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.
Key Financial Results
|
|
|
|
In millions of USD,
except per-share, per-Boe and ratio data
|
|
|
|
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 $1.5 billion of free
cash flow
- Volumes, capital expenditures, and per-unit operating costs
better than guidance midpoints
- Updated full-year guidance to reflect higher volumes and lower
per-unit operating costs
Volumes and Capital Expenditures
Wellhead Volumes
|
|
3Q 2023
|
|
|
|
|
|
3Q
2023
|
Guidance
Midpoint
|
2Q
2023
|
1Q
2023
|
4Q
2022
|
3Q
2022
|
|
Crude Oil and
Condensate (MBod)
|
483.3
|
472.9
|
476.6
|
457.7
|
465.6
|
465.1
|
|
Natural Gas Liquids
(MBbld)
|
231.1
|
223.0
|
215.7
|
212.2
|
189.0
|
209.3
|
|
Natural Gas
(MMcfd)
|
1,704
|
1,660
|
1,668
|
1,639
|
1,527
|
1,469
|
|
Total Crude Oil Equivalent
(MBoed)
|
998.5
|
972.6
|
970.3
|
943.0
|
909.1
|
919.2
|
|
|
|
|
|
Capital Expenditures ($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 Rate
The
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 Dividend
The 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 Repurchases
During 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 $4.3 billion remaining on its current repurchase
authorization.
Third Quarter 2023 Results vs
Guidance
|
|
(Unaudited)
|
|
See "Endnotes" below
for related discussion and definitions.
|
|
|
|
|
|
3Q
2023
|
|
|
|
|
|
|
|
3Q
2023
|
Guidance
Midpoint
|
Variance
|
2Q 2023
|
1Q 2023
|
4Q 2022
|
3Q 2022
|
|
Crude Oil and Condensate Volumes
(MBod)
|
|
|
|
United
States
|
482.8
|
472.5
|
10.3
|
476.0
|
457.1
|
465.1
|
464.6
|
|
Trinidad
|
0.5
|
0.4
|
0.1
|
0.6
|
0.6
|
0.5
|
0.5
|
|
Other
International
|
0.0
|
0.0
|
0.0
|
0.0
|
0.0
|
0.0
|
0.0
|
|
Total
|
483.3
|
472.9
|
10.4
|
476.6
|
457.7
|
465.6
|
465.1
|
|
Natural Gas Liquids Volumes
(MBbld)
|
|
|
|
Total
|
231.1
|
223.0
|
8.1
|
215.7
|
212.2
|
189.0
|
209.3
|
|
Natural Gas Volumes (MMcfd)
|
|
|
|
United
States
|
1,562
|
1,530
|
32
|
1,513
|
1,475
|
1,378
|
1,306
|
|
Trinidad
|
142
|
130
|
12
|
155
|
164
|
149
|
163
|
|
Other
International
|
0
|
0
|
0
|
0
|
0
|
0
|
0
|
|
Total
|
1,704
|
1,660
|
44
|
1,668
|
1,639
|
1,527
|
1,469
|
|
|
|
|
|
Total Crude Oil Equivalent Volumes
(MBoed)
|
998.5
|
972.6
|
25.9
|
970.3
|
943.0
|
909.1
|
919.2
|
|
Total
MMBoe
|
91.9
|
89.5
|
2.4
|
88.3
|
84.9
|
83.6
|
84.6
|
|
|
|
|
|
Benchmark Price
|
|
|
|
Oil (WTI)
($/Bbl)
|
82.18
|
|
|
73.75
|
76.11
|
82.63
|
91.64
|
|
Natural Gas (HH)
($/Mcf)
|
2.55
|
|
|
2.09
|
3.43
|
6.27
|
8.18
|
|
|
|
|
Crude Oil and Condensate - above (below)
WTI3 ($/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 ($/Mcf)
|
|
|
|
United
States
|
0.04
|
(0.05)
|
0.09
|
(0.02)
|
0.04
|
(0.15)
|
1.17
|
|
Natural Gas
Realizations5 ($/Mcf)
|
|
|
|
Trinidad
|
3.41
|
3.35
|
0.06
|
3.45
|
3.87
|
3.97
|
7.45
|
|
|
|
|
|
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 ($MM)
|
486
|
345
|
141
|
241
|
338
|
409
|
481
|
|
Fourth Quarter and Full-Year 2023
Guidance7
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
See "Endnotes" below for related discussion and
definitions.
|
|
|
|
|
|
|
|
|
|
4Q 2023
Guidance
Range
|
4Q 2023
Midpoint
|
FY 2023
Guidance
Range
|
FY 2023
Midpoint
|
2022
Actual
|
2021
Actual
|
2020
Actual
|
|
Crude Oil and Condensate Volumes
(MBod)
|
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
479.1
|
-
|
487.1
|
483.1
|
473.5
|
-
|
476.5
|
475.0
|
460.7
|
443.4
|
408.1
|
|
Trinidad
|
0.2
|
-
|
0.6
|
0.4
|
0.3
|
-
|
0.5
|
0.4
|
0.6
|
1.5
|
1.0
|
|
Other
International
|
0.0
|
-
|
0.0
|
0.0
|
0.0
|
-
|
0.0
|
0.0
|
0.0
|
0.1
|
0.1
|
|
Total
|
479.3
|
-
|
487.7
|
483.5
|
473.8
|
-
|
477.0
|
475.4
|
461.3
|
445.0
|
409.2
|
|
Natural Gas Liquids Volumes
(MBbld)
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
230.0
|
-
|
238.0
|
234.0
|
222.3
|
-
|
224.3
|
223.3
|
197.7
|
144.5
|
136.0
|
|
Natural Gas Volumes (MMcfd)
|
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
1,590
|
-
|
1,640
|
1,615
|
1,515
|
-
|
1,575
|
1,545
|
1,315
|
1,210
|
1,040
|
|
Trinidad
|
155
|
-
|
185
|
170
|
140
|
-
|
170
|
155
|
180
|
217
|
180
|
|
Other
International
|
0
|
-
|
0
|
0
|
0
|
-
|
0
|
0
|
0
|
9
|
32
|
|
Total
|
1,745
|
-
|
1,825
|
1,785
|
1,655
|
-
|
1,745
|
1,700
|
1,495
|
1,436
|
1,252
|
|
Crude Oil Equivalent Volumes
(MBoed)
|
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
974.1
|
-
|
998.4
|
986.3
|
948.3
|
-
|
963.3
|
955.8
|
877.5
|
789.6
|
717.5
|
|
Trinidad
|
26.0
|
-
|
31.4
|
28.7
|
23.6
|
-
|
28.8
|
26.2
|
30.7
|
37.7
|
30.9
|
|
Other
International
|
0.0
|
-
|
0.0
|
0.0
|
0.0
|
-
|
0.0
|
0.0
|
0.0
|
1.6
|
5.4
|
|
Total
|
1,000.1
|
-
|
1,029.8
|
1,015.0
|
971.9
|
-
|
992.1
|
982.0
|
908.2
|
828.9
|
753.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benchmark Price
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (WTI)
($/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 Webcast
Friday, 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 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 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.
|
|
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
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)
|
|
|
|
|
3Q 2022
|
|
|
Before
Tax
|
|
Income Tax
Impact
|
|
After
Tax
|
|
Diluted
Earnings
per Share
|
|
|
|
|
|
|
|
|
|
|
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)
(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 (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,
2023
|
|
June 30,
2023
|
|
March 31,
2023
|
|
December 31,
2022
|
|
September 30,
2022
|
|
|
|
|
|
|
|
|
|
|
|
|
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 %
|
|
View original
content:https://www.prnewswire.com/news-releases/eog-resources-reports-third-quarter-2023-results-increases-annual-cash-return-commitment-to-shareholders-and-raises-regular-dividend-10-301976393.html
SOURCE EOG Resources, Inc.