
|
|
Trinidad |
(12.00) |
– |
(10.50) |
(11.25) |
(10.50) |
– |
(9.30) |
(9.90) |
(8.07) |
(11.70) |
(9.20) |
|
|
Natural Gas Liquids – Realizations as % of WTI |
||||||||||||
|
Total |
22.0 % |
– |
32.0 % |
27.0 % |
28.0 % |
– |
31.0 % |
29.5 % |
39.0 % |
50.5 % |
34.0 % |
|
|
Natural Gas – above (below) NYMEX Henry Hub4 ($/Mcf) |
||||||||||||
|
United States |
(0.05) |
– |
0.35 |
0.15 |
0.00 |
– |
0.10 |
0.05 |
0.63 |
1.03 |
(0.47) |
|
|
Natural Gas Realizations5 ($/Mcf) |
||||||||||||
|
Trinidad |
3.20 |
– |
3.75 |
3.48 |
3.49 |
– |
3.63 |
3.56 |
4.43 |
3.40 |
2.57 |
|
|
Total Expenditures (GAAP) ($MM) |
5,610 |
4,255 |
4,113 |
|||||||||
|
Capital Expenditures8 (non-GAAP) ($MM) |
1,400 |
– |
1,600 |
1,500 |
5,900 |
– |
6,100 |
6,000 |
4,607 |
3,755 |
3,344 |
|
|
Operating Unit Costs ($/Boe) |
||||||||||||
|
Lease and Well |
3.90 |
– |
4.50 |
4.20 |
4.02 |
– |
4.18 |
4.10 |
4.02 |
3.75 |
3.85 |
|
|
Transportation Costs |
2.50 |
– |
2.80 |
2.65 |
2.64 |
– |
2.72 |
2.68 |
2.91 |
2.85 |
2.66 |
|
|
Gathering and Processing |
1.75 |
– |
2.05 |
1.90 |
1.81 |
– |
1.89 |
1.85 |
1.87 |
1.85 |
1.66 |
|
|
General and Administrative (GAAP) |
1.75 |
– |
2.05 |
1.90 |
1.70 |
– |
1.78 |
1.74 |
1.72 |
1.69 |
1.75 |
|
|
General and Administrative (non-GAAP)1 |
1.67 |
1.69 |
1.75 |
|||||||||
|
Cash Operating Costs (GAAP) |
9.90 |
– |
11.40 |
10.65 |
10.17 |
– |
10.57 |
10.37 |
10.52 |
10.14 |
9.92 |
|
|
Cash Operating Costs (non-GAAP) |
10.47 |
10.14 |
9.92 |
|||||||||
|
Depreciation, Depletion and Amortization |
9.50 |
– |
10.50 |
10.00 |
9.62 |
– |
9.88 |
9.75 |
10.69 |
12.07 |
12.32 |
|
|
Expenses ($MM) |
||||||||||||
|
Exploration and Dry Hole |
25 |
– |
65 |
45 |
165 |
– |
205 |
185 |
204 |
225 |
159 |
|
|
Impairment (GAAP) |
382 |
376 |
2,100 |
|||||||||
|
Impairment (excluding certain impairments (non-GAAP))6 |
65 |
– |
135 |
100 |
165 |
– |
235 |
200 |
269 |
361 |
232 |
|
|
Capitalized Interest |
8 |
– |
12 |
10 |
32 |
– |
36 |
34 |
36 |
33 |
31 |
|
|
Net Interest |
32 |
– |
36 |
34 |
145 |
– |
149 |
147 |
179 |
178 |
205 |
|
|
TOTI (% of Wellhead Revenue) (GAAP) |
6.5 % |
– |
8.5 % |
7.5 % |
7.0 % |
– |
9.0 % |
8.0 % |
7.0 % |
6.8 % |
6.6 % |
|
|
TOTI (% of Wellhead Revenue) (non-GAAP)1 |
7.5 % |
6.8 % |
6.6 % |
|||||||||
|
Income Taxes |
||||||||||||
|
Effective Rate |
19.0 % |
– |
24.0 % |
21.5 % |
19.0 % |
– |
24.0 % |
21.5 % |
21.7 % |
21.4 % |
18.2 % |
|
|
Current Tax (Benefit) / Expense ($MM) |
280 |
– |
380 |
330 |
1,345 |
– |
1,445 |
1,395 |
2,208 |
1,393 |
(61) |
|
Third Quarter 2023 Results WebcastFriday, November 3, 2023, 9:00 a.m. Central time (10:00 a.m. Eastern time) Webcast will be available on EOG’s website for one year. http://investors.eogresources.com/Investors
About EOGEOG Resources, Inc. (NYSE: EOG) is one of the largest crude oil and natural gas exploration and production companies in the United States with proved reserves in the United States and Trinidad. To learn more visit www.eogresources.com.
Investor ContactsPearce Hammond 713-571-4684
Neel Panchal 713-571-4884
Shelby O’Connor 713-571-4560
Media ContactKimberly Ehmer 713-571-4676
|
Endnotes |
||
|
1) |
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 fourth quarter and full year 2023 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. |
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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 |
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, 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, or pay and/or increase dividends 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. Furthermore, this press release and any accompanying disclosures may include or reference certain forward-looking, non-GAAP financial measures, such as free cash flow and cash flow from operations before changes in working capital, and certain related estimates regarding future performance, results and financial position. 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. 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. 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. 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;
the availability, proximity and capacity of, and costs associated with, appropriate gathering, processing, compression, storage, transportation, refining, 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 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, 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 conflict), 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, 2022 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.
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, 2022, 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. In addition, reconciliation schedules and definitions for non-GAAP financial measures can be found on the EOG website at www.eogresources.com.
|
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 |
YTD |
|||
|
Operating Revenues and Other |
||||||||||||
|
Crude Oil and Condensate |
3,889 |
4,699 |
4,109 |
3,670 |
16,367 |
3,182 |
3,252 |
3,717 |
10,151 |
|||
|
Natural Gas Liquids |
681 |
777 |
693 |
497 |
2,648 |
490 |
409 |
501 |
1,400 |
|||
|
Natural Gas |
716 |
1,000 |
1,235 |
830 |
3,781 |
517 |
334 |
417 |
1,268 |
|||
|
Gains (Losses) on Mark-to-Market Financial Commodity Derivative Contracts, Net |
(2,820) |
(1,377) |
(18) |
233 |
(3,982) |
376 |
101 |
43 |
520 |
|||
|
Gathering, Processing and Marketing |
1,469 |
2,169 |
1,561 |
1,497 |
6,696 |
1,390 |
1,465 |
1,478 |
4,333 |
|||
|
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 |
62 |
|||
|
Total |
3,983 |
7,407 |
7,593 |
6,719 |
25,702 |
6,044 |
5,573 |
6,212 |
17,829 |
|||
|
Operating Expenses |
||||||||||||
|
Lease and Well |
318 |
324 |
335 |
354 |
1,331 |
359 |
348 |
369 |
1,076 |
|||
|
Transportation Costs |
228 |
244 |
257 |
237 |
966 |
236 |
236 |
240 |
712 |
|||
|
Gathering and Processing Costs |
144 |
152 |
167 |
158 |
621 |
159 |
160 |
166 |
485 |
|||
|
Exploration Costs |
45 |
35 |
35 |
44 |
159 |
50 |
47 |
43 |
140 |
|||
|
Dry Hole Costs |
3 |
20 |
18 |
4 |
45 |
1 |
— |
— |
1 |
|||
|
Impairments |
55 |
91 |
94 |
142 |
382 |
34 |
35 |
54 |
123 |
|||
|
Marketing Costs |
1,283 |
2,127 |
1,621 |
1,504 |
6,535 |
1,361 |
1,456 |
1,383 |
4,200 |
|||
|
Depreciation, Depletion and Amortization |
847 |
911 |
906 |
878 |
3,542 |
798 |
866 |
898 |
2,562 |
|||
|
General and Administrative |
124 |
128 |
162 |
156 |
570 |
145 |
142 |
161 |
448 |
|||
|
Taxes Other Than Income |
390 |
472 |
334 |
389 |
1,585 |
329 |
313 |
341 |
983 |
|||
|
Total |
3,437 |
4,504 |
3,929 |
3,866 |
15,736 |
3,472 |
3,603 |
3,655 |
10,730 |
|||
|
Operating Income |
546 |
2,903 |
3,664 |
2,853 |
9,966 |
2,572 |
1,970 |
2,557 |
7,099 |
|||
|
Other Income (Expense), Net |
(1) |
27 |
40 |
48 |
114 |
65 |
51 |
52 |
168 |
|||
|
Income Before Interest Expense and Income Taxes |
545 |
2,930 |
3,704 |
2,901 |
10,080 |
2,637 |
2,021 |
2,609 |
7,267 |
|||
|
Interest Expense, Net |
48 |
48 |
41 |
42 |
179 |
42 |
35 |
36 |
113 |
|||
|
Income Before Income Taxes |
497 |
2,882 |
3,663 |
2,859 |
9,901 |
2,595 |
1,986 |
2,573 |
7,154 |
|||
|
Income Tax Provision |
107 |
644 |
809 |
582 |
2,142 |
572 |
433 |
543 |
1,548 |
|||
|
Net Income |
390 |
2,238 |
2,854 |
2,277 |
7,759 |
2,023 |
1,553 |
2,030 |
5,606 |
|||
|
Dividends Declared per Common Share |
1.7500 |
2.5500 |
2.2500 |
2.3250 |
8.8750 |
1.8250 |
0.8250 |
0.8250 |
3.4750 |
|||
|
Net Income Per Share |
||||||||||||
|
Basic |
0.67 |
3.84 |
4.90 |
3.90 |
13.31 |
3.46 |
2.68 |
3.51 |
9.65 |
|||
|
Diluted |
0.67 |
3.81 |
4.86 |
3.87 |
13.22 |
3.45 |
2.66 |
3.48 |
9.60 |
|||
|
Average Number of Common Shares |
||||||||||||
|
Basic |
582 |
583 |
583 |
584 |
583 |
584 |
580 |
579 |
581 |
|||
|
Diluted |
586 |
588 |
587 |
588 |
587 |
587 |
584 |
583 |
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 |
YTD |
|||
|
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 |
472.0 |
|||
|
Trinidad |
0.7 |
0.6 |
0.5 |
0.5 |
0.6 |
0.6 |
0.6 |
0.5 |
0.6 |
|||
|
Total |
450.1 |
464.1 |
465.1 |
465.6 |
461.3 |
457.7 |
476.6 |
483.3 |
472.6 |
|||
|
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 |
$ 78.69 |
|||
|
Trinidad |
83.82 |
98.29 |
84.98 |
75.21 |
86.16 |
68.98 |
64.88 |
71.38 |
68.37 |
|||
|
Composite |
96.00 |
111.25 |
96.04 |
85.67 |
97.21 |
77.26 |
74.97 |
83.60 |
78.67 |
|||
|
Natural Gas Liquids Volumes (MBbld) (A) |
||||||||||||
|
United States |
190.3 |
201.9 |
209.3 |
189.0 |
197.7 |
212.2 |
215.7 |
231.1 |
219.7 |
|||
|
Total |
190.3 |
201.9 |
209.3 |
189.0 |
197.7 |
212.2 |
215.7 |
231.1 |
219.7 |
|||
|
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 |
$ 23.35 |
|||
|
Composite |
39.77 |
42.28 |
36.02 |
28.55 |
36.70 |
25.67 |
20.85 |
23.56 |
23.35 |
|||
|
Natural Gas Volumes (MMcfd) (A) |
||||||||||||
|
United States |
1,249 |
1,324 |
1,306 |
1,378 |
1,315 |
1,475 |
1,513 |
1,562 |
1,517 |
|||
|
Trinidad |
209 |
204 |
163 |
149 |
180 |
164 |
155 |
142 |
154 |
|||
|
Total |
1,458 |
1,528 |
1,469 |
1,527 |
1,495 |
1,639 |
1,668 |
1,704 |
1,671 |
|||
|
Average Natural Gas Prices ($/Mcf) (B) |
||||||||||||
|
United States |
$ 5.81 |
$ 7.77 |
$ 9.35 |
$ 6.12 |
$ 7.27 |
$ 3.47 |
$ 2.07 |
$ 2.59 |
$ 2.70 |
|||
|
Trinidad (D) |
3.36 |
3.42 |
7.45 |
3.97 |
4.43 |
3.87 |
3.45 |
3.41 |
3.59 |
|||
|
Composite |
5.46 |
7.19 |
9.14 |
5.91 |
6.93 |
3.51 |
2.20 |
2.66 |
2.78 |
|||
|
Crude Oil Equivalent Volumes (MBoed) (C) |
||||||||||||
|
United States |
847.8 |
886.1 |
891.6 |
883.8 |
877.5 |
915.0 |
943.8 |
974.2 |
944.6 |
|||
|
Trinidad |
35.5 |
34.6 |
27.6 |
25.3 |
30.7 |
28.0 |
26.5 |
24.3 |
26.2 |
|||
|
Total |
883.3 |
920.7 |
919.2 |
909.1 |
908.2 |
943.0 |
970.3 |
998.5 |
970.8 |
|||
|
Total MMBoe (C) |
79.5 |
83.8 |
84.6 |
83.6 |
331.5 |
84.9 |
88.3 |
91.9 |
265.0 |
|||
|
(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 Condensed Consolidated Financial Statements in EOG’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 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 $3.37 per Mcf and $0.76 per Mcf ($0.37 per Mcf and $0.09 per Mcf of EOG’s composite wellhead natural gas price) for the three months ended September 30, 2022 and the twelve months ended December 31, 2022, respectively, 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 |
|||
|
Accounts Receivable, Net |
3,213 |
3,735 |
3,343 |
2,774 |
2,455 |
2,263 |
2,927 |
|||
|
Inventories |
586 |
739 |
872 |
1,058 |
1,131 |
1,355 |
1,379 |
|||
|
Assets from Price Risk Management Activities |
— |
1 |
— |
— |
— |
— |
— |
|||
|
Income Taxes Receivable |
— |
— |
93 |
97 |
— |
1 |
— |
|||
|
Other |
671 |
605 |
621 |
574 |
580 |
523 |
626 |
|||
|
Total |
8,479 |
8,153 |
10,201 |
10,475 |
9,184 |
8,906 |
10,258 |
|||
|
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 |
|||
|
Other Property, Plant and Equipment |
4,801 |
4,862 |
4,659 |
4,786 |
5,101 |
5,282 |
5,355 |
|||
|
Total Property, Plant and Equipment |
70,209 |
70,960 |
71,724 |
72,108 |
73,008 |
74,460 |
76,085 |
|||
|
Less: Accumulated Depreciation, Depletion and Amortization |
(41,747) |
(42,113) |
(42,623) |
(42,679) |
(42,785) |
(43,550) |
(44,362) |
|||
|
Total Property, Plant and Equipment, Net |
28,462 |
28,847 |
29,101 |
29,429 |
30,223 |
30,910 |
31,723 |
|||
|
Deferred Income Taxes |
13 |
12 |
18 |
33 |
31 |
33 |
33 |
|||
|
Other Assets |
1,143 |
1,127 |
1,167 |
1,434 |
1,587 |
1,638 |
1,633 |
|||
|
Total Assets |
38,097 |
38,139 |
40,487 |
41,371 |
41,025 |
41,487 |
43,647 |
|||
|
Current Liabilities |
||||||||||
|
Accounts Payable |
2,660 |
2,896 |
2,718 |
2,532 |
2,438 |
2,205 |
2,464 |
|||
|
Accrued Taxes Payable |
1,130 |
594 |
542 |
405 |
637 |
425 |
605 |
|||
|
Dividends Payable |
436 |
437 |
437 |
482 |
482 |
478 |
478 |
|||
|
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 |
|||
|
Current Portion of Operating Lease Liabilities |
223 |
216 |
235 |
296 |
354 |
335 |
337 |
|||
|
Other |
272 |
264 |
289 |
346 |
253 |
232 |
285 |
|||
|
Total |
6,264 |
5,768 |
5,746 |
5,513 |
4,228 |
3,731 |
4,225 |
|||
|
Long-Term Debt |
3,816 |
3,809 |
3,802 |
3,795 |
3,787 |
3,780 |
3,772 |
|||
|
Other Liabilities |
2,191 |
2,067 |
2,573 |
2,574 |
2,620 |
2,581 |
2,698 |
|||
|
Deferred Income Taxes |
4,286 |
4,183 |
4,517 |
4,710 |
4,943 |
5,138 |
5,194 |
|||
|
Commitments and Contingencies |
||||||||||
|
Stockholders’ Equity |
||||||||||
|
Common Stock, $0.01 Par |
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 |
|||
|
Accumulated Other Comprehensive Loss |
(13) |
(12) |
(6) |
(8) |
(8) |
(9) |
(7) |
|||
|
Retained Earnings |
15,283 |
16,028 |
17,563 |
18,472 |
19,423 |
20,497 |
22,047 |
|||
|
Common Stock Held in Treasury |
(31) |
(38) |
(69) |
(78) |
(393) |
(694) |
(621) |
|||
|
Total Stockholders’ Equity |
21,540 |
22,312 |
23,849 |
24,779 |
25,447 |
26,257 |
27,758 |
|||
|
Total Liabilities and Stockholders’ Equity |
38,097 |
38,139 |
40,487 |
41,371 |
41,025 |
41,487 |
43,647 |
|||
|
Cash Flows 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 |
YTD |
|||
|
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 |
5,606 |
|||
|
Items Not Requiring (Providing) Cash |
||||||||||||
|
Depreciation, Depletion and Amortization |
847 |
911 |
906 |
878 |
3,542 |
798 |
866 |
898 |
2,562 |
|||
|
Impairments |
55 |
91 |
94 |
142 |
382 |
34 |
35 |
54 |
123 |
|||
|
Stock-Based Compensation Expenses |
35 |
30 |
34 |
34 |
133 |
34 |
35 |
57 |
126 |
|||
|
Deferred Income Taxes |
(465) |
(102) |
327 |
179 |
(61) |
234 |
194 |
56 |
484 |
|||
|
(Gains) Losses on Asset Dispositions, Net |
(25) |
(97) |
21 |
27 |
(74) |
(69) |
9 |
(35) |
(95) |
|||
|
Other, Net |
6 |
(16) |
(5) |
15 |
— |
4 |
2 |
(1) |
5 |
|||
|
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) |
(520) |
|||
|
Net Cash Received from (Payments for) Settlements of Financial Commodity Derivative Contracts |
(296) |
(2,114) |
(847) |
(244) |
(3,501) |
(123) |
(30) |
23 |
(130) |
|||
|
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) |
(239) |
|||
|
Inventories |
(14) |
(157) |
(140) |
(223) |
(534) |
(77) |
(226) |
(28) |
(331) |
|||
|
Accounts Payable |
130 |
259 |
(88) |
(211) |
90 |
(77) |
(231) |
238 |
(70) |
|||
|
Accrued Taxes Payable |
613 |
(536) |
(53) |
(137) |
(113) |
232 |
(212) |
180 |
200 |
|||
|
Other Assets |
(213) |
71 |
(129) |
(93) |
(364) |
52 |
43 |
(92) |
3 |
|||
|
Other Liabilities |
(2,250) |
433 |
1,269 |
282 |
(266) |
193 |
(47) |
54 |
200 |
|||
|
Changes in Components of Working Capital Associated with Investing Activities |
68 |
143 |
90 |
74 |
375 |
35 |
250 |
28 |
313 |
|||
|
Net Cash Provided by Operating Activities |
828 |
2,048 |
4,773 |
3,444 |
11,093 |
3,255 |
2,277 |
2,704 |
8,236 |
|||
|
Investing Cash Flows |
||||||||||||
|
Additions to Oil and Gas Properties |
(939) |
(1,349) |
(1,102) |
(1,229) |
(4,619) |
(1,305) |
(1,341) |
(1,379) |
(4,025) |
|||
|
Additions to Other Property, Plant and Equipment |
(70) |
(75) |
(103) |
(133) |
(381) |
(319) |
(180) |
(139) |
(638) |
|||
|
Proceeds from Sales of Assets |
121 |
110 |
79 |
39 |
349 |
92 |
29 |
14 |
135 |
|||
|
Other Investing Activities |
— |
(30) |
— |
— |
(30) |
— |
— |
— |
— |
|||
|
Changes in Components of Working Capital Associated with Investing Activities |
(68) |
(143) |
(90) |
(74) |
(375) |
(35) |
(250) |
(28) |
(313) |
|||
|
Net Cash Used in Investing Activities |
(956) |
(1,487) |
(1,216) |
(1,397) |
(5,056) |
(1,567) |
(1,742) |
(1,532) |
(4,841) |
|||
|
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) |
(2,041) |
|||
|
Treasury Stock Purchased |
(43) |
(15) |
(37) |
(23) |
(118) |
(317) |
(302) |
(109) |
(728) |
|||
|
Proceeds from Stock Options Exercised and Employee Stock Purchase Plan |
4 |
13 |
— |
11 |
28 |
— |
9 |
1 |
10 |
|||
|
Debt Issuance Costs |
— |
— |
— |
— |
— |
— |
(8) |
— |
(8) |
|||
|
Repayment of Finance Lease Liabilities |
(10) |
(9) |
(8) |
(8) |
(35) |
(8) |
(8) |
(8) |
(24) |
|||
|
Net Cash Used in Financing Activities |
(1,072) |
(1,497) |
(1,357) |
(1,347) |
(5,273) |
(2,642) |
(789) |
(610) |
(4,041) |
|||
|
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 |
(646) |
|||
|
Cash and Cash Equivalents at Beginning of Period |
5,209 |
4,009 |
3,073 |
5,272 |
5,209 |
5,972 |
5,018 |
4,764 |
5,972 |
|||
|
Cash and Cash Equivalents at End of Period |
4,009 |
3,073 |
5,272 |
5,972 |
5,972 |
5,018 |
4,764 |
5,326 |
5,326 |
|||
|
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. |
||||||||
|
3Q 2023 |
||||||||
|
Before |
Income Tax |
After |
Diluted |
|||||
|
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 |
Income Tax |
After |
Diluted |
|||||
|
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 |
|||||
|
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 |
|||||
|
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) |
||||||||
|
3Q 2022 |
||||||||
|
Before |
Income Tax |
After |
Diluted |
|||||
|
Reported Net Income (GAAP) |
3,663 |
(809) |
2,854 |
4.86 |
||||
|
Adjustments: |
||||||||
|
Losses on Mark-to-Market Financial Commodity Derivative Contracts, Net |
18 |
(4) |
14 |
0.03 |
||||
|
Net Cash Payments for Settlements of Financial Commodity Derivative Contracts (1) |
(847) |
184 |
(663) |
(1.13) |
||||
|
Add: Losses on Asset Dispositions, Net |
21 |
(3) |
18 |
0.03 |
||||
|
Add: Certain Impairments |
46 |
(8) |
38 |
0.06 |
||||
|
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 |
(868) |
193 |
(675) |
(1.15) |
||||
|
Adjusted Net Income (Non-GAAP) |
2,795 |
(616) |
2,179 |
3.71 |
||||
|
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 three months ended September 30, 2022, such amount was $847 million, of which $63 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) |
||||
|
2Q 2023 Net Income per Share (GAAP) |
2.66 |
|||
|
Realized Price |
||||
|
3Q 2023 Composite Average Wellhead Revenue per Boe |
50.46 |
|||
|
Less: 2Q 2023 Composite Average Wellhead Revenue per Boe |
(45.24) |
|||
|
Subtotal |
5.22 |
|||
|
Multiplied by: 3Q 2023 Crude Oil Equivalent Volumes (MMBoe) |
91.9 |
|||
|
Total Change in Revenue |
480 |
|||
|
Less: Income Tax Benefit (Provision) Imputed (based on 22%) |
(106) |
|||
|
Change in Net Income |
374 |
|||
|
Change in Diluted Earnings per Share |
0.64 |
|||
|
Wellhead Volumes |
||||
|
3Q 2023 Crude Oil Equivalent Volumes (MMBoe) |
91.9 |
|||
|
Less: 2Q 2023 Crude Oil Equivalent Volumes (MMBoe) |
(88.3) |
|||
|
Subtotal |
3.6 |
|||
|
Multiplied by: 3Q 2023 Composite Average Margin per Boe (Non-GAAP) |
25.58 |
|||
|
Change in Margin |
92 |
|||
|
Less: Income Tax Benefit (Provision) Imputed (based on 22%) |
(20) |
|||
|
Change in Net Income |
72 |
|||
|
Change in Diluted Earnings per Share |
0.12 |
|||
|
Certain Operating Costs per Boe |
||||
|
2Q 2023 Total Cash Operating Costs (GAAP) and Total DD&A per Boe (refer to “Revenues, Costs and Margins Per Barrel of Oil Equivalent” schedule) |
19.84 |
|||
|
Less: 3Q 2023 Total Cash Operating Costs (GAAP) and Total DD&A per Boe (refer to “Revenues, Costs and Margins Per Barrel of Oil Equivalent” schedule) |
(19.97) |
|||
|
Subtotal |
(0.13) |
|||
|
Multiplied by: 3Q 2023 Crude Oil Equivalent Volumes (MMBoe) |
91.9 |
|||
|
Change in Before-Tax Net Income |
(12) |
|||
|
Less: Income Tax Benefit (Provision) Imputed (based on 22%) |
3 |
|||
|
Change in Net Income |
(9) |
|||
|
Change in Diluted Earnings per Share |
(0.02) |
|||
|
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 |
||||
|
3Q 2023 Net Gains (Losses) on Mark-to-Market Financial Commodity Derivative Contracts |
43 |
|||
|
Less: Income Tax Benefit (Provision) |
(9) |
|||
|
After Tax – (a) |
34 |
|||
|
Less: 2Q 2023 Net Gains (Losses) on Mark-to-Market Financial Commodity Derivative Contracts |
101 |
|||
|
Less: Income Tax Benefit (Provision) |
(22) |
|||
|
After Tax – (b) |
79 |
|||
|
Change in Net Income – (a) – (b) |
(45) |
|||
|
Change in Diluted Earnings per Share |
(0.08) |
|||
|
Other (1) |
0.16 |
|||
|
3Q 2023 Net Income per Share (GAAP) |
3.48 |
|||
|
3Q 2023 Average Number of Common Shares (GAAP) – Diluted |
583 |
|||
|
(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) |
||||
|
2Q 2023 Adjusted Net Income per Share (Non-GAAP) |
2.49 |
|||
|
Realized Price |
||||
|
3Q 2023 Composite Average Wellhead Revenue per Boe |
50.46 |
|||
|
Less: 2Q 2023 Composite Average Wellhead Revenue per Boe |
(45.24) |
|||
|
Subtotal |
5.22 |
|||
|
Multiplied by: 3Q 2023 Crude Oil Equivalent Volumes (MMBoe) |
91.9 |
|||
|
Total Change in Revenue |
480 |
|||
|
Less: Income Tax Benefit (Provision) Imputed (based on 22%) |
(106) |
|||
|
Change in Net Income |
374 |
|||
|
Change in Diluted Earnings per Share |
0.64 |
|||
|
Wellhead Volumes |
||||
|
3Q 2023 Crude Oil Equivalent Volumes (MMBoe) |
91.9 |
|||
|
Less: 2Q 2023 Crude Oil Equivalent Volumes (MMBoe) |
(88.3) |
|||
|
Subtotal |
3.6 |
|||
|
Multiplied by: 3Q 2023 Composite Average Margin per Boe (Non-GAAP) (Including Total Exploration Costs) (refer to “Revenues, Costs and Margins Per Barrel of Oil Equivalent” schedule) |
25.58 |
|||
|
Change in Margin |
92 |
|||
|
Less: Income Tax Benefit (Provision) Imputed (based on 22%) |
(20) |
|||
|
Change in Net Income |
72 |
|||
|
Change in Diluted Earnings per Share |
0.12 |
|||
|
Certain Operating Costs per Boe |
||||
|
2Q 2023 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe (refer to “Revenues, Costs and Margins Per Barrel of Oil Equivalent” schedule) |
19.84 |
|||
|
Less: 3Q 2023 Total Cash Operating Costs (Non-GAAP) and Total DD&A per Boe (refer to “Revenues, Costs and Margins Per Barrel of Oil Equivalent” schedule) |
(19.97) |
|||
|
Subtotal |
(0.13) |
|||
|
Multiplied by: 3Q 2023 Crude Oil Equivalent Volumes (MMBoe) |
91.9 |
|||
|
Change in Before-Tax Net Income |
(12) |
|||
|
Less: Income Tax Benefit (Provision) Imputed (based on 22%) |
3 |
|||
|
Change in Net Income |
(9) |
|||
|
Change in Diluted Earnings per Share |
(0.02) |
|||
|
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 |
||||
|
3Q 2023 Net Cash Received from (Payments for) Settlement of Financial Commodity Derivative Contracts |
23 |
|||
|
Less: Income Tax Benefit (Provision) |
(5) |
|||
|
After Tax – (a) |
18 |
|||
|
2Q 2023 Net Cash Received from (Payments for) Settlement of Financial Commodity Derivative Contracts |
(30) |
|||
|
Less: Income Tax Benefit (Provision) |
6 |
|||
|
After Tax – (b) |
(24) |
|||
|
Change in Net Income – (a) – (b) |
42 |
|||
|
Change in Diluted Earnings per Share |
0.07 |
|||
|
Other (1) |
0.14 |
|||
|
3Q 2023 Adjusted Net Income per Share (Non-GAAP) |
3.44 |
|||
|
3Q 2023 Average Number of Common Shares (Non-GAAP) – Diluted |
583 |
|||
|
(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 and Financing 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 |
YTD |
|||
|
Net Cash Provided by Operating Activities (GAAP) |
828 |
2,048 |
4,773 |
3,444 |
11,093 |
3,255 |
2,277 |
2,704 |
8,236 |
|||
|
Adjustments: |
||||||||||||
|
Changes in Components of Working Capital and Other Assets and Liabilities |
||||||||||||
|
Accounts Receivable |
878 |
522 |
(392) |
(661) |
347 |
(338) |
(137) |
714 |
239 |
|||
|
Inventories |
14 |
157 |
140 |
223 |
534 |
77 |
226 |
28 |
331 |
|||
|
Accounts Payable |
(130) |
(259) |
88 |
211 |
(90) |
77 |
231 |
(238) |
70 |
|||
|
Accrued Taxes Payable |
(613) |
536 |
53 |
137 |
113 |
(232) |
212 |
(180) |
(200) |
|||
|
Other Assets |
213 |
(71) |
129 |
93 |
364 |
(52) |
(43) |
92 |
(3) |
|||
|
Other Liabilities |
2,250 |
(433) |
(1,269) |
(282) |
266 |
(193) |
47 |
(54) |
(200) |
|||
|
Changes in Components of Working Capital Associated with Investing Activities |
(68) |
(143) |
(90) |
(74) |
(375) |
(35) |
(250) |
(28) |
(313) |
|||
|
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 |
8,160 |
|||
|
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 |
8,160 |
|||
|
Less: |
||||||||||||
|
Total Capital Expenditures (Non-GAAP) (a) |
(1,009) |
(1,071) |
(1,166) |
(1,361) |
(4,607) |
(1,489) |
(1,521) |
(1,519) |
(4,529) |
|||
|
Free Cash Flow (Non-GAAP) |
2,363 |
1,286 |
2,266 |
1,730 |
7,645 |
1,070 |
1,042 |
1,519 |
3,631 |
|||
|
(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 |
YTD |
|||
|
Total Expenditures (GAAP) |
1,144 |
1,521 |
1,410 |
1,535 |
5,610 |
1,717 |
1,664 |
1,803 |
5,184 |
|||
|
Less: |
||||||||||||
|
Asset Retirement Costs |
(27) |
(43) |
(139) |
(89) |
(298) |
(10) |
(26) |
(191) |
(227) |
|||
|
Non-Cash Acquisition Costs of Unproved Properties |
(58) |
(21) |
(28) |
(20) |
(127) |
(31) |
(28) |
(1) |
(60) |
|||
|
Non-Cash Development Drilling |
— |
— |
— |
— |
— |
— |
(35) |
(50) |
(85) |
|||
|
Acquisition Costs of Proved Properties |
(5) |
(351) |
(42) |
(21) |
(419) |
(4) |
(6) |
1 |
(9) |
|||
|
Acquisition Costs of Other Property, Plant and Equipment |
— |
— |
— |
— |
— |
(133) |
(1) |
— |
(134) |
|||
|
Exploration Costs |
(45) |
(35) |
(35) |
(44) |
(159) |
(50) |
(47) |
(43) |
(140) |
|||
|
Total Capital Expenditures (Non-GAAP) |
1,009 |
1,071 |
1,166 |
1,361 |
4,607 |
1,489 |
1,521 |
1,519 |
4,529 |
|||
|
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. |
||||||||||
|
September 30, |
June 30, |
March 31, |
December 31, |
September 30, |
||||||
|
Total Stockholders’ Equity – (a) |
27,758 |
26,257 |
25,447 |
24,779 |
23,849 |
|||||
|
Current and Long-Term Debt (GAAP) – (b) |
3,806 |
3,814 |
3,820 |
5,078 |
5,084 |
|||||
|
Less: Cash |
(5,326) |
(4,764) |
(5,018) |
(5,972) |
(5,272) |
|||||
|
Net Debt (Non-GAAP) – (c) |
(1,520) |
(950) |
(1,198) |
(894) |
(188) |
|||||
|
Total Capitalization (GAAP) – (a) + (b) |
31,564 |
30,071 |
29,267 |
29,857 |
28,933 |
|||||
|
Total Capitalization (Non-GAAP) – (a) + (c) |
26,238 |
25,307 |
24,249 |
23,885 |
23,661 |
|||||
|
Debt-to-Total Capitalization (GAAP) – (b) / [(a) + (b)] |
12.1 % |
12.7 % |
13.1 % |
17.0 % |
17.6 % |
|||||
|
Net Debt-to-Total Capitalization (Non-GAAP) – (c) / [(a) + (c)] |
-5.8 % |
-3.8 % |
-4.9 % |
-3.7 % |
-0.8 % |
|||||
SOURCE EOG Resources, Inc.
