HOUSTON, Aug. 3, 2023
/PRNewswire/ -- EOG Resources, Inc. (EOG) today reported second
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
|
2Q 2023
|
1Q 2023
|
4Q 2022
|
3Q 2022
|
2Q 2022
|
|
Total
Revenue
|
5,573
|
6,044
|
6,719
|
7,593
|
7,407
|
|
Net Income
|
1,553
|
2,023
|
2,277
|
2,854
|
2,238
|
|
Net Income Per
Share
|
2.66
|
3.45
|
3.87
|
4.86
|
3.81
|
|
Net Cash Provided by
Operating Activities
|
2,277
|
3,255
|
3,444
|
4,773
|
2,048
|
|
Total
Expenditures
|
1,664
|
1,717
|
1,535
|
1,410
|
1,521
|
|
Current and Long-Term
Debt
|
3,814
|
3,820
|
5,078
|
5,084
|
5,091
|
|
Cash and Cash
Equivalents
|
4,764
|
5,018
|
5,972
|
5,272
|
3,073
|
|
Debt-to-Total
Capitalization
|
12.7 %
|
13.1 %
|
17.0 %
|
17.6 %
|
18.6 %
|
|
Cash Operating Costs
($/Boe)
|
10.03
|
10.59
|
10.82
|
10.89
|
10.12
|
|
General and
Administrative Costs ($/Boe)
|
1.61
|
1.71
|
1.87
|
1.92
|
1.53
|
|
|
|
|
|
Non -
GAAP
|
|
|
|
Adjusted Net
Income
|
1,457
|
1,578
|
1,941
|
2,179
|
1,614
|
|
Adjusted Net Income
Per Share
|
2.49
|
2.69
|
3.30
|
3.71
|
2.74
|
|
CFO before Changes in
Working Capital
|
2,563
|
2,559
|
3,091
|
3,432
|
2,357
|
|
Capital
Expenditures
|
1,521
|
1,489
|
1,361
|
1,166
|
1,071
|
|
Free Cash
Flow
|
1,042
|
1,070
|
1,730
|
2,266
|
1,286
|
|
Net Debt
|
(950)
|
(1,198)
|
(894)
|
(188)
|
2,018
|
|
Net Debt-to-Total
Capitalization
|
(3.8 %)
|
(4.9 %)
|
(3.7 %)
|
(0.8 %)
|
8.3 %
|
|
Cash Operating Costs
($/Boe)1
|
10.03
|
10.59
|
10.82
|
10.70
|
10.12
|
|
General and
Administrative Costs ($/Boe)1
|
1.61
|
1.71
|
1.87
|
1.73
|
1.53
|
|
Second Quarter Highlights
- Earned adjusted net income of $1.5
billion, or $2.49
per share
- Generated $1.0 billion of free
cash flow
- Declared regular quarterly dividend of $0.825 per share
- Repurchased $300 million of
shares during the second quarter
- Oil, NGL, and natural gas production above
guidance midpoints
- Capital expenditures, per-unit cash operating costs, and
per-unit DD&A below guidance midpoints
Volumes and Capital Expenditures
|
|
2Q 2023
|
|
|
|
|
|
2Q
2023
|
Guidance
Midpoint
|
1Q
2023
|
4Q
2022
|
3Q
2022
|
2Q
2022
|
|
Wellhead
Volumes
|
|
|
|
|
|
|
|
Crude Oil and
Condensate (MBod)
|
476.6
|
472.6
|
457.7
|
465.6
|
465.1
|
464.1
|
|
Natural Gas Liquids
(MBbld)
|
215.7
|
212.0
|
212.2
|
189.0
|
209.3
|
201.9
|
|
Natural Gas
(MMcfd)
|
1,668
|
1,635
|
1,639
|
1,527
|
1,469
|
1,528
|
|
Total Crude Oil Equivalent
(MBoed)
|
970.3
|
957.1
|
943.0
|
909.1
|
919.2
|
920.7
|
|
|
|
|
|
Capital Expenditures ($MM)
|
1,521
|
1,650
|
1,489
|
1,361
|
1,166
|
1,071
|
|
Regular Dividend and Second Quarter Share
Repurchases
The Board of Directors today declared a dividend
of $0.825 per share on EOG's common
stock. The dividend will be payable October
31, 2023, to stockholders of record as of October 17, 2023. The indicated annual rate is
$3.30 per share.
During the second quarter, the company repurchased 2.8 million
shares for $300 million under its
share repurchase authorization, at an average purchase price of
approximately $108 per share.
Year-to-date, the company repurchased 5.7 million shares for
$610 million under its share
repurchase authorization, at an average purchase price of
approximately $107 per share. EOG has
approximately $4.4 billion remaining
on its current share buyback authorization.
From Ezra Yacob, Chairman and
Chief Executive Officer
"EOG delivered another quarter of
exceptional operating performance with production volumes, capital
expenditures, and cash operating costs all better than expected.
Results through the first half of the year reflect consistent
operating execution across our multi-basin portfolio to lower costs
and generate free cash flow.
"EOG remains committed to returning cash to our shareholders. We
paid our peer-leading regular dividend and repurchased shares with
strong free cash flow during the quarter. To date, we have already
committed to returning more than 60% of expected free cash flow in
2023 to shareholders, with the potential to return additional cash
over the balance of the year.
"Along with strong performance in the Delaware Basin and Eagle Ford, we are pleased
by the outstanding progress across our emerging plays. The South
Texas Dorado, Southern Powder River Basin, and Ohio Utica Combo are
achieving significant operational improvements, driving lower costs
and supporting higher returns. EOG is performing better than ever,
with the benefits of our multi-basin portfolio providing a clear
runway to drive further improvements and value for
our shareholders."
Second Quarter 2023 Financial Performance
Prices
- Crude oil, NGL, and natural gas prices declined in 2Q
compared with 1Q
Volumes
- Total 2Q oil production of 476,600 Bopd was above the
midpoint of the guidance range and up 4% from 1Q, reflecting a
planned change in activity mix
- NGL and natural gas production were each above the midpoint of
the guidance range and up 2% from 1Q
- Total company equivalent production increased 3% from 1Q
Per-Unit Costs
- LOE, transportation, gathering and processing, and G&A
costs decreased in 2Q compared with 1Q, while DD&A expenses
increased
Hedges
- Mark-to-market hedge gains decreased, lowering GAAP earnings
per share in 2Q compared with 1Q
- Lower cash paid to settle hedges partially offset the impact of
lower commodity prices on adjusted non-GAAP earnings per share
Free Cash Flow
- Cash flow from operations before changes in working capital was
$2.56 billion
- EOG incurred $1.52 billion of
capital expenditures
- This resulted in $1.04 billion of
free cash flow
Cash Return and Working Capital
- Paid $480 million in regular
dividends
- Repurchased $300 million of
stock
- Changes in working capital accounted for $540 million of the decrease in cash
Second Quarter 2023 Operating Performance
Lease and Well
Per-unit lease and well costs decreased
in 2Q compared with 1Q and were below the guidance midpoint
primarily due to decreased workovers and fuel-related expenses.
Transportation; Gathering and Processing
Per-unit
transportation and G&P costs declined in 2Q and were below the
guidance midpoints primarily due to oil transportation
optimization, higher in-basin NGL sales, and lower fuel costs.
General and Administrative
Per-unit G&A costs
declined in 2Q and were below the guidance midpoint primarily due
to lower third-party service expenses.
Depreciation, Depletion and Amortization
Per-unit
DD&A costs increased in 2Q compared with 1Q but were below the
guidance midpoint due to well mix.
Second Quarter 2023 Results vs
Guidance
|
|
(Unaudited)
|
|
See "Endnotes" below for related discussion and
definitions.
|
|
|
|
|
2Q 2023
|
|
|
|
|
|
|
|
2Q
2023
|
|
Guidance
Midpoint
|
Variance
|
1Q
2023
|
4Q
2022
|
3Q
2022
|
2Q
2022
|
|
Crude Oil and Condensate Volumes
(MBod)
|
|
|
|
|
United
States
|
476.0
|
|
472.0
|
4.0
|
457.1
|
465.1
|
464.6
|
463.5
|
|
Trinidad
|
0.6
|
|
0.6
|
0.0
|
0.6
|
0.5
|
0.5
|
0.6
|
|
Other
International
|
0.0
|
|
0.0
|
0.0
|
0.0
|
0.0
|
0.0
|
0.0
|
|
Total
|
476.6
|
|
472.6
|
4.0
|
457.7
|
465.6
|
465.1
|
464.1
|
|
Natural Gas Liquids Volumes
(MBbld)
|
|
|
|
|
Total
|
215.7
|
|
212.0
|
3.7
|
212.2
|
189.0
|
209.3
|
201.9
|
|
Natural Gas Volumes (MMcfd)
|
|
|
|
|
United
States
|
1,513
|
|
1,490
|
23
|
1,475
|
1,378
|
1,306
|
1,324
|
|
Trinidad
|
155
|
|
145
|
10
|
164
|
149
|
163
|
204
|
|
Other
International
|
0
|
|
0
|
0
|
0
|
0
|
0
|
0
|
|
Total
|
1,668
|
|
1,635
|
33
|
1,639
|
1,527
|
1,469
|
1,528
|
|
|
|
|
|
|
Total Crude Oil Equivalent Volumes
(MBoed)
|
970.3
|
|
957.1
|
13.2
|
943.0
|
909.1
|
919.2
|
920.7
|
|
Total
MMBoe
|
88.3
|
|
87.1
|
1.2
|
84.9
|
83.6
|
84.6
|
83.8
|
|
|
|
|
|
|
Benchmark Price
|
|
|
|
|
Oil (WTI)
($/Bbl)
|
73.75
|
|
|
|
76.11
|
82.63
|
91.64
|
108.42
|
|
Natural Gas (HH)
($/Mcf)
|
2.09
|
|
|
|
3.43
|
6.27
|
8.18
|
7.17
|
|
|
|
|
|
|
Crude Oil and Condensate - above (below)
WTI3 ($/Bbl)
|
|
|
|
|
United
States
|
1.23
|
|
0.70
|
0.53
|
1.16
|
3.05
|
4.41
|
2.84
|
|
Trinidad
|
(8.87)
|
|
(9.50)
|
0.63
|
(7.13)
|
(7.42)
|
(6.66)
|
(10.13)
|
|
Natural Gas Liquids - Realizations as % of
WTI
|
|
|
|
|
Total
|
28.3 %
|
|
29.0 %
|
(0.7 %)
|
33.7 %
|
34.6 %
|
39.3 %
|
39.0 %
|
|
Natural Gas - above (below) NYMEX Henry
Hub4 ($/Mcf)
|
|
|
|
|
United
States
|
(0.02)
|
|
0.00
|
(0.02)
|
0.04
|
(0.15)
|
1.17
|
0.60
|
|
Natural Gas
Realizations5 ($/Mcf)
|
|
|
|
|
Trinidad
|
3.45
|
|
3.45
|
0.00
|
3.87
|
3.97
|
7.45
|
3.42
|
|
|
|
|
|
|
Total Expenditures (GAAP) ($MM)
|
1,664
|
|
|
|
1,717
|
1,535
|
1,410
|
1,521
|
|
Capital Expenditures (non-GAAP)
($MM)
|
1,521
|
|
1,650
|
(129)
|
1,489
|
1,361
|
1,166
|
1,071
|
|
|
|
|
|
|
Operating Unit Costs ($/Boe)
|
|
|
|
|
Lease and
Well
|
3.94
|
|
4.20
|
(0.26)
|
4.23
|
4.23
|
3.96
|
3.87
|
|
Transportation
Costs
|
2.67
|
|
2.85
|
(0.18)
|
2.78
|
2.83
|
3.04
|
2.91
|
|
Gathering and
Processing
|
1.81
|
|
1.90
|
(0.09)
|
1.87
|
1.89
|
1.97
|
1.81
|
|
General and
Administrative (GAAP)
|
1.61
|
|
1.70
|
(0.09)
|
1.71
|
1.87
|
1.92
|
1.53
|
|
General and
Administrative (non-GAAP)1
|
1.61
|
|
1.70
|
(0.09)
|
1.71
|
1.87
|
1.73
|
1.53
|
|
Cash Operating Costs
(GAAP)
|
10.03
|
|
10.65
|
(0.62)
|
10.59
|
10.82
|
10.89
|
10.12
|
|
Cash Operating Costs
(non-GAAP)
|
10.03
|
|
10.65
|
(0.62)
|
10.59
|
10.82
|
10.70
|
10.12
|
|
Depreciation,
Depletion and Amortization
|
9.81
|
|
10.00
|
(0.19)
|
9.40
|
10.50
|
10.71
|
10.87
|
|
|
|
|
|
|
Expenses ($MM)
|
|
|
|
|
Exploration and Dry
Hole
|
47
|
|
65
|
(18)
|
51
|
48
|
53
|
55
|
|
Impairment
(GAAP)
|
35
|
|
|
|
34
|
142
|
94
|
91
|
|
Impairment (excluding
certain impairments (non-GAAP))6
|
35
|
|
100
|
(65)
|
34
|
111
|
48
|
55
|
|
Capitalized
Interest
|
8
|
|
9
|
(1)
|
8
|
11
|
11
|
7
|
|
Net
Interest
|
35
|
|
34
|
1
|
42
|
42
|
41
|
48
|
|
|
|
|
|
|
TOTI (% of Wellhead Revenue)
(GAAP)
|
7.8 %
|
|
8.5 %
|
(0.7 %)
|
7.8 %
|
7.8 %
|
5.5 %
|
7.3 %
|
|
TOTI (% of Wellhead Revenue)
(non-GAAP)1
|
7.8 %
|
|
8.5 %
|
(0.7 %)
|
7.8 %
|
7.8 %
|
7.4 %
|
7.3 %
|
|
Income Taxes
|
|
|
|
|
Effective
Rate
|
21.9 %
|
|
21.5 %
|
0.4 %
|
22.0 %
|
20.4 %
|
22.1 %
|
22.3 %
|
|
Current Tax (Benefit)
/ Expense ($MM)
|
241
|
|
365
|
(124)
|
338
|
409
|
481
|
745
|
|
Third Quarter and Full-Year 2023
Guidance7
|
|
|
(Unaudited)
|
|
|
See "Endnotes" below for related discussion and
definitions.
|
|
|
|
3Q 2023
Guidance
Range
|
3Q 2023
Midpoint
|
FY 2023
Guidance
Range
|
FY 2023
Midpoint
|
2022
Actual
|
2021
Actual
|
2020
Actual
|
|
|
Crude Oil and Condensate Volumes
(MBod)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
467.0
|
-
|
478.0
|
472.5
|
471.0
|
-
|
476.0
|
473.5
|
460.7
|
443.4
|
408.1
|
|
|
Trinidad
|
0.2
|
-
|
0.6
|
0.4
|
0.3
|
-
|
0.5
|
0.4
|
0.6
|
1.5
|
1.0
|
|
|
Other
International
|
0.0
|
-
|
0.0
|
0.0
|
0.0
|
-
|
0.0
|
0.0
|
0.0
|
0.1
|
0.1
|
|
|
Total
|
467.2
|
-
|
478.6
|
472.9
|
471.3
|
-
|
476.5
|
473.9
|
461.3
|
445.0
|
409.2
|
|
|
Natural Gas Liquids Volumes
(MBbld)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
218.0
|
-
|
228.0
|
223.0
|
219.0
|
-
|
225.0
|
222.0
|
197.7
|
144.5
|
136.0
|
|
|
Natural Gas Volumes (MMcfd)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
1,500
|
-
|
1,560
|
1,530
|
1,510
|
-
|
1,570
|
1,540
|
1,315
|
1,210
|
1,040
|
|
|
Trinidad
|
115
|
-
|
145
|
130
|
140
|
-
|
170
|
155
|
180
|
217
|
180
|
|
|
Other
International
|
0
|
-
|
0
|
0
|
0
|
-
|
0
|
0
|
0
|
9
|
32
|
|
|
Total
|
1,615
|
-
|
1,705
|
1,660
|
1,650
|
-
|
1,740
|
1,695
|
1,495
|
1,436
|
1,252
|
|
|
Crude Oil Equivalent Volumes
(MBoed)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
935.0
|
-
|
966.0
|
950.5
|
941.7
|
-
|
962.7
|
952.2
|
877.5
|
789.6
|
717.5
|
|
|
Trinidad
|
19.4
|
-
|
24.8
|
22.1
|
23.6
|
-
|
28.8
|
26.2
|
30.7
|
37.7
|
30.9
|
|
|
Other
International
|
0.0
|
-
|
0.0
|
0.0
|
0.0
|
-
|
0.0
|
0.0
|
0.0
|
1.6
|
5.4
|
|
|
Total
|
954.4
|
-
|
990.8
|
972.6
|
965.3
|
-
|
991.5
|
978.4
|
908.2
|
828.9
|
753.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benchmark Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (WTI)
($/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
|
0.50
|
-
|
1.50
|
1.00
|
0.50
|
-
|
1.50
|
1.00
|
2.99
|
0.58
|
(0.75)
|
|
|
Trinidad
|
(11.00)
|
-
|
(9.00)
|
(10.00)
|
(9.50)
|
-
|
(8.50)
|
(9.00)
|
(8.07)
|
(11.70)
|
(9.20)
|
|
|
Natural Gas Liquids - Realizations as % of
WTI
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
23.0 %
|
-
|
33.0 %
|
28.0 %
|
27.0 %
|
-
|
33.0 %
|
30.0 %
|
39.0 %
|
50.5 %
|
34.0 %
|
|
|
Natural Gas - above (below) NYMEX Henry
Hub4
($/Mcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
(0.30)
|
-
|
0.20
|
(0.05)
|
(0.50)
|
-
|
0.50
|
0.00
|
0.63
|
1.03
|
(0.47)
|
|
|
Natural Gas
Realizations5 ($/Mcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Trinidad
|
3.00
|
-
|
3.70
|
3.35
|
3.30
|
-
|
3.80
|
3.55
|
4.43
|
3.40
|
2.57
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Expenditures (GAAP) ($MM)
|
|
|
|
|
|
|
|
|
5,610
|
4,255
|
4,113
|
|
|
Capital Expenditures8 (non-GAAP) ($MM)
|
1,560
|
-
|
1,760
|
1,660
|
5,800
|
-
|
6,200
|
6,000
|
4,607
|
3,755
|
3,344
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Unit Costs ($/Boe)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease and
Well
|
3.90
|
-
|
4.50
|
4.20
|
4.00
|
-
|
4.30
|
4.15
|
4.02
|
3.75
|
3.85
|
|
|
Transportation
Costs
|
2.55
|
-
|
2.85
|
2.70
|
2.70
|
-
|
2.80
|
2.75
|
2.91
|
2.85
|
2.66
|
|
|
Gathering and
Processing
|
1.80
|
-
|
2.00
|
1.90
|
1.85
|
-
|
1.95
|
1.90
|
1.87
|
1.85
|
1.66
|
|
|
General and
Administrative (GAAP)
|
1.75
|
-
|
2.05
|
1.90
|
1.65
|
-
|
1.80
|
1.73
|
1.72
|
1.69
|
1.75
|
|
|
General and
Administrative (non-GAAP)1
|
|
|
|
|
|
|
|
|
1.67
|
1.69
|
1.75
|
|
|
Cash Operating Costs
(GAAP)
|
10.00
|
-
|
11.40
|
10.70
|
10.20
|
-
|
10.85
|
10.53
|
10.52
|
10.14
|
9.92
|
|
|
Cash Operating Costs
(non-GAAP)
|
|
|
|
|
|
|
|
|
10.47
|
10.14
|
9.92
|
|
|
Depreciation,
Depletion and Amortization
|
9.40
|
-
|
10.40
|
9.90
|
9.60
|
-
|
10.20
|
9.90
|
10.69
|
12.07
|
12.32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses ($MM)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and Dry
Hole
|
45
|
-
|
85
|
65
|
170
|
-
|
230
|
200
|
204
|
225
|
159
|
|
|
Impairment
(GAAP)
|
|
|
|
|
|
|
|
|
382
|
376
|
2,100
|
|
|
Impairment (excluding
certain impairments (non GAAP))6
|
65
|
-
|
135
|
100
|
200
|
-
|
340
|
270
|
269
|
361
|
232
|
|
|
Capitalized
Interest
|
8
|
-
|
12
|
10
|
32
|
-
|
36
|
34
|
36
|
33
|
31
|
|
|
Net
Interest
|
32
|
-
|
36
|
34
|
142
|
-
|
146
|
144
|
179
|
178
|
205
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTI (% of Wellhead Revenue)
(GAAP)
|
7.5 %
|
-
|
9.5 %
|
8.5 %
|
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)
|
295
|
-
|
395
|
345
|
1,130
|
-
|
1,330
|
1,230
|
2,208
|
1,393
|
(61)
|
|
|
Second Quarter 2023 Results Webcast
Friday, August 4, 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
David
Streit 713-571-4902
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, 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 third 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
|
|
|
6,434
|
|
Natural Gas
Liquids
|
681
|
777
|
693
|
497
|
2,648
|
|
490
|
409
|
|
|
899
|
|
Natural
Gas
|
716
|
1,000
|
1,235
|
830
|
3,781
|
|
517
|
334
|
|
|
851
|
|
Gains (Losses)
on Mark-to-Market
Financial Commodity Derivative
Contracts, Net
|
(2,820)
|
(1,377)
|
(18)
|
233
|
(3,982)
|
|
376
|
101
|
|
|
477
|
|
Gathering, Processing
and Marketing
|
1,469
|
2,169
|
1,561
|
1,497
|
6,696
|
|
1,390
|
1,465
|
|
|
2,855
|
|
Gains (Losses) on
Asset Dispositions,
Net
|
25
|
97
|
(21)
|
(27)
|
74
|
|
69
|
(9)
|
|
|
60
|
|
Other, Net
|
23
|
42
|
34
|
19
|
118
|
|
20
|
21
|
|
|
41
|
|
Total
|
3,983
|
7,407
|
7,593
|
6,719
|
25,702
|
|
6,044
|
5,573
|
|
|
11,617
|
|
|
|
|
|
|
|
Operating Expenses
|
|
|
|
|
|
Lease and
Well
|
318
|
324
|
335
|
354
|
1,331
|
|
359
|
348
|
|
|
707
|
|
Transportation
Costs
|
228
|
244
|
257
|
237
|
966
|
|
236
|
236
|
|
|
472
|
|
Gathering and
Processing Costs
|
144
|
152
|
167
|
158
|
621
|
|
159
|
160
|
|
|
319
|
|
Exploration
Costs
|
45
|
35
|
35
|
44
|
159
|
|
50
|
47
|
|
|
97
|
|
Dry Hole
Costs
|
3
|
20
|
18
|
4
|
45
|
|
1
|
—
|
|
|
1
|
|
Impairments
|
55
|
91
|
94
|
142
|
382
|
|
34
|
35
|
|
|
69
|
|
Marketing
Costs
|
1,283
|
2,127
|
1,621
|
1,504
|
6,535
|
|
1,361
|
1,456
|
|
|
2,817
|
|
Depreciation,
Depletion and Amortization
|
847
|
911
|
906
|
878
|
3,542
|
|
798
|
866
|
|
|
1,664
|
|
General and
Administrative
|
124
|
128
|
162
|
156
|
570
|
|
145
|
142
|
|
|
287
|
|
Taxes Other Than
Income
|
390
|
472
|
334
|
389
|
1,585
|
|
329
|
313
|
|
|
642
|
|
Total
|
3,437
|
4,504
|
3,929
|
3,866
|
15,736
|
|
3,472
|
3,603
|
|
|
7,075
|
|
|
|
|
|
|
|
Operating Income
|
546
|
2,903
|
3,664
|
2,853
|
9,966
|
|
2,572
|
1,970
|
|
|
4,542
|
|
Other Income
(Expense), Net
|
(1)
|
27
|
40
|
48
|
114
|
|
65
|
51
|
|
|
116
|
|
Income Before
Interest Expense and
Income Taxes
|
545
|
2,930
|
3,704
|
2,901
|
10,080
|
|
2,637
|
2,021
|
|
|
4,658
|
|
Interest Expense,
Net
|
48
|
48
|
41
|
42
|
179
|
|
42
|
35
|
|
|
77
|
|
Income Before Income
Taxes
|
497
|
2,882
|
3,663
|
2,859
|
9,901
|
|
2,595
|
1,986
|
|
|
4,581
|
|
Income Tax
Provision
|
107
|
644
|
809
|
582
|
2,142
|
|
572
|
433
|
|
|
1,005
|
|
Net Income
|
390
|
2,238
|
2,854
|
2,277
|
7,759
|
|
2,023
|
1,553
|
|
|
3,576
|
|
|
|
|
|
|
|
Dividends Declared
per Common Share
|
1.7500
|
2.5500
|
2.2500
|
2.3250
|
8.8750
|
|
1.8250
|
0.8250
|
|
|
2.6500
|
|
Net Income Per
Share
|
|
|
|
|
|
Basic
|
0.67
|
3.84
|
4.90
|
3.90
|
13.31
|
|
3.46
|
2.68
|
|
|
6.14
|
|
Diluted
|
0.67
|
3.81
|
4.86
|
3.87
|
13.22
|
|
3.45
|
2.66
|
|
|
6.10
|
|
Average Number of
Common Shares
|
|
|
|
|
|
Basic
|
582
|
583
|
583
|
584
|
583
|
|
584
|
580
|
|
|
582
|
|
Diluted
|
586
|
588
|
587
|
588
|
587
|
|
587
|
584
|
|
|
586
|
|
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
|
|
|
466.6
|
|
Trinidad
|
0.7
|
0.6
|
0.5
|
0.5
|
0.6
|
|
0.6
|
0.6
|
|
|
0.6
|
|
Total
|
450.1
|
464.1
|
465.1
|
465.6
|
461.3
|
|
457.7
|
476.6
|
|
|
467.2
|
|
|
|
|
|
|
|
Average Crude Oil and
Condensate Prices ($/ Bbl) (B)
|
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
$ 96.02
|
$ 111.26
|
$ 96.05
|
$ 85.68
|
$ 97.22
|
|
$ 77.27
|
$ 74.98
|
|
|
$ 76.10
|
|
Trinidad
|
83.82
|
98.29
|
84.98
|
75.21
|
86.16
|
|
68.98
|
64.88
|
|
|
66.92
|
|
Composite
|
96.00
|
111.25
|
96.04
|
85.67
|
97.21
|
|
77.26
|
74.97
|
|
|
76.09
|
|
|
|
|
|
|
|
Natural Gas Liquids
Volumes (MBbld) (A)
|
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
190.3
|
201.9
|
209.3
|
189.0
|
197.7
|
|
212.2
|
215.7
|
|
|
213.9
|
|
Total
|
190.3
|
201.9
|
209.3
|
189.0
|
197.7
|
|
212.2
|
215.7
|
|
|
213.9
|
|
|
|
|
|
|
|
Average Natural Gas
Liquids Prices ($/Bbl) (B)
|
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
$ 39.77
|
$ 42.28
|
$ 36.02
|
$ 28.55
|
$ 36.70
|
|
$ 25.67
|
$ 20.85
|
|
|
$ 23.23
|
|
Composite
|
39.77
|
42.28
|
36.02
|
28.55
|
36.70
|
|
25.67
|
20.85
|
|
|
23.23
|
|
|
|
|
|
|
|
Natural Gas Volumes
(MMcfd) (A)
|
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
1,249
|
1,324
|
1,306
|
1,378
|
1,315
|
|
1,475
|
1,513
|
|
|
1,494
|
|
Trinidad
|
209
|
204
|
163
|
149
|
180
|
|
164
|
155
|
|
|
160
|
|
Total
|
1,458
|
1,528
|
1,469
|
1,527
|
1,495
|
|
1,639
|
1,668
|
|
|
1,654
|
|
|
|
|
|
|
|
Average Natural Gas
Prices ($/Mcf) (B)
|
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
$ 5.81
|
$ 7.77
|
$ 9.35
|
$ 6.12
|
$ 7.27
|
|
$ 3.47
|
$ 2.07
|
|
|
$ 2.76
|
|
Trinidad
(D)
|
3.36
|
3.42
|
7.45
|
3.97
|
4.43
|
|
3.87
|
3.45
|
|
|
3.67
|
|
Composite
|
5.46
|
7.19
|
9.14
|
5.91
|
6.93
|
|
3.51
|
2.20
|
|
|
2.84
|
|
|
|
|
|
|
|
Crude Oil Equivalent
Volumes (MBoed) (C)
|
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
847.8
|
886.1
|
891.6
|
883.8
|
877.5
|
|
915.0
|
943.8
|
|
|
929.5
|
|
Trinidad
|
35.5
|
34.6
|
27.6
|
25.3
|
30.7
|
|
28.0
|
26.5
|
|
|
27.2
|
|
Total
|
883.3
|
920.7
|
919.2
|
909.1
|
908.2
|
|
943.0
|
970.3
|
|
|
956.7
|
|
|
|
|
|
|
|
Total MMBoe (C)
|
79.5
|
83.8
|
84.6
|
83.6
|
331.5
|
|
84.9
|
88.3
|
|
|
173.2
|
|
|
|
|
(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 June 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
|
|
|
|
Accounts Receivable,
Net
|
3,213
|
3,735
|
3,343
|
2,774
|
|
2,455
|
2,263
|
|
|
|
Inventories
|
586
|
739
|
872
|
1,058
|
|
1,131
|
1,355
|
|
|
|
Assets from Price
Risk Management Activities
|
—
|
1
|
—
|
—
|
|
—
|
—
|
|
|
|
Income Taxes
Receivable
|
—
|
—
|
93
|
97
|
|
—
|
1
|
|
|
|
Other
|
671
|
605
|
621
|
574
|
|
580
|
523
|
|
|
|
Total
|
8,479
|
8,153
|
10,201
|
10,475
|
|
9,184
|
8,906
|
|
|
|
|
|
|
|
|
Property, Plant and Equipment
|
|
|
|
|
Oil and Gas
Properties (Successful Efforts Method)
|
65,408
|
66,098
|
67,065
|
67,322
|
|
67,907
|
69,178
|
|
|
|
Other Property, Plant
and Equipment
|
4,801
|
4,862
|
4,659
|
4,786
|
|
5,101
|
5,282
|
|
|
|
Total Property, Plant
and Equipment
|
70,209
|
70,960
|
71,724
|
72,108
|
|
73,008
|
74,460
|
|
|
|
Less: Accumulated
Depreciation, Depletion and Amortization
|
(41,747)
|
(42,113)
|
(42,623)
|
(42,679)
|
|
(42,785)
|
(43,550)
|
|
|
|
Total Property, Plant and Equipment,
Net
|
28,462
|
28,847
|
29,101
|
29,429
|
|
30,223
|
30,910
|
|
|
|
Deferred Income Taxes
|
13
|
12
|
18
|
33
|
|
31
|
33
|
|
|
|
Other Assets
|
1,143
|
1,127
|
1,167
|
1,434
|
|
1,587
|
1,638
|
|
|
|
Total Assets
|
38,097
|
38,139
|
40,487
|
41,371
|
|
41,025
|
41,487
|
|
|
|
|
|
|
|
|
Current Liabilities
|
|
|
|
|
Accounts
Payable
|
2,660
|
2,896
|
2,718
|
2,532
|
|
2,438
|
2,205
|
|
|
|
Accrued Taxes
Payable
|
1,130
|
594
|
542
|
405
|
|
637
|
425
|
|
|
|
Dividends
Payable
|
436
|
437
|
437
|
482
|
|
482
|
478
|
|
|
|
Liabilities from
Price Risk Management Activities
|
260
|
79
|
243
|
169
|
|
31
|
22
|
|
|
|
Current Portion of
Long-Term Debt
|
1,283
|
1,282
|
1,282
|
1,283
|
|
33
|
34
|
|
|
|
Current Portion of
Operating Lease Liabilities
|
223
|
216
|
235
|
296
|
|
354
|
335
|
|
|
|
Other
|
272
|
264
|
289
|
346
|
|
253
|
232
|
|
|
|
Total
|
6,264
|
5,768
|
5,746
|
5,513
|
|
4,228
|
3,731
|
|
|
|
|
|
|
|
|
Long-Term Debt
|
3,816
|
3,809
|
3,802
|
3,795
|
|
3,787
|
3,780
|
|
|
|
Other Liabilities
|
2,191
|
2,067
|
2,573
|
2,574
|
|
2,620
|
2,581
|
|
|
|
Deferred Income Taxes
|
4,286
|
4,183
|
4,517
|
4,710
|
|
4,943
|
5,138
|
|
|
|
Commitments and Contingencies
|
|
|
|
|
|
|
|
|
|
Stockholders' Equity
|
|
|
|
|
Common Stock, $0.01
Par
|
206
|
206
|
206
|
206
|
|
206
|
206
|
|
|
|
Additional Paid in
Capital
|
6,095
|
6,128
|
6,155
|
6,187
|
|
6,219
|
6,257
|
|
|
|
Accumulated Other
Comprehensive Loss
|
(13)
|
(12)
|
(6)
|
(8)
|
|
(8)
|
(9)
|
|
|
|
Retained
Earnings
|
15,283
|
16,028
|
17,563
|
18,472
|
|
19,423
|
20,497
|
|
|
|
Common Stock Held in
Treasury
|
(31)
|
(38)
|
(69)
|
(78)
|
|
(393)
|
(694)
|
|
|
|
Total Stockholders' Equity
|
21,540
|
22,312
|
23,849
|
24,779
|
|
25,447
|
26,257
|
|
|
|
Total Liabilities and Stockholders'
Equity
|
38,097
|
38,139
|
40,487
|
41,371
|
|
41,025
|
41,487
|
|
|
|
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
|
|
|
3,576
|
|
Items Not Requiring
(Providing) Cash
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation,
Depletion and Amortization
|
847
|
911
|
906
|
878
|
3,542
|
|
798
|
866
|
|
|
1,664
|
|
Impairments
|
55
|
91
|
94
|
142
|
382
|
|
34
|
35
|
|
|
69
|
|
Stock-Based
Compensation Expenses
|
35
|
30
|
34
|
34
|
133
|
|
34
|
35
|
|
|
69
|
|
Deferred Income
Taxes
|
(465)
|
(102)
|
327
|
179
|
(61)
|
|
234
|
194
|
|
|
428
|
|
(Gains) Losses on
Asset Dispositions, Net
|
(25)
|
(97)
|
21
|
27
|
(74)
|
|
(69)
|
9
|
|
|
(60)
|
|
Other, Net
|
6
|
(16)
|
(5)
|
15
|
—
|
|
4
|
2
|
|
|
6
|
|
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)
|
|
|
(477)
|
|
Net Cash Payments for
Settlements of
Financial Commodity Derivative
Contracts
|
(296)
|
(2,114)
|
(847)
|
(244)
|
(3,501)
|
|
(123)
|
(30)
|
|
|
(153)
|
|
Other, Net
|
2
|
19
|
12
|
12
|
45
|
|
(1)
|
—
|
|
|
(1)
|
|
Changes in Components
of Working Capital and
Other Assets and Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
Receivable
|
(878)
|
(522)
|
392
|
661
|
(347)
|
|
338
|
137
|
|
|
475
|
|
Inventories
|
(14)
|
(157)
|
(140)
|
(223)
|
(534)
|
|
(77)
|
(226)
|
|
|
(303)
|
|
Accounts
Payable
|
130
|
259
|
(88)
|
(211)
|
90
|
|
(77)
|
(231)
|
|
|
(308)
|
|
Accrued Taxes
Payable
|
613
|
(536)
|
(53)
|
(137)
|
(113)
|
|
232
|
(212)
|
|
|
20
|
|
Other
Assets
|
(213)
|
71
|
(129)
|
(93)
|
(364)
|
|
52
|
43
|
|
|
95
|
|
Other
Liabilities
|
(2,250)
|
433
|
1,269
|
282
|
(266)
|
|
193
|
(47)
|
|
|
146
|
|
Changes in Components
of Working Capital
Associated with Investing Activities
|
68
|
143
|
90
|
74
|
375
|
|
35
|
250
|
|
|
285
|
|
Net Cash Provided by Operating
Activities
|
828
|
2,048
|
4,773
|
3,444
|
11,093
|
|
3,255
|
2,277
|
|
|
5,532
|
|
Investing Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to Oil and
Gas Properties
|
(939)
|
(1,349)
|
(1,102)
|
(1,229)
|
(4,619)
|
|
(1,305)
|
(1,341)
|
|
|
(2,646)
|
|
Additions to Other Property, Plant and Equipment
|
(70)
|
(75)
|
(103)
|
(133)
|
(381)
|
|
(319)
|
(180)
|
|
|
(499)
|
|
Proceeds from Sales of Assets
|
121
|
110
|
79
|
39
|
349
|
|
92
|
29
|
|
|
121
|
|
Other Investing Activities
|
—
|
(30)
|
—
|
—
|
(30)
|
|
—
|
—
|
|
|
—
|
|
Changes in Components
of Working Capital
Associated with Investing Activities
|
(68)
|
(143)
|
(90)
|
(74)
|
(375)
|
|
(35)
|
(250)
|
|
|
(285)
|
|
Net Cash Used in Investing
Activities
|
(956)
|
(1,487)
|
(1,216)
|
(1,397)
|
(5,056)
|
|
(1,567)
|
(1,742)
|
|
|
(3,309)
|
|
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)
|
|
|
(1,547)
|
|
Treasury Stock
Purchased
|
(43)
|
(15)
|
(37)
|
(23)
|
(118)
|
|
(317)
|
(302)
|
|
|
(619)
|
|
Proceeds from Stock
Options Exercised and
Employee Stock Purchase Plan
|
4
|
13
|
—
|
11
|
28
|
|
—
|
9
|
|
|
9
|
|
Debt Issuance
Costs
|
—
|
—
|
—
|
—
|
—
|
|
—
|
(8)
|
|
|
(8)
|
|
Repayment of Finance
Lease Liabilities
|
(10)
|
(9)
|
(8)
|
(8)
|
(35)
|
|
(8)
|
(8)
|
|
|
(16)
|
|
Net Cash Used in Financing
Activities
|
(1,072)
|
(1,497)
|
(1,357)
|
(1,347)
|
(5,273)
|
|
(2,642)
|
(789)
|
|
|
(3,431)
|
|
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)
|
|
|
(1,208)
|
|
Cash and Cash Equivalents at Beginning of
Period
|
5,209
|
4,009
|
3,073
|
5,272
|
5,209
|
|
5,972
|
5,018
|
|
|
5,972
|
|
Cash and Cash Equivalents at End of
Period
|
4,009
|
3,073
|
5,272
|
5,972
|
5,972
|
|
5,018
|
4,764
|
|
|
4,764
|
|
Non-GAAP Financial
Measure
|
|
|
|
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 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.
|
|
|
|
|
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.
|
Adjusted Net Income (Loss)
|
|
(Continued)
|
|
In millions of USD,
except share data (in millions) and per share data
(Unaudited)
|
|
|
|
|
2Q
2022
|
|
|
Before
Tax
|
Income Tax
Impact
|
After
Tax
|
Diluted Earnings per
Share
|
|
|
|
|
|
|
|
Reported Net Income (GAAP)
|
2,882
|
(644)
|
2,238
|
3.81
|
|
Adjustments:
|
|
|
|
|
|
Losses on
Mark-to-Market Financial Commodity Derivative Contracts,
Net
|
1,377
|
(299)
|
1,078
|
1.82
|
|
Net Cash Payments for
Settlements of Financial Commodity Derivative Contracts
(1)
|
(2,114)
|
459
|
(1,655)
|
(2.81)
|
|
Less: Gains on Asset
Dispositions, Net
|
(97)
|
21
|
(76)
|
(0.13)
|
|
Add: Certain
Impairments
|
36
|
(7)
|
29
|
0.05
|
|
Adjustments to Net
Income
|
(798)
|
174
|
(624)
|
(1.07)
|
|
|
|
|
|
|
|
Adjusted Net Income (Non-GAAP)
|
2,084
|
(470)
|
1,614
|
2.74
|
|
|
|
|
|
|
|
Average Number of
Common Shares (Non-GAAP)
|
|
|
|
|
|
Basic
|
|
|
|
583
|
|
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
June 30, 2022, such amount was $2,114 million, of which $1,328
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)
|
|
|
|
|
|
|
|
1Q 2023 Net Income per Share
(GAAP)
|
|
3.45
|
|
|
|
|
|
Realized Price
|
|
|
|
2Q 2023 Composite
Average Wellhead Revenue per Boe
|
45.24
|
|
|
Less: 1Q 2023
Composite Average Wellhead Revenue per Boe
|
(49.37)
|
|
|
Subtotal
|
(4.13)
|
|
|
Multiplied by: 2Q
2023 Crude Oil Equivalent Volumes (MMBoe)
|
88.3
|
|
|
Total Change in
Revenue
|
(365)
|
|
|
Less: Income Tax
Benefit (Provision) Imputed (based on 22%)
|
80
|
|
|
Change in Net
Income
|
(285)
|
|
|
Change in Diluted
Earnings per Share
|
|
(0.49)
|
|
|
|
|
|
Wellhead Volumes
|
|
|
|
2Q 2023 Crude Oil
Equivalent Volumes (MMBoe)
|
88.3
|
|
|
Less: 1Q 2023 Crude
Oil Equivalent Volumes (MMBoe)
|
(84.9)
|
|
|
Subtotal
|
3.4
|
|
|
Multiplied by: 2Q
2023 Composite Average Margin per Boe (Non-GAAP)
(Including Total Exploration Costs)(refer to
"Revenues Costs and Margins Per Barrel of Oil
Equivalent" schedule)
|
20.53
|
|
|
Change in
Margin
|
70
|
|
|
Less: Income Tax
Benefit (Provision) Imputed (based on 22%)
|
(15)
|
|
|
Change in Net
Income
|
55
|
|
|
Change in Diluted
Earnings per Share
|
|
0.09
|
|
|
|
|
|
Certain Operating Costs
per Boe
|
|
|
|
1Q
2023 Total Cash Operating Costs (GAAP) and Total DD&A
per Boe (refer to "Revenues,
Costs and
Margins Per Barrel of Oil Equivalent"
schedule)
|
19.99
|
|
|
Less: 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)
|
|
|
Subtotal
|
0.15
|
|
|
Multiplied by: 2Q
2023 Crude Oil Equivalent Volumes (MMBoe)
|
88.3
|
|
|
Change in Before-Tax
Net Income
|
13
|
|
|
Less: Income Tax
Benefit (Provision) Imputed (based on 22%)
|
(3)
|
|
|
Change in Net
Income
|
10
|
|
|
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
|
|
|
|
2Q 2023 Net Gains
(Losses) on Mark-to-Market Financial Commodity Derivative
Contracts
|
101
|
|
|
Less: Income Tax
Benefit (Provision)
|
(22)
|
|
|
After Tax -
(a)
|
79
|
|
|
Less: 1Q 2023 Net
Gains (Losses) on Mark-to-Market Financial Commodity Derivative
Contracts
|
376
|
|
|
Less: Income Tax
Benefit (Provision)
|
(81)
|
|
|
After Tax -
(b)
|
295
|
|
|
Change in Net Income
- (a) - (b)
|
(216)
|
|
|
Change in Diluted
Earnings per Share
|
|
(0.37)
|
|
|
|
|
|
Other (1)
|
|
(0.04)
|
|
|
|
|
|
2Q 2023 Net Income per Share
(GAAP)
|
|
2.66
|
|
|
|
|
|
2Q 2023 Average
Number of Common Shares (GAAP) - Diluted
|
584
|
|
|
|
|
(1)
|
Includes gathering,
processing and marketing revenue, gains (losses) on asset
dispositions, other revenue, exploration, dry hole, impairments and
marketing costs, taxes other than income, other income (expense),
interest expense and the impact of changes in the effective income
tax rate.
|
Adjusted Net Income
Per Share
|
|
|
|
In millions of USD,
except share data (in millions), per share data, production volume
data and per Boe data (Unaudited)
|
|
|
|
1Q 2023 Adjusted Net Income per Share
(Non-GAAP)
|
|
2.69
|
|
|
|
|
|
Realized Price
|
|
|
|
2Q 2023 Composite
Average Wellhead Revenue per Boe
|
45.24
|
|
|
Less: 1Q 2023
Composite Average Wellhead Revenue per Boe
|
(49.37)
|
|
|
Subtotal
|
(4.13)
|
|
|
Multiplied by: 2Q
2023 Crude Oil Equivalent Volumes (MMBoe)
|
88.3
|
|
|
Total Change in
Revenue
|
(365)
|
|
|
Less: Income Tax
Benefit (Provision) Imputed (based on 22%)
|
80
|
|
|
Change in Net
Income
|
(285)
|
|
|
Change in Diluted
Earnings per Share
|
|
(0.49)
|
|
Wellhead Volumes
|
|
|
|
2Q 2023 Crude Oil
Equivalent Volumes (MMBoe)
|
88.3
|
|
|
Less: 1Q 2023 Crude
Oil Equivalent Volumes (MMBoe)
|
(84.9)
|
|
|
Subtotal
|
3.4
|
|
|
Multiplied by: 2Q
2023 Composite Average Margin per Boe (Non-GAAP) (Including
Total
Exploration Costs) (refer to "Revenues, Costs
and Margins Per Barrel of Oil Equivalent" schedule)
|
20.53
|
|
|
Change in
Margin
|
70
|
|
|
Less: Income Tax
Benefit (Provision) Imputed (based on 22%)
|
(15)
|
|
|
Change in Net
Income
|
55
|
|
|
Change in Diluted
Earnings per Share
|
|
0.09
|
|
|
|
|
|
Certain Operating Costs
per Boe
|
|
|
|
1Q
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)
|
19.99
|
|
|
Less: 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)
|
|
|
Subtotal
|
0.15
|
|
|
Multiplied by: 2Q
2023 Crude Oil Equivalent Volumes (MMBoe)
|
88.3
|
|
|
Change in Before-Tax
Net Income
|
13
|
|
|
Less: Income Tax
Benefit (Provision) Imputed (based on 22%)
|
(3)
|
|
|
Change in Net
Income
|
10
|
|
|
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
|
|
|
|
2Q 2023 Net Cash
Received from (Payments for) Settlement of Financial Commodity
Derivative
Contracts
|
(30)
|
|
|
Less: Income Tax
Benefit (Provision)
|
6
|
|
|
After Tax - (a)
|
(24)
|
|
|
1Q 2023 Net Cash
Received from (Payments for) Settlement of Financial Commodity
Derivative
Contracts
|
(123)
|
|
|
Less: Income Tax
Benefit (Provision)
|
27
|
|
|
After Tax -
(b)
|
(96)
|
|
|
Change in Net Income
- (a) - (b)
|
72
|
|
|
Change in Diluted
Earnings per Share
|
|
0.12
|
|
|
|
|
|
Other (1)
|
|
0.06
|
|
|
|
|
|
2Q 2023 Adjusted Net Income per Share
(Non-GAAP)
|
|
2.49
|
|
|
|
|
|
2Q 2023 Average
Number of Common Shares (Non-GAAP) - Diluted
|
584
|
|
|
|
|
(1)
|
Includes gathering,
processing and marketing revenue, other revenue, exploration, dry
hole, impairments and marketing costs, taxes other than income,
other income (expense), interest expense and the impact of changes
in the effective income tax rate.
|
Cash Flow from Operations and Free Cash
Flow
|
|
|
In millions of USD
(Unaudited)
|
|
|
|
|
|
The following tables
reconcile Net Cash Provided by Operating Activities (GAAP) to Cash
Flow from Operations Before 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 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
|
|
|
5,532
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
Changes in Components
of Working Capital and Other Assets and Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
Receivable
|
878
|
522
|
(392)
|
(661)
|
347
|
|
(338)
|
(137)
|
|
|
(475)
|
|
Inventories
|
14
|
157
|
140
|
223
|
534
|
|
77
|
226
|
|
|
303
|
|
Accounts
Payable
|
(130)
|
(259)
|
88
|
211
|
(90)
|
|
77
|
231
|
|
|
308
|
|
Accrued Taxes
Payable
|
(613)
|
536
|
53
|
137
|
113
|
|
(232)
|
212
|
|
|
(20)
|
|
Other
Assets
|
213
|
(71)
|
129
|
93
|
364
|
|
(52)
|
(43)
|
|
|
(95)
|
|
Other
Liabilities
|
2,250
|
(433)
|
(1,269)
|
(282)
|
266
|
|
(193)
|
47
|
|
|
(146)
|
|
Changes in Components
of Working Capital Associated with Investing Activities
|
(68)
|
(143)
|
(90)
|
(74)
|
(375)
|
|
(35)
|
(250)
|
|
|
(285)
|
|
Cash Flow from Operations Before Working Capital
(Non-GAAP)
|
3,372
|
2,357
|
3,432
|
3,091
|
12,252
|
|
2,559
|
2,563
|
|
|
5,122
|
|
|
|
|
|
|
|
Cash Flow from
Operations Before Working Capital (Non-GAAP)
|
3,372
|
2,357
|
3,432
|
3,091
|
12,252
|
|
2,559
|
2,563
|
|
|
5,122
|
|
Less:
|
|
|
|
|
|
Total Capital
Expenditures (Non-GAAP) (a)
|
(1,009)
|
(1,071)
|
(1,166)
|
(1,361)
|
(4,607)
|
|
(1,489)
|
(1,521)
|
|
|
(3,010)
|
|
Free Cash Flow (Non-GAAP)
|
2,363
|
1,286
|
2,266
|
1,730
|
7,645
|
|
1,070
|
1,042
|
|
|
2,112
|
|
|
|
|
(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
|
|
|
3,381
|
|
Less:
|
|
|
|
|
|
Asset Retirement
Costs
|
(27)
|
(43)
|
(139)
|
(89)
|
(298)
|
|
(10)
|
(26)
|
|
|
(36)
|
|
Non-Cash Acquisition
Costs of Unproved Properties
|
(58)
|
(21)
|
(28)
|
(20)
|
(127)
|
|
(31)
|
(28)
|
|
|
(59)
|
|
Non-Cash Development
Drilling
|
—
|
—
|
—
|
—
|
—
|
|
—
|
(35)
|
|
|
(35)
|
|
Acquisition Costs of
Proved Properties
|
(5)
|
(351)
|
(42)
|
(21)
|
(419)
|
|
(4)
|
(6)
|
|
|
(10)
|
|
Acquisition Costs of
Other Property, Plant and Equipment
|
—
|
—
|
—
|
—
|
—
|
|
(133)
|
(1)
|
|
|
(134)
|
|
Exploration
Costs
|
(45)
|
(35)
|
(35)
|
(44)
|
(159)
|
|
(50)
|
(47)
|
|
|
(97)
|
|
Total Capital Expenditures
(Non-GAAP)
|
1,009
|
1,071
|
1,166
|
1,361
|
4,607
|
|
1,489
|
1,521
|
|
|
3,010
|
|
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.
|
|
|
|
|
June 30,
2023
|
March 31,
2023
|
December 31,
2022
|
September 30,
2022
|
June 30,
2022
|
|
|
|
|
|
|
|
|
Total Stockholders'
Equity - (a)
|
26,257
|
25,447
|
24,779
|
23,849
|
22,312
|
|
|
|
|
|
|
|
|
Current and Long-Term
Debt (GAAP) - (b)
|
3,814
|
3,820
|
5,078
|
5,084
|
5,091
|
|
Less: Cash
|
(4,764)
|
(5,018)
|
(5,972)
|
(5,272)
|
(3,073)
|
|
Net Debt (Non-GAAP) -
(c)
|
(950)
|
(1,198)
|
(894)
|
(188)
|
2,018
|
|
|
|
|
|
|
|
|
Total Capitalization
(GAAP) - (a) + (b)
|
30,071
|
29,267
|
29,857
|
28,933
|
27,403
|
|
|
|
|
|
|
|
|
Total Capitalization (Non-GAAP) - (a) +
(c)
|
25,307
|
24,249
|
23,885
|
23,661
|
24,330
|
|
|
|
|
|
|
|
|
Debt-to-Total
Capitalization (GAAP) - (b) / [(a) + (b)]
|
12.7 %
|
13.1 %
|
17.0 %
|
17.6 %
|
18.6 %
|
|
|
|
|
|
|
|
|
Net Debt-to-Total Capitalization (Non-GAAP) - (c)
/
[(a) + (c)]
|
-3.8 %
|
-4.9 %
|
-3.7 %
|
-0.8 %
|
8.3 %
|
|
View original
content:https://www.prnewswire.com/news-releases/eog-resources-reports-second-quarter-2023-results-301893106.html
SOURCE EOG Resources, Inc.