Delaware
|
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25-0996816
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(State or other jurisdiction of incorporation or organization)
|
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(I.R.S. Employer Identification No.)
|
Title of each class
|
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Name of each exchange on which registered
|
Common Stock, par value $1.00
|
|
New York Stock Exchange
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Table of Contents
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•
|
conditions in the oil and gas industry, including supply/demand levels for crude oil and condensate, NGLs, natural gas and synthetic crude oil and the resulting impact on price;
|
•
|
changes in expected reserve or production levels;
|
•
|
changes in political or economic conditions in the jurisdictions in which we operate, including changes in foreign currency exchange rates, interest rates, inflation rates, and global and domestic market conditions;
|
•
|
risks relating to our hedging activities;
|
•
|
capital available for exploration and development;
|
•
|
drilling and operating risks;
|
•
|
well production timing;
|
•
|
availability of drilling rigs, materials and labor, including the costs associated therewith;
|
•
|
difficulty in obtaining necessary approvals and permits;
|
•
|
non-performance by third parties of their contractual obligations;
|
•
|
unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response thereto;
|
•
|
cyber-attacks;
|
•
|
changes in safety, health, environmental, tax and other regulations;
|
•
|
other geological, operating and economic considerations; and
|
•
|
other factors discussed in Item 1. Business, Item 1A. Risk Factors, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A. Quantitative and Qualitative Disclosures About Market Risk, and elsewhere in this report.
|
•
|
North America E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas in North America;
|
•
|
International E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of North America and produces and markets products manufactured from natural gas, such as LNG and methanol, in E.G.; and
|
•
|
Oil Sands Mining – mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and market synthetic crude oil and vacuum gas oil.
|
|
North America
|
|
Africa
|
|
|
|
|
||||||||||||||||
December 31, 2016
|
U.S.
|
|
Canada
|
|
Total
|
|
E.G.
|
|
Other
|
|
Total
|
|
Other Int'l
|
|
Total
|
||||||||
Proved Developed Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Crude oil and condensate
(mmbbl)
|
238
|
|
|
—
|
|
|
238
|
|
|
45
|
|
|
172
|
|
|
217
|
|
|
13
|
|
|
468
|
|
Natural gas liquids
(mmbbl)
|
78
|
|
|
—
|
|
|
78
|
|
|
24
|
|
|
—
|
|
|
24
|
|
|
—
|
|
|
102
|
|
Natural gas
(bcf)
|
648
|
|
|
—
|
|
|
648
|
|
|
943
|
|
|
95
|
|
|
1,038
|
|
|
5
|
|
|
1,691
|
|
Synthetic crude oil
(mmbbl)
|
—
|
|
|
692
|
|
|
692
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
692
|
|
Total proved developed reserves
(mmboe)
|
424
|
|
|
692
|
|
|
1,116
|
|
|
226
|
|
|
188
|
|
|
414
|
|
|
14
|
|
|
1,544
|
|
Proved Undeveloped Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Crude oil and condensate (
mmbbl
)
|
325
|
|
|
—
|
|
|
325
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9
|
|
|
334
|
|
Natural gas liquids (
mmbbl
)
|
92
|
|
|
—
|
|
|
92
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
92
|
|
Natural gas (
bcf
)
|
640
|
|
|
—
|
|
|
640
|
|
|
—
|
|
|
110
|
|
|
110
|
|
|
5
|
|
|
755
|
|
Synthetic crude oil
(mmbbl)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total proved undeveloped reserves (
mmboe
)
|
524
|
|
|
—
|
|
|
524
|
|
|
—
|
|
|
18
|
|
|
18
|
|
|
10
|
|
|
552
|
|
Total Proved Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Crude oil and condensate (
mmbbl
)
|
563
|
|
|
—
|
|
|
563
|
|
|
45
|
|
|
172
|
|
|
217
|
|
|
22
|
|
|
802
|
|
Natural gas liquids (
mmbbl
)
|
170
|
|
|
—
|
|
|
170
|
|
|
24
|
|
|
—
|
|
|
24
|
|
|
—
|
|
|
194
|
|
Natural gas (
bcf
)
|
1,288
|
|
|
—
|
|
|
1,288
|
|
|
943
|
|
|
205
|
|
|
1,148
|
|
|
10
|
|
|
2,446
|
|
Synthetic crude oil (
mmbbl
)
|
—
|
|
|
692
|
|
|
692
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
692
|
|
Total proved reserves (
mmboe
)
|
948
|
|
|
692
|
|
|
1,640
|
|
|
226
|
|
|
206
|
|
|
432
|
|
|
24
|
|
|
2,096
|
|
|
Productive Wells
(a)
|
|
|
|
|
|
|
|
|
||||||||||||||
|
Oil
|
|
Natural Gas
|
|
Service Wells
|
|
Drilling Wells
|
||||||||||||||||
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||||
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
U.S.
(b)
|
4,533
|
|
|
1,650
|
|
|
1,830
|
|
|
708
|
|
|
821
|
|
|
85
|
|
|
42
|
|
|
10
|
|
E.G.
|
—
|
|
|
—
|
|
|
17
|
|
|
11
|
|
|
2
|
|
|
1
|
|
|
—
|
|
|
—
|
|
Other Africa
|
1,071
|
|
|
175
|
|
|
7
|
|
|
1
|
|
|
94
|
|
|
16
|
|
|
—
|
|
|
—
|
|
Total Africa
|
1,071
|
|
|
175
|
|
|
24
|
|
|
12
|
|
|
96
|
|
|
17
|
|
|
—
|
|
|
—
|
|
Other International
|
62
|
|
|
23
|
|
|
35
|
|
|
14
|
|
|
23
|
|
|
8
|
|
|
—
|
|
|
—
|
|
Total
|
5,666
|
|
|
1,848
|
|
|
1,889
|
|
|
734
|
|
|
940
|
|
|
110
|
|
|
42
|
|
|
10
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
U.S.
|
7,198
|
|
|
2,878
|
|
|
1,796
|
|
|
750
|
|
|
2,727
|
|
|
747
|
|
|
|
|
|
||
E.G.
|
—
|
|
|
—
|
|
|
17
|
|
|
11
|
|
|
2
|
|
|
1
|
|
|
|
|
|
||
Other Africa
|
1,071
|
|
|
175
|
|
|
7
|
|
|
1
|
|
|
94
|
|
|
16
|
|
|
|
|
|
||
Total Africa
|
1,071
|
|
|
175
|
|
|
24
|
|
|
12
|
|
|
96
|
|
|
17
|
|
|
|
|
|
||
Other International
|
59
|
|
|
21
|
|
|
39
|
|
|
16
|
|
|
24
|
|
|
8
|
|
|
|
|
|
||
Total
|
8,328
|
|
|
3,074
|
|
|
1,859
|
|
|
778
|
|
|
2,847
|
|
|
772
|
|
|
|
|
|
||
2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
U.S.
|
7,058
|
|
|
2,919
|
|
|
2,246
|
|
|
1,023
|
|
|
2,638
|
|
|
760
|
|
|
|
|
|
||
E.G.
|
—
|
|
|
—
|
|
|
16
|
|
|
11
|
|
|
2
|
|
|
1
|
|
|
|
|
|
||
Other Africa
|
1,071
|
|
|
175
|
|
|
7
|
|
|
1
|
|
|
94
|
|
|
16
|
|
|
|
|
|
||
Total Africa
|
1,071
|
|
|
175
|
|
|
23
|
|
|
12
|
|
|
96
|
|
|
17
|
|
|
|
|
|
||
Other International
|
55
|
|
|
20
|
|
|
39
|
|
|
16
|
|
|
24
|
|
|
8
|
|
|
|
|
|
||
Total
|
8,184
|
|
|
3,114
|
|
|
2,308
|
|
|
1,051
|
|
|
2,758
|
|
|
785
|
|
|
|
|
|
(a)
|
Of the gross productive wells, wells with multiple completions operated by us totaled
8
,
12
and
31
as of
December 31, 2016
,
2015
and
2014
. Information on wells with multiple completions operated by others is unavailable to us.
|
(b)
|
Reduction in December 31, 2016 gross and net productive wells and service wells is primarily due to the dispositions of our West Texas and Wyoming assets in 2016. See Item 8. Financial Statements and Supplementary Data - Note
6
to the consolidated financial statements for information about these dispositions.
|
|
Development
|
|
Exploratory
|
|
|
|||||||||||||||||||||
|
Oil
|
|
Natural
Gas
|
|
Dry
|
|
Total
|
|
Oil
|
|
Natural
Gas
|
|
Dry
|
|
Total
|
|
Total
|
|||||||||
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
U.S.
|
64
|
|
|
12
|
|
|
—
|
|
|
76
|
|
|
70
|
|
|
27
|
|
|
—
|
|
|
97
|
|
|
173
|
|
E.G.
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Other Africa
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total Africa
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Other International
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
64
|
|
|
12
|
|
|
—
|
|
|
76
|
|
|
70
|
|
|
27
|
|
|
—
|
|
|
97
|
|
|
173
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
U.S.
|
135
|
|
|
36
|
|
|
11
|
|
|
182
|
|
|
49
|
|
|
48
|
|
|
1
|
|
|
98
|
|
|
280
|
|
E.G.
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
1
|
|
|
2
|
|
Other Africa
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total Africa
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
1
|
|
|
2
|
|
Other International
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
Total
|
136
|
|
|
37
|
|
|
11
|
|
|
184
|
|
|
49
|
|
|
48
|
|
|
2
|
|
|
99
|
|
|
283
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
U.S.
|
253
|
|
|
43
|
|
|
1
|
|
|
297
|
|
|
49
|
|
|
19
|
|
|
4
|
|
|
72
|
|
|
369
|
|
E.G.
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
1
|
|
|
1
|
|
Other Africa
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
Total Africa
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
1
|
|
|
2
|
|
Other International
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
Total
|
255
|
|
|
43
|
|
|
1
|
|
|
299
|
|
|
49
|
|
|
19
|
|
|
5
|
|
|
73
|
|
|
372
|
|
|
Developed
|
|
Undeveloped
|
|
Developed and
Undeveloped
|
||||||||||||
(In thousands)
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
U.S.
|
1,399
|
|
|
1,053
|
|
|
413
|
|
|
386
|
|
|
1,812
|
|
|
1,439
|
|
Canada
|
—
|
|
|
—
|
|
|
142
|
|
|
54
|
|
|
142
|
|
|
54
|
|
Total North America
|
1,399
|
|
|
1,053
|
|
|
555
|
|
|
440
|
|
|
1,954
|
|
|
1,493
|
|
E.G.
|
45
|
|
|
29
|
|
|
92
|
|
|
73
|
|
|
137
|
|
|
102
|
|
Other Africa
|
12,909
|
|
|
2,108
|
|
|
2,519
|
|
|
753
|
|
|
15,428
|
|
|
2,861
|
|
Total Africa
|
12,954
|
|
|
2,137
|
|
|
2,611
|
|
|
826
|
|
|
15,565
|
|
|
2,963
|
|
Other International
|
86
|
|
|
31
|
|
|
171
|
|
|
32
|
|
|
257
|
|
|
63
|
|
Total
|
14,439
|
|
|
3,221
|
|
|
3,337
|
|
|
1,298
|
|
|
17,776
|
|
|
4,519
|
|
|
North America
|
|
Africa
|
|
|
|
|
|
|
|||||||||||||||||
|
U.S.
|
|
Canada
|
|
Total
|
|
E.G.
|
|
Other
|
|
Total
|
|
Other Int'l
|
|
Disc Ops
|
|
Total |
|||||||||
Year Ended December 31,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Crude and condensate
(mbbld)
(a)
|
131
|
|
|
—
|
|
|
131
|
|
|
20
|
|
|
3
|
|
|
23
|
|
|
12
|
|
|
—
|
|
|
166
|
|
Natural gas liquids
(mbbld)
|
40
|
|
|
—
|
|
|
40
|
|
|
11
|
|
|
—
|
|
|
11
|
|
|
—
|
|
|
—
|
|
|
51
|
|
Natural gas
(mmcfd)
(b)
|
314
|
|
|
—
|
|
|
314
|
|
|
425
|
|
|
—
|
|
|
425
|
|
|
28
|
|
|
—
|
|
|
767
|
|
Synthetic crude oil
(mbbld)
(c)
|
—
|
|
|
48
|
|
|
48
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
48
|
|
Total production
(mboed)
|
223
|
|
|
48
|
|
|
271
|
|
|
102
|
|
|
3
|
|
|
105
|
|
|
17
|
|
|
—
|
|
|
393
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Crude and condensate
(mbbld)
(a)
|
171
|
|
|
—
|
|
|
171
|
|
|
19
|
|
|
—
|
|
|
19
|
|
|
14
|
|
|
—
|
|
|
204
|
|
Natural gas liquids
(mbbld)
|
39
|
|
|
—
|
|
|
39
|
|
|
10
|
|
|
—
|
|
|
10
|
|
|
—
|
|
|
—
|
|
|
49
|
|
Natural gas
(mmcfd)
(b)
|
351
|
|
|
—
|
|
|
351
|
|
|
410
|
|
|
—
|
|
|
410
|
|
|
21
|
|
|
—
|
|
|
782
|
|
Synthetic crude oil
(mbbld)
(c)
|
—
|
|
|
45
|
|
|
45
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
45
|
|
Total production
(mboed)
|
269
|
|
|
45
|
|
|
314
|
|
|
97
|
|
|
—
|
|
|
97
|
|
|
18
|
|
|
—
|
|
|
429
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Crude and condensate
(mbbld)
(a)
|
157
|
|
|
—
|
|
|
157
|
|
|
21
|
|
|
7
|
|
|
28
|
|
|
11
|
|
|
48
|
|
|
244
|
|
Natural gas liquids
(mbbld)
|
29
|
|
|
—
|
|
|
29
|
|
|
10
|
|
|
—
|
|
|
10
|
|
|
—
|
|
|
—
|
|
|
39
|
|
Natural gas
(mmcfd)
(b)
|
310
|
|
|
—
|
|
|
310
|
|
|
439
|
|
|
1
|
|
|
440
|
|
|
21
|
|
|
37
|
|
|
808
|
|
Synthetic crude oil
(mbbld)
(c)
|
—
|
|
|
41
|
|
|
41
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
41
|
|
Total production
(mboed)
|
238
|
|
|
41
|
|
|
279
|
|
|
104
|
|
|
7
|
|
|
111
|
|
|
15
|
|
|
54
|
|
|
459
|
|
(a)
|
The amounts correspond with the basis for fiscal settlements with governments, representing equity tanker liftings and direct deliveries of liquid hydrocarbons.
|
(b)
|
Excludes volumes acquired from third parties for injection and subsequent resale.
|
(c)
|
Upgraded bitumen excluding blendstocks.
|
|
North America
|
|
Africa
|
|
|
|
|
|
|
||||||||||||||||||||||||
(Dollars per boe)
|
U.S.
|
|
Canada
|
|
Total
|
|
E.G.
|
|
Other
|
|
Total
|
|
Other Int'l
|
|
Disc Ops
|
|
Total
|
||||||||||||||||
2016
|
$
|
9.84
|
|
|
$
|
29.36
|
|
|
$
|
13.35
|
|
|
$
|
2.17
|
|
|
N.M.
|
|
$
|
2.17
|
|
|
$
|
23.13
|
|
|
$
|
—
|
|
|
$
|
11.02
|
|
2015
|
10.65
|
|
|
38.42
|
|
|
14.69
|
|
|
2.37
|
|
|
N.M.
|
|
2.37
|
|
|
27.23
|
|
|
—
|
|
|
12.62
|
|
||||||||
2014
|
13.34
|
|
|
46.63
|
|
|
18.73
|
|
|
4.03
|
|
|
N.M.
|
|
4.03
|
|
|
47.06
|
|
|
8.92
|
|
|
15.37
|
|
(a)
|
Production, severance and property taxes are excluded; however, shipping and handling as well as other operating expenses are included in the production costs used in this calculation. See Item 8. Financial Statements and Supplementary Data – Supplementary Information on Oil and Gas Producing Activities - Results of Operations for Oil and Gas Production Activities for more information regarding production costs.
|
|
North America
|
|
Africa
|
|
|
|
|
|
|
||||||||||||||||||||||||||
(Dollars per unit)
|
U.S.
|
|
Canada
|
|
Total
|
|
E.G.
|
|
Other
|
|
Total
|
|
Other Int'l
|
|
Disc Ops
|
|
Total |
||||||||||||||||||
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||||
Crude and condensate
(bbl)
|
$
|
38.57
|
|
|
$
|
—
|
|
|
$
|
38.57
|
|
|
$
|
38.85
|
|
|
$
|
57.69
|
|
|
$
|
40.95
|
|
|
$
|
43.21
|
|
|
$
|
—
|
|
|
$
|
39.23
|
|
Natural gas liquids
(bbl)
|
13.15
|
|
|
—
|
|
|
13.15
|
|
|
1.00
|
|
(b)
|
—
|
|
|
1.00
|
|
|
26.41
|
|
|
—
|
|
|
10.68
|
|
|||||||||
Natural gas
(mcf)
|
2.38
|
|
|
—
|
|
|
2.38
|
|
|
0.24
|
|
(b)
|
—
|
|
|
0.24
|
|
|
4.80
|
|
|
—
|
|
|
1.26
|
|
|||||||||
Synthetic crude oil
(bbl)
|
—
|
|
|
37.57
|
|
|
37.57
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
37.57
|
|
|||||||||
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||||
Crude and condensate
(bbl)
|
$
|
43.50
|
|
|
$
|
—
|
|
|
$
|
43.50
|
|
|
$
|
42.83
|
|
|
$
|
—
|
|
|
$
|
42.83
|
|
|
$
|
53.91
|
|
|
$
|
—
|
|
|
$
|
44.14
|
|
Natural gas liquids
(bbl)
|
13.37
|
|
|
—
|
|
|
13.37
|
|
|
1.00
|
|
(b)
|
—
|
|
|
1.00
|
|
|
32.53
|
|
|
—
|
|
|
11.16
|
|
|||||||||
Natural gas
(mcf)
|
2.66
|
|
|
—
|
|
|
2.66
|
|
|
0.24
|
|
(b)
|
—
|
|
|
0.24
|
|
|
6.85
|
|
|
—
|
|
|
1.50
|
|
|||||||||
Synthetic crude oil
(bbl)
|
—
|
|
|
40.13
|
|
|
40.13
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
40.13
|
|
|||||||||
2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||||
Crude and condensate
(bbl)
|
$
|
85.25
|
|
|
$
|
—
|
|
|
$
|
85.25
|
|
|
$
|
81.01
|
|
|
$
|
94.70
|
|
|
$
|
84.48
|
|
|
$
|
94.31
|
|
|
$
|
109.80
|
|
|
$
|
90.37
|
|
Natural gas liquids
(bbl)
|
33.42
|
|
|
—
|
|
|
33.42
|
|
|
1.00
|
|
(b)
|
—
|
|
|
1.00
|
|
|
67.73
|
|
|
—
|
|
|
25.25
|
|
|||||||||
Natural gas
(mcf)
|
4.57
|
|
|
—
|
|
|
4.57
|
|
|
0.24
|
|
(b)
|
3.11
|
|
|
0.25
|
|
|
8.27
|
|
|
9.94
|
|
|
2.55
|
|
|||||||||
Synthetic crude oil
(bbl)
|
—
|
|
|
83.35
|
|
|
83.35
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
83.35
|
|
(a)
|
Excludes gains or losses on commodity derivative instruments.
|
(b)
|
Primarily represents fixed prices under long-term contracts with Alba Plant LLC, AMPCO and/or EGHoldings, which are equity method investees. We include our share of income from each of these equity method investees in our International E&P Segment.
|
|
|
2017
|
|
2018
|
|
2019
|
|
Thereafter
|
|
Commitment Period Through
|
|||
Eagle Ford
|
|
|
|
|
|
|
|
|
|
|
|||
Crude and condensate
(mbbld)
|
|
105
|
|
|
80
|
|
|
66
|
|
|
51
|
|
2020
|
Natural gas
(mmcfd)
|
|
210
|
|
|
168
|
|
|
168
|
|
|
46 - 168
|
|
2022
|
Bakken
|
|
|
|
|
|
|
|
|
|
|
|||
Crude and condensate
(mbbld)
|
|
5
|
|
|
10
|
|
|
10
|
|
|
5-10
|
|
2027
|
OSM
|
|
|
|
|
|
|
|
|
|
|
|||
Synthetic crude oil
(mbbld)
|
|
10
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Lee M. Tillman
|
|
55
|
|
President and Chief Executive Officer
|
Sylvia J. Kerrigan
|
|
51
|
|
Executive Vice President, General Counsel and Secretary
|
T. Mitch Little
|
|
53
|
|
Executive Vice President—Operations
|
Patrick J. Wagner
|
|
52
|
|
Interim Chief Financial Officer and Vice President-Corporate Development and Strategy
|
Catherine L. Krajicek
|
|
55
|
|
Vice President—Conventional
|
Gary E. Wilson
|
|
55
|
|
Vice President, Controller and Chief Accounting Officer
|
•
|
our Code of Business Conduct and Code of Ethics for Senior Financial Officers;
|
•
|
our Corporate Governance Principles; and
|
•
|
the charters of our Audit and Finance Committee, Compensation Committee, Corporate Governance and Nominating Committee and Health, Environmental, Safety and Corporate Responsibility Committee.
|
•
|
worldwide and domestic supplies of and demand for crude oil and condensate, NGLs, natural gas and synthetic crude oil;
|
•
|
the cost of exploring for, developing and producing crude oil and condensate, NGLs, natural gas and synthetic crude oil;
|
•
|
the ability of the members of OPEC and certain non-OPEC members, such as Russia, to agree to and maintain production controls;
|
•
|
the production levels of non-OPEC countries, including production levels in the shale plays in the United States;
|
•
|
the level of drilling, completion and production activities by other exploration and production companies, and variability therein, in response to market conditions;
|
•
|
political instability or armed conflict in oil and natural gas producing regions;
|
•
|
changes in weather patterns and climate;
|
•
|
natural disasters such as hurricanes and tornadoes;
|
•
|
the price and availability of alternative and competing forms of energy;
|
•
|
the effect of conservation efforts;
|
•
|
epidemics or pandemics;
|
•
|
technological advances affecting energy consumption and energy supply;
|
•
|
domestic and foreign governmental regulations and taxes; and
|
•
|
general economic conditions worldwide.
|
•
|
reducing the amount of crude oil and condensate, NGLs, natural gas and synthetic crude oil that we can produce economically;
|
•
|
reducing our revenues, operating income and cash flows;
|
•
|
causing us to reduce our capital expenditures, and delay or postpone some of our capital projects;
|
•
|
requiring us to impair the carrying value of our assets;
|
•
|
reducing the standardized measure of discounted future net cash flows relating to crude oil and condensate, NGLs, natural gas and synthetic crude oil; and
|
•
|
increasing the costs of obtaining capital, such as equity and short- and long-term debt.
|
|
SEC Pricing 2016
|
||
WTI Crude oil
(per bbl)
|
$
|
42.75
|
|
Henry Hub natural gas
(per mmbtu)
|
$
|
2.49
|
|
Brent crude oil
(per bbl)
|
$
|
43.53
|
|
Mont Belvieu NGLs
(per bbl)
|
$
|
15.89
|
|
•
|
location, size and shape of the accumulation as well as fluid, rock and producing characteristics of the accumulation;
|
•
|
historical production from the area, compared with production from other analogous producing areas;
|
•
|
volumes of bitumen in-place and various factors affecting the recoverability of bitumen and its conversion into synthetic crude oil such as historical upgrader performance;
|
•
|
the assumed impacts of regulation by governmental agencies;
|
•
|
assumptions concerning future operating costs, taxes, development costs and workover and repair costs; and
|
•
|
industry economic conditions, levels of cash flows from operations and other operating considerations.
|
•
|
the amount and timing of production;
|
•
|
the revenues and costs associated with that production; and
|
•
|
the amount and timing of future development expenditures.
|
•
|
obtaining rights to explore for, develop and produce crude oil and condensate, NGLs, natural gas and synthetic crude oil in promising areas;
|
•
|
drilling success;
|
•
|
the ability to complete long lead-time, capital-intensive projects timely and cost effectively;
|
•
|
the ability to find or acquire additional proved reserves at acceptable costs; and
|
•
|
the ability to fund such activity.
|
•
|
unexpected drilling conditions;
|
•
|
title problems;
|
•
|
pressure or irregularities in formations;
|
•
|
equipment failures or accidents;
|
•
|
inflation in exploration and drilling costs;
|
•
|
fires, explosions, blowouts or surface cratering;
|
•
|
lack of access to pipelines or other transportation methods; and
|
•
|
shortages or delays in the availability of services or delivery of equipment.
|
•
|
denial of or delay in receiving requisite regulatory approvals and/or permits;
|
•
|
unplanned increases in the cost of construction materials or labor;
|
•
|
disruptions in transportation of components or construction materials;
|
•
|
increased costs or operational delays resulting from shortages of water;
|
•
|
adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of vendors or suppliers;
|
•
|
shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;
|
•
|
market-related increases in a project’s debt or equity financing costs; and
|
•
|
nonperformance by, or disputes with, vendors, suppliers, contractors or subcontractors.
|
•
|
changes in governmental policies relating to crude oil and condensate, NGLs, natural gas or synthetic crude oil and taxation;
|
•
|
other political, economic or diplomatic developments and international monetary fluctuations;
|
•
|
political and economic instability, war, acts of terrorism, armed conflict and civil disturbances;
|
•
|
the possibility that a government may seize our property with or without compensation, may attempt to renegotiate or revoke existing contractual arrangements or may impose additional taxes or royalty burdens; and
|
•
|
fluctuating currency values, hard currency shortages and currency controls.
|
•
|
volatility in global crude oil prices which could negatively impact the global economy, resulting in slower economic growth rates and reduced demand for our products;
|
•
|
negative impact on the world crude oil supply if transportation avenues are disrupted;
|
•
|
security concerns leading to the prolonged evacuation of our personnel;
|
•
|
damage to, or the inability to access, production facilities or other operating assets; and
|
•
|
inability of our service and equipment providers to deliver items necessary for us to conduct our operations.
|
•
|
we may be more vulnerable to general adverse economic and industry conditions;
|
•
|
a portion of our cash flows from operating activities must be used to service our indebtedness and is not available for other purposes;
|
•
|
our flexibility in planning for, or reacting to, changes in our industry may be limited;
|
•
|
a financial covenant in our Credit Agreement stipulates that our total debt to capitalization ratio will not exceed 65% as of the last day of any fiscal quarter, and if exceeded, may make additional borrowings more expensive and affect our ability to plan for and react to changes in the economy and our industry;
|
•
|
we may be at a competitive disadvantage as compared to similar companies that have less debt; and
|
•
|
additional financing in the future for working capital, capital expenditures, acquisitions or development activities, general corporate or other purposes may have higher costs and more restrictive covenants.
|
Period
|
Total Number of
Shares
Purchased
(a)
|
|
Average
Price Paid
per Share
|
|
Total Number of
Shares Purchased
as Part of Publicly
Announced Plans
or Programs
(b)
|
|
Approximate
Dollar Value of
Shares that May
Yet Be Purchased
Under the Plans
or Programs
(b)
|
|||||
10/01/16 – 10/31/16
|
51,396
|
|
|
$15.96
|
|
—
|
|
|
$
|
1,500,285,529
|
|
|
11/01/16 – 11/30/16
|
919
|
|
|
$13.20
|
|
—
|
|
|
$
|
1,500,285,529
|
|
|
12/01/16 – 12/31/16
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
1,500,285,529
|
|
Total
|
52,315
|
|
|
$15.91
|
|
—
|
|
|
|
(a)
|
52,315
shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.
|
(b)
|
In January 2006, we announced a $2.0 billion share repurchase program. Our Board of directors subsequently increased the authorization for repurchases under the program by $500 million in January 2007, by $500 million in May 2007, by $2.0 billion in July 2007, and by $1.2 billion in December 2013, for a total authorized amount of $6.2 billion. The remaining share repurchase authorization as of
December 31, 2016
is $1.5 billion. No repurchases were made under the program in 2016.
|
|
Year Ended December 31,
|
||||||||||||||||||
(In millions, except per share data)
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
Statement of Income Data
(a)(b)(c)
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues
|
$
|
4,031
|
|
|
$
|
5,522
|
|
|
$
|
10,846
|
|
|
$
|
11,325
|
|
|
$
|
11,966
|
|
Income (loss) from continuing operations
|
(2,140
|
)
|
|
(2,204
|
)
|
|
969
|
|
|
931
|
|
|
856
|
|
|||||
Net income (loss)
|
(2,140
|
)
|
|
(2,204
|
)
|
|
3,046
|
|
|
1,753
|
|
|
1,582
|
|
|||||
Per Share Data
(a)(b)(c)
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic:
|
|
|
|
|
|
|
|
|
|
||||||||||
Income (loss) from continuing operations
|
$
|
(2.61
|
)
|
|
$
|
(3.26
|
)
|
|
$
|
1.42
|
|
|
$
|
1.32
|
|
|
$
|
1.21
|
|
Net income (loss)
|
$
|
(2.61
|
)
|
|
$
|
(3.26
|
)
|
|
$
|
4.48
|
|
|
$
|
2.49
|
|
|
$
|
2.24
|
|
Diluted:
|
|
|
|
|
|
|
|
|
|
||||||||||
Income (loss) from continuing operations
|
$
|
(2.61
|
)
|
|
$
|
(3.26
|
)
|
|
$
|
1.42
|
|
|
$
|
1.31
|
|
|
$
|
1.21
|
|
Net income (loss)
|
$
|
(2.61
|
)
|
|
$
|
(3.26
|
)
|
|
$
|
4.46
|
|
|
$
|
2.47
|
|
|
$
|
2.23
|
|
Statement of Cash Flows Data
(b)
|
|
|
|
|
|
|
|
|
|
||||||||||
Additions to property, plant and equipment related to continuing operations
|
$
|
1,245
|
|
|
$
|
3,476
|
|
|
$
|
5,160
|
|
|
$
|
4,443
|
|
|
$
|
4,361
|
|
Dividends paid
|
162
|
|
|
460
|
|
|
543
|
|
|
508
|
|
|
480
|
|
|||||
Dividends per share
|
$0.20
|
|
$0.68
|
|
$0.80
|
|
$0.72
|
|
$0.68
|
||||||||||
Balance Sheet Data at December 31
|
|
|
|
|
|
|
|
|
|
||||||||||
Total assets
|
$
|
31,094
|
|
|
$
|
32,311
|
|
|
$
|
35,983
|
|
|
$
|
35,588
|
|
|
$
|
35,269
|
|
Total long-term debt, including capitalized leases
|
6,589
|
|
|
7,276
|
|
|
5,295
|
|
|
6,362
|
|
|
6,475
|
|
(a)
|
Includes impairments to producing properties of
$67 million
,
$412 million
,
$132 million
,
$96 million
and
$371 million
in
2016
,
2015
,
2014
,
2013
and
2012
and impairments to unproved properties of $
195 million
,
$964 million
,
$306 million
,
$572 million
and
$227 million
in
2016
,
2015
,
2014
,
2013
and
2012
(see Item 8. Financial Statements and Supplementary Data – Note
13
to the consolidated financial statements). Includes a goodwill impairment of
$340 million
in 2015 related to the N.A. E&P reporting unit. (see Item 8. Financial Statements and Supplementary Data – Note
14
to the consolidated financial statements).
|
(b)
|
We closed the sale of our Angola assets and our Norway business in 2014 (see Item 8. Financial Statements and Supplementary Data – Note
6
to the consolidated financial statements). The applicable periods have been recast to reflect as discontinued operations.
|
(c)
|
December 31, 2016 includes the increase of a valuation allowance on certain of our deferred tax assets for
$1,346 million
(see Item 8. Financial Statements and Supplementary Data – Note 9 to the consolidated financial statements).
|
•
|
North America E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas in North America;
|
•
|
International E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of North America and produces and markets products manufactured from natural gas, such as LNG and methanol, in E.G.; and
|
•
|
Oil Sands Mining – mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and market synthetic crude oil and vacuum gas oil.
|
•
|
Reduced 2016 Capital Program spend to $1.1 billion, below $1.4 billion original budget
|
•
|
Reduced production expenses per boe in
2016
|
•
|
Reduced average completed well costs in 2016 by 22% in the Oklahoma Resource Basins and 26% in Eagle Ford compared to 2015
|
•
|
Decreased total general and administrative costs by 18% in 2016 compared to last year
|
•
|
Closed on the Oklahoma STACK acquisition of 61,000 net acres
|
•
|
Concentrated asset base to lower cost, higher margin resource plays by closing on
$1.3 billion
in non-core asset sales
|
•
|
Increased our liquidity to
$5.8 billion
at December 31, 2016 compared to $4.2 billion at December 31, 2015
|
•
|
Improved our cash-adjusted debt-to-capital ratio to
21%
at December 31, 2016 compared to 25% at December 31, 2015
|
•
|
Increased U.S. resource play rig count by 50 percent in fourth quarter of 2016, while remaining under budget, and positioning to resume sequential production growth in the resource plays in the first half of 2017
|
•
|
Total company net sales volumes of 404 mboed in 2016
|
•
|
We ended 2016 with 2,096 mmboe of proved reserves, with extension, discovery and other additions of 304 mmboe
|
•
|
Increased net sales volumes by
40%
in the Oklahoma Resource Basins as we increased activity on our STACK and SCOOP acreage
|
•
|
Delivered basin-leading well results in the Bakken supported by enhanced completions and advantaged geology, while reducing production expense by approximately 30% year-over-year
|
•
|
Achieved record drilling efficiency in the Eagle Ford and record low completed costs during 2016 while continuing to execute high intensity completions
|
•
|
Completed the Alba B3 Compression project in E.G., extending plateau production and field life
|
•
|
Resumed liftings in Libya in December 2016; Force Majeure lifted in September 2016
|
•
|
Ended the year with 12 rigs operating in the U.S. resource plays
|
•
|
2016 net loss of $2.1 billion versus 2015 net loss of $2.2 billion; included in the loss for 2016:
|
◦
|
Non-cash charge related to a valuation allowance on our deferred tax assets of
$1.3 billion
(see Item 8. Financial Statements and Supplementary Data – Note 9 to the consolidated financial statements)
|
◦
|
Reduction in segment sales revenues of $1.2 billion with a nearly even split between lower price realizations and decreased sales volumes
|
◦
|
Non-cash charge of $262 million for proved and unproved property impairments (See Item 8. Financial Statements and Supplementary Data - Note
13
to the consolidated financial statement for additional detail)
|
•
|
Net cash provided by operating activities in 2016 was
$1.1 billion
, compared to
$1.6 billion
in
2015
, reflecting the lower segment revenues
|
(In millions)
|
Capital Program
|
||
North America E&P
|
$
|
2,107
|
|
International E&P
|
64
|
|
|
Oil Sands Mining
|
29
|
|
|
Segment total
|
2,200
|
|
|
Corporate and other
|
25
|
|
|
Total Capital Program
|
$
|
2,225
|
|
Net Sales Volumes
|
2016
|
|
Increase
(Decrease) |
|
2015
|
|
Increase
(Decrease) |
|
2014
|
||
North America E&P
(mboed)
|
223
|
|
(17
|
)%
|
|
269
|
|
13
|
%
|
|
238
|
International E&P
(mboed)
|
122
|
|
5
|
%
|
|
116
|
|
(9
|
)%
|
|
127
|
Oil Sands Mining
(mbbld)
(a)
|
59
|
|
11
|
%
|
|
53
|
|
6
|
%
|
|
50
|
Total Continuing Operations
(mboed)
|
404
|
|
(8
|
)%
|
|
438
|
|
6
|
%
|
|
415
|
(a)
|
Year ended December 31, 2016 decreases relating to assets sold were
23
mboed, primarily consisting of Wyoming, West Texas, East Texas, North Louisiana and certain Gulf of Mexico assets.
|
Sales Mix - U.S. Resource Plays - 2016
|
|
Oklahoma Resource Basins
|
|
Eagle Ford
|
|
Bakken
|
|
Total
|
Crude oil and condensate
|
|
25%
|
|
57%
|
|
81%
|
|
58%
|
Natural gas liquids
|
|
26%
|
|
21%
|
|
11%
|
|
19%
|
Natural gas
|
|
49%
|
|
22%
|
|
8%
|
|
23%
|
Net Sales Volumes
|
2016
|
|
Increase
(Decrease) |
|
2015
|
|
Increase
(Decrease) |
|
2014
|
Equivalent Barrels
(mboed)
|
|
|
|
|
|
|
|
|
|
Equatorial Guinea
|
102
|
|
5%
|
|
97
|
|
(7)%
|
|
104
|
United Kingdom
(a)
|
17
|
|
(11)%
|
|
19
|
|
19%
|
|
16
|
Libya
|
3
|
|
100%
|
|
—
|
|
(100)%
|
|
7
|
Total International E&P
(mboed)
|
122
|
|
5%
|
|
116
|
|
(9)%
|
|
127
|
Net Sales Volumes of Equity Method Investees
|
|
|
|
|
|
|
|
|
|
LNG
(mtd)
|
5,874
|
|
—%
|
|
5,884
|
|
(10)%
|
|
6,535
|
Methanol
(mtd)
|
1,358
|
|
45%
|
|
937
|
|
(14)%
|
|
1,092
|
Condensate & LPG
(boed)
|
13,430
|
|
10%
|
|
12,208
|
|
(40)%
|
|
20,506
|
|
|
2016
|
|
Increase (Decrease)
|
|
2015
|
Decrease
|
|
2014
|
|||||||
Average Price Realizations
(a)
|
|
|
|
|
|
|
|
|
|
|||||||
Crude Oil and Condensate
(per bbl)
(b)
|
|
|
$38.57
|
|
|
(11
|
)%
|
|
|
$43.50
|
|
(49
|
)%
|
|
85.25
|
|
Natural Gas Liquids
(per bbl)
|
|
13.15
|
|
|
(2
|
)%
|
|
13.37
|
|
(60
|
)%
|
|
33.42
|
|
||
Total Liquid Hydrocarbons
(per bbl)
|
|
32.71
|
|
|
(14
|
)%
|
|
37.85
|
|
(51
|
)%
|
|
77.02
|
|
||
Natural Gas
(per mcf)
(c)
|
|
2.38
|
|
|
(11
|
)%
|
|
2.66
|
|
(42
|
)%
|
|
4.57
|
|
||
Benchmarks
|
|
|
|
|
|
|
|
|
|
|
|
|||||
WTI crude oil average of daily prices
(per bbl)
|
|
|
$43.47
|
|
|
(11
|
)%
|
|
|
$48.76
|
|
(48
|
)%
|
|
92.91
|
|
LLS crude oil average of daily prices
(per bbl)
|
|
45.02
|
|
|
(14
|
)%
|
|
52.33
|
|
(46
|
)%
|
|
96.64
|
|
||
Mont Belvieu NGLs
(per bbl)
(d)
|
|
17.40
|
|
|
3
|
%
|
|
16.94
|
|
(48
|
)%
|
|
32.52
|
|
||
Henry Hub natural gas settlement date average (per
mmbtu)
|
|
2.46
|
|
|
(8
|
)%
|
|
2.66
|
|
(40
|
)%
|
|
4.42
|
|
(a)
|
Excludes gains or losses on commodity derivative instruments.
|
(b)
|
Inclusion of realized gains on crude oil derivative instruments would have increased average liquid hydrocarbon price realizations per barrel by
$0.92
and
$1.24
for
2016
and
2015
. There were no crude oil derivative instruments for
2014
.
|
(c)
|
Inclusion of realized gains (losses) on natural gas derivative instruments would have a de minimus impact on average price realizations for the periods presented.
|
(d)
|
Bloomberg Finance LLP: Y-grade Mix NGL of 50% ethane, 25% propane, 10% butane, 5% isobutane and 10% natural gasoline.
|
|
|
2016
|
|
Decrease
|
|
2015
|
|
Increase (Decrease)
|
|
2014
|
||||||||
Average Price Realizations
|
|
|
|
|
|
|
|
|
|
|
||||||||
Crude Oil and Condensate
(per bbl)
|
|
|
$41.70
|
|
|
(12
|
)%
|
|
|
$47.50
|
|
|
(46
|
)%
|
|
|
$87.23
|
|
Natural Gas Liquids
(per bbl)
|
|
2.11
|
|
|
(25
|
)%
|
|
2.81
|
|
|
14
|
%
|
|
2.46
|
|
|||
Total Liquid Hydrocarbons
(per bbl)
|
|
32.10
|
|
|
(12
|
)%
|
|
36.67
|
|
|
(47
|
)%
|
|
68.98
|
|
|||
Natural Gas
(per mcf)
|
|
0.52
|
|
|
(24
|
)%
|
|
0.68
|
|
|
(6
|
)%
|
|
0.72
|
|
|||
Benchmark
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Brent (Europe) crude oil
(per bbl)
(a)
|
|
|
$43.55
|
|
|
(17
|
)%
|
|
|
$52.35
|
|
|
(47
|
)%
|
|
|
$99.02
|
|
(a)
|
Average of monthly prices obtained from EIA website.
|
|
|
2016
|
|
Decrease
|
|
2015
|
|
Decrease |
|
2014
|
||||||||
Average Price Realizations
|
|
|
|
|
|
|
|
|
|
|
||||||||
Synthetic Crude Oil
(per bbl)
|
|
|
$37.57
|
|
|
(6
|
%)
|
|
|
$40.13
|
|
|
(52
|
%)
|
|
|
$83.35
|
|
Benchmark
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
WTI crude oil average of daily prices
(per bbl)
|
|
|
$43.47
|
|
|
(11
|
%)
|
|
|
$48.76
|
|
|
(48
|
%)
|
|
|
$92.91
|
|
WCS crude oil
(per bbl)
(a)
|
|
29.48
|
|
|
(16
|
%)
|
|
35.28
|
|
|
(52
|
%)
|
|
73.60
|
|
(a)
|
Average of monthly prices based upon average WTI adjusted for differentials unique to western Canada.
|
|
Year Ended December 31,
|
|||||
(In millions)
|
2016
|
2015
|
||||
Sales and other operating revenues, including related party
|
|
|
||||
North America E&P
|
$
|
2,375
|
|
$
|
3,358
|
|
International E&P
|
665
|
|
728
|
|
||
Oil Sands Mining
|
823
|
|
815
|
|
||
Segment sales and other operating revenues, including related party
|
3,863
|
|
4,901
|
|
||
Unrealized gain (loss) on commodity derivative instruments
|
(110
|
)
|
50
|
|
||
Sales and other operating revenues, including related party
|
$
|
3,753
|
|
$
|
4,951
|
|
($ per boe)
|
2016
|
2015
|
||||
North America E&P
|
|
$5.96
|
|
|
$7.38
|
|
International E&P
|
|
$5.05
|
|
|
$5.99
|
|
Oil Sands Mining
(a)
|
|
$27.89
|
|
|
$36.48
|
|
|
Year Ended December 31,
|
|||||
(In millions)
|
2016
|
2015
|
||||
Unproved property impairments
|
$
|
195
|
|
$
|
964
|
|
Dry well costs
|
32
|
|
250
|
|
||
Geological and geophysical
|
5
|
|
31
|
|
||
Other
|
98
|
|
73
|
|
||
Total exploration expenses
|
$
|
330
|
|
$
|
1,318
|
|
($ per boe)
|
2016
|
2015
|
||||
North America E&P
|
|
$22.49
|
|
|
$24.24
|
|
International E&P
|
|
$6.21
|
|
|
$6.95
|
|
Oil Sands Mining
|
|
$11.32
|
|
|
$12.48
|
|
|
Year Ended December 31,
|
|||||
(In millions)
|
2016
|
2015
|
||||
Production and severance
|
$
|
91
|
|
$
|
131
|
|
Ad valorem
|
23
|
|
39
|
|
||
Other
|
54
|
|
64
|
|
||
Total
|
$
|
168
|
|
$
|
234
|
|
|
Year Ended December 31,
|
||||||
(In millions)
|
2016
|
|
2015
|
||||
North America E&P
|
$
|
(415
|
)
|
|
$
|
(486
|
)
|
International E&P
|
228
|
|
|
112
|
|
||
Oil Sands Mining
|
(55
|
)
|
|
(113
|
)
|
||
Segment income (loss)
|
(242
|
)
|
|
(487
|
)
|
||
Items not allocated to segments, net of income taxes
|
(1,898
|
)
|
|
(1,717
|
)
|
||
Net income (loss)
|
$
|
(2,140
|
)
|
|
$
|
(2,204
|
)
|
|
Year Ended December 31,
|
|||||
(In millions)
|
2015
|
2014
|
||||
Sales and other operating revenues, including related party
|
|
|
||||
North America E&P
|
$
|
3,358
|
|
$
|
5,770
|
|
International E&P
|
728
|
|
1,410
|
|
||
Oil Sands Mining
|
815
|
|
1,556
|
|
||
Segment sales and other operating revenues, including related party
|
4,901
|
|
8,736
|
|
||
Unrealized gain on crude oil derivative instruments
|
50
|
|
—
|
|
||
Sales and other operating revenues, including related party
|
$
|
4,951
|
|
$
|
8,736
|
|
($ per boe)
|
2015
|
2014
|
||||
North America E&P
|
|
$7.38
|
|
|
$10.25
|
|
International E&P
|
|
$5.99
|
|
|
$8.31
|
|
Oil Sands Mining
(a)
|
|
$36.48
|
|
|
$44.53
|
|
(a)
|
Production expense per synthetic crude oil barrel (before royalties) includes production costs, shipping and handling, taxes other than income and insurance costs and excludes pre-development costs.
|
|
Year Ended December 31,
|
|||||
(In millions)
|
2015
|
2014
|
||||
Unproved property impairments
|
$
|
964
|
|
$
|
306
|
|
Dry well costs
|
250
|
|
317
|
|
||
Geological and geophysical
|
31
|
|
85
|
|
||
Other
|
73
|
|
85
|
|
||
Total exploration expenses
|
$
|
1,318
|
|
$
|
793
|
|
($ per boe)
|
2015
|
2014
|
||||
North America E&P
|
|
$24.24
|
|
|
$26.95
|
|
International E&P
|
|
$6.95
|
|
|
$5.79
|
|
Oil Sands Mining
|
|
$12.48
|
|
|
$12.07
|
|
|
Year Ended December 31,
|
|||||
(In millions)
|
2015
|
2014
|
||||
Production and severance
|
$
|
131
|
|
$
|
240
|
|
Ad valorem
|
39
|
|
74
|
|
||
Other
|
64
|
|
92
|
|
||
Total
|
$
|
234
|
|
$
|
406
|
|
|
Year Ended December 31,
|
||||||
(In millions)
|
2015
|
|
2014
|
||||
North America E&P
|
$
|
(486
|
)
|
|
$
|
693
|
|
International E&P
|
112
|
|
|
568
|
|
||
Oil Sands Mining
|
(113
|
)
|
|
235
|
|
||
Segment income (loss)
|
(487
|
)
|
|
1,496
|
|
||
Items not allocated to segments, net of income taxes
|
$
|
(1,717
|
)
|
|
(527
|
)
|
|
Income (loss) from continuing operations
|
(2,204
|
)
|
|
969
|
|
||
Discontinued operations
|
—
|
|
|
2,077
|
|
||
Net income (loss)
|
$
|
(2,204
|
)
|
|
$
|
3,046
|
|
•
|
Divested of certain non-core assets resulting in net proceeds of $
1.2 billion
|
•
|
Raised proceeds of
$1.2 billion
from an equity offering in the first quarter of 2016
|
•
|
Expanded the capacity of the revolving credit facility from $3.0 billion to $3.3 billion in the first quarter of 2016
|
•
|
Improved cost structure by reducing total company production expenses by 23% and production expense per boe in 2016 by:
|
•
|
Increased cash and cash equivalents by $1.3 billion from year-end 2015
|
•
|
Progressed our 2017 commodity hedging program which covers approximately 40% of our expected U.S. crude oil and natural gas production. Pricing for these hedges is discussed in further detail in Item 8. Financial Statements and Supplementary Data – Note 16 to the consolidated financial statements
|
|
Year Ended December 31,
|
||||||||||
(In millions)
|
2016
|
|
2015
|
|
2014
|
||||||
Sources of cash and cash equivalents
|
|
|
|
|
|
|
|
||||
Continuing operations
|
$
|
1,073
|
|
|
$
|
1,565
|
|
|
$
|
4,736
|
|
Discontinued operations
|
—
|
|
|
—
|
|
|
751
|
|
|||
Disposals of assets
|
1,219
|
|
|
225
|
|
|
3,760
|
|
|||
Issuance of common stock
|
1,236
|
|
|
—
|
|
|
—
|
|
|||
Maturities of short-term investment
|
—
|
|
|
925
|
|
|
—
|
|
|||
Borrowings, net
|
—
|
|
|
1,996
|
|
|
—
|
|
|||
Other
|
56
|
|
|
91
|
|
|
214
|
|
|||
Total sources of cash and cash equivalents
|
$
|
3,584
|
|
|
$
|
4,802
|
|
|
$
|
9,461
|
|
Uses of cash and cash equivalents
|
|
|
|
|
|
||||||
Cash additions to property, plant and equipment
|
$
|
(1,245
|
)
|
|
$
|
(3,476
|
)
|
|
$
|
(5,160
|
)
|
Purchases of short-term investments
|
—
|
|
|
(925
|
)
|
|
—
|
|
|||
Investing activities of discontinued operations
|
—
|
|
|
—
|
|
|
(376
|
)
|
|||
Acquisitions
|
(902
|
)
|
|
—
|
|
|
(21
|
)
|
|||
Purchases of common stock
|
—
|
|
|
—
|
|
|
(1,000
|
)
|
|||
Commercial paper, net
|
—
|
|
|
—
|
|
|
(135
|
)
|
|||
Debt repayments
|
(1
|
)
|
|
(1,069
|
)
|
|
(68
|
)
|
|||
Debt issuance costs
|
—
|
|
|
(19
|
)
|
|
—
|
|
|||
Dividends paid
|
(162
|
)
|
|
(460
|
)
|
|
(543
|
)
|
|||
Other
|
(5
|
)
|
|
(30
|
)
|
|
(24
|
)
|
|||
Total uses of cash and cash equivalents
|
$
|
(2,315
|
)
|
|
$
|
(5,979
|
)
|
|
$
|
(7,327
|
)
|
|
Year Ended December 31,
|
||||||||||
(In millions)
|
2016
|
|
2015
|
|
2014
|
||||||
North America E&P
|
$
|
936
|
|
|
$
|
2,553
|
|
|
$
|
4,698
|
|
International E&P
|
82
|
|
|
368
|
|
|
534
|
|
|||
Oil Sands Mining
(a)
|
33
|
|
|
(10
|
)
|
|
212
|
|
|||
Corporate
|
18
|
|
|
25
|
|
|
51
|
|
|||
Total capital expenditures
|
1,069
|
|
|
2,936
|
|
|
5,495
|
|
|||
Change in capital expenditure accrual
|
176
|
|
|
540
|
|
|
(335
|
)
|
|||
Additions to property, plant and equipment
|
$
|
1,245
|
|
|
$
|
3,476
|
|
|
$
|
5,160
|
|
(Dollars in millions)
|
2016
|
|
2015
|
||||
Long-term debt due within one year
|
$
|
686
|
|
|
$
|
1
|
|
Long-term debt
|
6,589
|
|
|
7,276
|
|
||
Total debt
|
$
|
7,275
|
|
|
$
|
7,277
|
|
Cash and cash equivalents
|
$
|
2,490
|
|
|
$
|
1,221
|
|
Equity
|
$
|
17,541
|
|
|
$
|
18,553
|
|
Calculation
|
|
|
|
||||
Total debt
|
$
|
7,275
|
|
|
$
|
7,277
|
|
Minus cash and cash equivalents
|
2,490
|
|
|
1,221
|
|
||
Total debt minus cash and cash equivalents
|
4,785
|
|
|
6,056
|
|
||
Total debt
|
$
|
7,275
|
|
|
$
|
7,277
|
|
Plus equity
|
17,541
|
|
|
18,553
|
|
||
Minus cash and cash equivalents
|
2,490
|
|
|
1,221
|
|
||
Total debt plus equity minus cash, cash equivalents
|
$
|
22,326
|
|
|
$
|
24,609
|
|
Cash-adjusted debt-to-capital ratio
|
21
|
%
|
|
25
|
%
|
(In millions)
|
Total
|
|
2017
|
|
2018-
2019
|
|
2020-
2021
|
|
Later
Years
|
||||||||||
Short and long-term debt (includes interest)
(a)
|
$
|
11,318
|
|
|
$
|
1,042
|
|
|
$
|
1,654
|
|
|
$
|
1,102
|
|
|
$
|
7,520
|
|
Lease obligations
|
183
|
|
|
36
|
|
|
58
|
|
|
55
|
|
|
34
|
|
|||||
Purchase obligations:
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil and gas activities
(b)
|
151
|
|
|
128
|
|
|
14
|
|
|
7
|
|
|
2
|
|
|||||
Service and materials contracts
(c)
|
764
|
|
|
78
|
|
|
93
|
|
|
28
|
|
|
565
|
|
|||||
Transportation and related contracts
|
1,606
|
|
|
256
|
|
|
483
|
|
|
261
|
|
|
606
|
|
|||||
Drilling rigs and fracturing crews
(d)
|
44
|
|
|
44
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Other
|
126
|
|
|
20
|
|
|
32
|
|
|
22
|
|
|
52
|
|
|||||
Total purchase obligations
|
2,691
|
|
|
526
|
|
|
622
|
|
|
318
|
|
|
1,225
|
|
|||||
Other long-term liabilities reported in the consolidated balance sheet
(e)
|
370
|
|
|
51
|
|
|
69
|
|
|
69
|
|
|
181
|
|
|||||
Total contractual cash obligations
(f)
|
$
|
14,562
|
|
|
$
|
1,655
|
|
|
$
|
2,403
|
|
|
$
|
1,544
|
|
|
$
|
8,960
|
|
(a)
|
Includes anticipated cash payments for interest of
$359 million
for
2017
,
$572 million
for
2018
-
2019
,
$502 million
for
2020
-
2021
and
$2,585 million
for the remaining years for a total of
$4,018 million
.
|
(b)
|
Oil and gas activities include contracts to acquire property, plant and equipment and commitments for oil and gas exploration such as costs related to contractually obligated exploratory work programs that are expensed immediately.
|
(c)
|
Service and materials contracts include contracts to purchase services such as utilities, supplies and various other maintenance and operating services.
|
(d)
|
Some contracts may be canceled at an amount less than the contract amount. Were we to elect that option where possible at December 31,
2016
our minimum commitment would be
$42 million
.
|
(e)
|
Primarily includes obligations for pension and other postretirement benefits including medical and life insurance. We have estimated projected funding requirements through 2026. Although unrecognized tax benefits are not a contractual obligation, they are presented in this table because they represent potential demands on our liquidity.
|
(f)
|
This table does not include the estimated discounted liability for dismantlement, abandonment and restoration costs of oil and gas properties of
$1,748 million
. See Item 8. Financial Statements and Supplementary Data – Note
18
to the consolidated financial statements.
|
|
SEC Pricing 2016
|
||
WTI Crude oil
(per bbl)
|
$
|
42.75
|
|
Henry Hub natural gas
(per mmbtu)
|
$
|
2.49
|
|
Brent crude oil
(per bbl)
|
$
|
43.53
|
|
Mont Belvieu NGLs
(per bbl)
|
$
|
15.89
|
|
|
Impact of a 10% Increase in Proved Reserves
|
|
Impact of a 10% Decrease in Proved Reserves
|
||||||||||||
(In millions, except per boe)
|
DD&A per boe
|
|
Pretax Income
|
|
DD&A per boe
|
|
Pretax Income
|
||||||||
North America E&P
|
$
|
(2.04
|
)
|
|
$
|
167
|
|
|
$
|
2.50
|
|
|
$
|
(204
|
)
|
International E&P
|
$
|
(0.56
|
)
|
|
$
|
25
|
|
|
$
|
0.69
|
|
|
$
|
(31
|
)
|
Oil Sands Mining
|
$
|
(0.99
|
)
|
|
$
|
18
|
|
|
$
|
1.26
|
|
|
$
|
(22
|
)
|
•
|
Level 1 – Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
|
•
|
Level 2 – Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the measurement date.
|
•
|
Level 3 – Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.
|
•
|
impairment assessments of long-lived assets;
|
•
|
impairment assessments of goodwill; and
|
•
|
recorded value of derivative instruments.
|
•
|
Future crude oil and condensate, NGLs, natural gas and synthetic crude oil prices.
Our estimates of future prices are based on our analysis of market supply and demand and consideration of market price indicators. Although these commodity prices may experience extreme volatility in any given year, we believe long-term industry prices are driven by global market supply and demand. To estimate supply, we consider numerous factors, including the worldwide resource base, depletion rates and OPEC production policies. We believe demand is largely driven by global economic factors, such as population and income growth, governmental policies and vehicle stocks. The prices we use in our fair value estimates are consistent with those used in our planning and capital investment reviews. There has been significant volatility in crude oil and condensate, NGLs, natural gas and synthetic crude oil prices and estimates of such future prices are inherently imprecise. See Item 1A. Risk Factors for further discussion on commodity prices.
|
•
|
Estimated quantities of crude oil and condensate, NGLs, natural gas and synthetic crude oil.
Such quantities are based on a combination of proved reserves and risk-weighted probable reserves and resources such that the combined volumes represent the most likely expectation of recovery. See Item 1A. Risk Factors for further discussion on reserves.
|
•
|
Expected timing of production.
Production forecasts are the outcome of engineer studies which estimate reserves, as well as expected capital development programs. The actual timing of the production could be different than the projection. Cash flows realized later in the projection period are less valuable than those realized earlier due to the time value of money. The expected timing of production that we use in our fair value estimates is consistent with that used in our planning and capital investment reviews.
|
•
|
Discount rate commensurate with the risks involved.
We apply a discount rate to our expected cash flows based on a variety of factors, including market and economic conditions, operational risk, regulatory risk and political risk. A higher discount rate decreases the net present value of cash flows.
|
•
|
Future capital requirements.
Our estimates of future capital requirements are based upon a combination of authorized spending and internal forecasts.
|
•
|
the discount rate for measuring the present value of future plan obligations;
|
•
|
the expected long-term return on plan assets;
|
•
|
the rate of future increases in compensation levels; and
|
•
|
health care cost projections.
|
|
Impact of a 0.25% Increase in Discount Rate
|
|
Impact of a 0.25% Decrease in Discount Rate
|
||||||||||||
(In millions)
|
Obligation
|
|
Expense
|
|
Obligation
|
|
Expense
|
||||||||
U.S. pension plans
|
$
|
(5
|
)
|
|
$
|
—
|
|
|
$
|
6
|
|
|
$
|
—
|
|
Other U.S. postretirement benefit plans
|
$
|
(5
|
)
|
|
$
|
—
|
|
|
$
|
5
|
|
|
$
|
—
|
|
Crude Oil
(a)
|
|||||||
|
2017
|
||||||
|
First Quarter
|
|
Second Quarter
|
|
Third Quarter
|
|
Fourth Quarter
|
Three-Way Collars
(b)
|
|
|
|
|
|
|
|
Volume (Bbls/day)
|
50,000
|
|
50,000
|
|
30,000
|
|
30,000
|
Price per Bbl:
|
|
|
|
|
|
|
|
Ceiling
|
$58.42
|
|
$58.42
|
|
$59.60
|
|
$59.60
|
Floor
|
$50.30
|
|
$50.30
|
|
$54.00
|
|
$54.00
|
Sold put
|
$43.50
|
|
$43.50
|
|
$47.00
|
|
$47.00
|
Sold Call Options
(c)
|
|
|
|
|
|
|
|
Volume (Bbls/day)
|
35,000
|
|
35,000
|
|
35,000
|
|
35,000
|
Price per Bbl
|
$61.91
|
|
$61.91
|
|
$61.91
|
|
$61.91
|
(a)
|
Subsequent to December 31, 2016, we entered into 10,000 Bbls/day of fixed-price swaps with a weighted average price of $54.00 indexed to WTI for February - March of 2017.
|
(b)
|
Subsequent to December 31, 2016, we entered into 20,000 Bbls/day of three-way collars for July - December of 2017 with a ceiling price of $61.52, a floor price of $56.00, and a sold put price of $49.00.
|
(c)
|
Call options settle monthly.
|
Natural Gas
|
|||||
|
2017
|
2018
|
|||
|
First Quarter
|
Second Quarter
|
Third Quarter
|
Fourth Quarter
|
|
Three-Way Collars
(a)
|
|
|
|
|
|
Volume (MMBtu/day)
|
60,000
|
90,000
|
90,000
|
90,000
|
20,000
|
Price per MMBtu
|
|
|
|
|
|
Ceiling
|
$3.46
|
$3.54
|
$3.54
|
$3.61
|
$3.56
|
Floor
|
$2.84
|
$3.01
|
$3.01
|
$3.04
|
$3.00
|
Sold put
|
$2.35
|
$2.48
|
$2.48
|
$2.52
|
$2.50
|
Swap
|
|
|
|
|
|
Volume (MMBtu/day)
|
20,000
|
20,000
|
20,000
|
20,000
|
—
|
Price per MMBtu
|
2.93
|
2.93
|
2.93
|
2.93
|
—
|
(a)
|
Subsequent to December 31, 2016, we entered into three-way collars of 30,000 MMBtus/day for April - September of 2017 with a ceiling price of $3.70, a floor price of $3.35, and a sold put price of $2.75; 30,000 MMBtus/day for October - December of 2017 with a ceiling price of $4.00, a floor price of $3.45, and a sold put price of $2.85; and 70,000 MMBtus/day for January - December of 2018 with a ceiling price of $3.62, a floor price of $3.00, and a sold put price of $2.50.
|
(In millions)
|
Hypothetical Price Increase of 10%
|
Hypothetical Price Decrease of 10%
|
||
Crude oil derivatives
|
(79
|
)
|
56
|
|
Natural gas derivatives
|
(11
|
)
|
13
|
|
Total
|
(90
|
)
|
69
|
|
(a)
|
Fair values of cash and cash equivalents, receivables, accounts payable and accrued interest approximate carrying value and are relatively insensitive to changes in interest rates due to the short-term maturity of the instruments. Accordingly, these instruments are excluded from the table.
|
(b)
|
Fair value was based on market prices where available, or current borrowing rates for financings with similar terms and maturities.
|
(c)
|
Excludes capital leases.
|
|
Page
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Lee M. Tillman
|
|
/s/ Patrick J. Wagner
|
|
|
President and Chief Executive Officer
|
|
Interim Chief Financial Officer and Vice President-Corporate Development and Strategy
|
|
|
/s/ Lee M. Tillman
|
|
/s/ Patrick J. Wagner
|
|
President and Chief Executive Officer
|
|
Interim Chief Financial Officer and Vice President-Corporate Development and Strategy
|
|
|
Year Ended December 31,
|
||||||||||
(In millions, except per share data)
|
2016
|
|
2015
|
|
2014
|
||||||
Revenues and other income:
|
|
|
|
|
|
||||||
Sales and other operating revenues, including related party
|
$
|
3,753
|
|
|
$
|
4,951
|
|
|
$
|
8,736
|
|
Marketing revenues
|
278
|
|
|
571
|
|
|
2,110
|
|
|||
Income from equity method investments
|
175
|
|
|
145
|
|
|
424
|
|
|||
Net gain (loss) on disposal of assets
|
389
|
|
|
120
|
|
|
(90
|
)
|
|||
Other income
|
55
|
|
|
74
|
|
|
78
|
|
|||
Total revenues and other income
|
4,650
|
|
|
5,861
|
|
|
11,258
|
|
|||
Costs and expenses:
|
|
|
|
|
|
||||||
Production
|
1,313
|
|
|
1,694
|
|
|
2,246
|
|
|||
Marketing, including purchases from related parties
|
282
|
|
|
569
|
|
|
2,105
|
|
|||
Other operating
|
511
|
|
|
438
|
|
|
462
|
|
|||
Exploration
|
330
|
|
|
1,318
|
|
|
793
|
|
|||
Depreciation, depletion and amortization
|
2,395
|
|
|
2,957
|
|
|
2,861
|
|
|||
Impairments
|
67
|
|
|
752
|
|
|
132
|
|
|||
Taxes other than income
|
168
|
|
|
234
|
|
|
406
|
|
|||
General and administrative
|
484
|
|
|
590
|
|
|
654
|
|
|||
Total costs and expenses
|
5,550
|
|
|
8,552
|
|
|
9,659
|
|
|||
Income (loss) from operations
|
(900
|
)
|
|
(2,691
|
)
|
|
1,599
|
|
|||
Net interest and other
|
(335
|
)
|
|
(267
|
)
|
|
(238
|
)
|
|||
Income (loss) from continuing operations before income taxes
|
(1,235
|
)
|
|
(2,958
|
)
|
|
1,361
|
|
|||
Provision (benefit) for income taxes
|
905
|
|
|
(754
|
)
|
|
392
|
|
|||
Income (loss) from continuing operations
|
(2,140
|
)
|
|
(2,204
|
)
|
|
969
|
|
|||
Discontinued operations
|
—
|
|
|
—
|
|
|
2,077
|
|
|||
Net income (loss)
|
$
|
(2,140
|
)
|
|
$
|
(2,204
|
)
|
|
$
|
3,046
|
|
Per Share Data
|
|
|
|
|
|
||||||
Basic:
|
|
|
|
|
|
||||||
Income (loss) from continuing operations
|
$
|
(2.61
|
)
|
|
$
|
(3.26
|
)
|
|
$
|
1.42
|
|
Discontinued operations
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3.06
|
|
Net income (loss)
|
$
|
(2.61
|
)
|
|
$
|
(3.26
|
)
|
|
$
|
4.48
|
|
Diluted:
|
|
|
|
|
|
||||||
Income (loss) from continuing operations
|
$
|
(2.61
|
)
|
|
$
|
(3.26
|
)
|
|
$
|
1.42
|
|
Discontinued operations
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3.04
|
|
Net income (loss)
|
$
|
(2.61
|
)
|
|
$
|
(3.26
|
)
|
|
$
|
4.46
|
|
Dividends
|
$
|
0.20
|
|
|
$
|
0.68
|
|
|
$
|
0.80
|
|
Weighted average shares:
|
|
|
|
|
|
||||||
Basic
|
819
|
|
|
677
|
|
|
680
|
|
|||
Diluted
|
819
|
|
|
677
|
|
|
683
|
|
|
Year Ended December 31,
|
||||||||||
(In millions)
|
2016
|
|
2015
|
|
2014
|
||||||
Net income (loss)
|
$
|
(2,140
|
)
|
|
$
|
(2,204
|
)
|
|
$
|
3,046
|
|
Other comprehensive income (loss)
|
|
|
|
|
|
||||||
Postretirement and postemployment plans
|
|
|
|
|
|
||||||
Change in actuarial loss and other
|
16
|
|
|
228
|
|
|
(52
|
)
|
|||
Income tax benefit (provision)
|
(4
|
)
|
|
(86
|
)
|
|
25
|
|
|||
Postretirement and postemployment plans, net of tax
|
12
|
|
|
142
|
|
|
(27
|
)
|
|||
Derivative hedges
|
|
|
|
|
|
||||||
Net unrecognized gain
|
61
|
|
|
—
|
|
|
1
|
|
|||
Income tax provision
|
(22
|
)
|
|
—
|
|
|
—
|
|
|||
Derivative hedges, net of tax
|
39
|
|
|
—
|
|
|
1
|
|
|||
Other, net of tax
|
1
|
|
|
—
|
|
|
(1
|
)
|
|||
Other comprehensive income (loss)
|
52
|
|
|
142
|
|
|
(27
|
)
|
|||
Comprehensive income (loss)
|
$
|
(2,088
|
)
|
|
$
|
(2,062
|
)
|
|
$
|
3,019
|
|
|
December 31,
|
||||||
(In millions, except par values and share amounts)
|
2016
|
|
2015
|
||||
Assets
|
|
|
|
||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
2,490
|
|
|
$
|
1,221
|
|
Receivables, less reserve of $6 and $4
|
877
|
|
|
912
|
|
||
Inventories
|
227
|
|
|
313
|
|
||
Other current assets
|
71
|
|
|
144
|
|
||
Total current assets
|
3,665
|
|
|
2,590
|
|
||
Equity method investments
|
931
|
|
|
1,003
|
|
||
Property, plant and equipment, less accumulated depreciation,
|
|
|
|
|
|
||
depletion and amortization of $22,214 and $23,260
|
25,718
|
|
|
27,061
|
|
||
Goodwill
|
115
|
|
|
115
|
|
||
Other noncurrent assets
|
665
|
|
|
1,542
|
|
||
Total assets
|
$
|
31,094
|
|
|
$
|
32,311
|
|
Liabilities
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Accounts payable
|
1,078
|
|
|
1,313
|
|
||
Payroll and benefits payable
|
129
|
|
|
133
|
|
||
Accrued taxes
|
94
|
|
|
132
|
|
||
Other current liabilities
|
253
|
|
|
150
|
|
||
Long-term debt due within one year
|
686
|
|
|
1
|
|
||
Total current liabilities
|
2,240
|
|
|
1,729
|
|
||
Long-term debt
|
6,589
|
|
|
7,276
|
|
||
Deferred tax liabilities
|
2,438
|
|
|
2,441
|
|
||
Defined benefit postretirement plan obligations
|
345
|
|
|
403
|
|
||
Asset retirement obligations
|
1,697
|
|
|
1,601
|
|
||
Deferred credits and other liabilities
|
244
|
|
|
308
|
|
||
Total liabilities
|
13,553
|
|
|
13,758
|
|
||
Commitments and contingencies
|
|
|
|
|
|||
Stockholders’ Equity
|
|
|
|
||||
Preferred stock - no shares issued or outstanding (no par value,
|
|
|
|
||||
26 million shares authorized)
|
—
|
|
|
—
|
|
||
Common stock:
|
|
|
|
||||
Issued – 937 million and 770 million shares, respectively (par value $1 per share, 1.1 billion shares authorized)
|
937
|
|
|
770
|
|
||
Securities exchangeable into common stock – no shares issued
|
|
|
|
|
|
||
or outstanding (no par value, 29 million shares authorized)
|
—
|
|
|
—
|
|
||
Held in treasury, at cost – 90 million and 93 million shares
|
(3,431
|
)
|
|
(3,554
|
)
|
||
Additional paid-in capital
|
7,446
|
|
|
6,498
|
|
||
Retained earnings
|
12,672
|
|
|
14,974
|
|
||
Accumulated other comprehensive loss
|
(83
|
)
|
|
(135
|
)
|
||
Total stockholders' equity
|
17,541
|
|
|
18,553
|
|
||
Total liabilities and stockholders' equity
|
$
|
31,094
|
|
|
$
|
32,311
|
|
|
Year Ended December 31,
|
||||||||||
(In millions)
|
2016
|
|
2015
|
|
2014
|
||||||
Increase (decrease) in cash and cash equivalents
|
|
|
|
|
|
||||||
Operating activities:
|
|
|
|
|
|
|
|||||
Net income (loss)
|
$
|
(2,140
|
)
|
|
$
|
(2,204
|
)
|
|
$
|
3,046
|
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
|
|||||
Discontinued operations
|
—
|
|
|
—
|
|
|
(2,077
|
)
|
|||
Depreciation, depletion and amortization
|
2,395
|
|
|
2,957
|
|
|
2,861
|
|
|||
Impairments
|
67
|
|
|
752
|
|
|
132
|
|
|||
Exploratory dry well costs and unproved property impairments
|
227
|
|
|
1,214
|
|
|
623
|
|
|||
Net (gain) loss on disposal of assets
|
(389
|
)
|
|
(120
|
)
|
|
90
|
|
|||
Deferred income taxes
|
811
|
|
|
(806
|
)
|
|
88
|
|
|||
Net (gain) loss on derivative instruments
|
63
|
|
|
(126
|
)
|
|
(4
|
)
|
|||
Net cash received (paid) in settlement of derivative instruments
|
61
|
|
|
55
|
|
|
(5
|
)
|
|||
Pension and other postretirement benefits, net
|
(3
|
)
|
|
1
|
|
|
(34
|
)
|
|||
Stock based compensation
|
48
|
|
|
44
|
|
|
52
|
|
|||
Equity method investments, net
|
17
|
|
|
33
|
|
|
27
|
|
|||
Changes in:
|
|
|
|
|
|
||||||
Current receivables
|
50
|
|
|
817
|
|
|
119
|
|
|||
Inventories
|
75
|
|
|
36
|
|
|
(11
|
)
|
|||
Current accounts payable and accrued liabilities
|
(133
|
)
|
|
(965
|
)
|
|
(33
|
)
|
|||
All other operating, net
|
(76
|
)
|
|
(123
|
)
|
|
(138
|
)
|
|||
Net cash provided by continuing operations
|
1,073
|
|
|
1,565
|
|
|
4,736
|
|
|||
Net cash provided by discontinued operations
|
—
|
|
|
—
|
|
|
751
|
|
|||
Net cash provided by operating activities
|
1,073
|
|
|
1,565
|
|
|
5,487
|
|
|||
Investing activities:
|
|
|
|
|
|
||||||
Additions to property, plant and equipment
|
(1,245
|
)
|
|
(3,476
|
)
|
|
(5,160
|
)
|
|||
Acquisitions, net of cash acquired
|
(902
|
)
|
|
—
|
|
|
(21
|
)
|
|||
Disposal of assets
|
1,219
|
|
|
225
|
|
|
3,760
|
|
|||
Equity method investments - return of capital
|
55
|
|
|
77
|
|
|
61
|
|
|||
Investing activities of discontinued operations
|
—
|
|
|
—
|
|
|
(376
|
)
|
|||
Purchases of short term investments
|
—
|
|
|
(925
|
)
|
|
—
|
|
|||
Maturities of short term investments
|
—
|
|
|
925
|
|
|
—
|
|
|||
All other investing, net
|
(1
|
)
|
|
(28
|
)
|
|
(10
|
)
|
|||
Net cash used in investing activities
|
(874
|
)
|
|
(3,202
|
)
|
|
(1,746
|
)
|
|||
Financing activities:
|
|
|
|
|
|
||||||
Borrowings
|
—
|
|
|
1,996
|
|
|
—
|
|
|||
Debt repayments
|
(1
|
)
|
|
(1,069
|
)
|
|
(68
|
)
|
|||
Purchases of common stock
|
—
|
|
|
—
|
|
|
(1,000
|
)
|
|||
Issuance of common stock
|
1,236
|
|
|
—
|
|
|
—
|
|
|||
Dividends paid
|
(162
|
)
|
|
(460
|
)
|
|
(543
|
)
|
|||
All other financing, net
|
1
|
|
|
(5
|
)
|
|
18
|
|
|||
Net cash provided by (used in) financing activities
|
1,074
|
|
|
462
|
|
|
(1,593
|
)
|
|||
Effect of exchange rate changes on cash:
|
|
|
|
|
|
||||||
Continuing operations
|
(4
|
)
|
|
(2
|
)
|
|
(2
|
)
|
|||
Discontinued operations
|
—
|
|
|
—
|
|
|
(12
|
)
|
|||
Net increase (decrease) in cash and cash equivalents
|
1,269
|
|
|
(1,177
|
)
|
|
2,134
|
|
|||
Cash and cash equivalents at beginning of period
|
1,221
|
|
|
2,398
|
|
|
264
|
|
|||
Cash and cash equivalents at end of period
|
$
|
2,490
|
|
|
$
|
1,221
|
|
|
$
|
2,398
|
|
|
Total Equity of Marathon Oil Stockholders
|
|
|
||||||||||||||||||||||||||||
(In millions)
|
Preferred
Stock
|
|
Common
Stock
|
|
Securities
Exchangeable
into Common
Stock
|
|
Treasury
Stock
|
|
Additional
Paid-in
Capital
|
|
Retained
Earnings
|
|
Accumulated
Other
Comprehensive
Loss
|
|
Total
Equity
|
||||||||||||||||
December 31, 2013 Balance
|
$
|
—
|
|
|
$
|
770
|
|
|
$
|
—
|
|
|
$
|
(2,903
|
)
|
|
$
|
6,592
|
|
|
$
|
15,135
|
|
|
$
|
(250
|
)
|
|
$
|
19,344
|
|
Shares issued - stock-based
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
276
|
|
|
(57
|
)
|
|
—
|
|
|
—
|
|
|
219
|
|
||||||||
Shares repurchased
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,015
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,015
|
)
|
||||||||
Stock-based compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
||||||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,046
|
|
|
—
|
|
|
3,046
|
|
||||||||
Other comprehensive loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(27
|
)
|
|
(27
|
)
|
||||||||
Dividends paid
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(543
|
)
|
|
—
|
|
|
(543
|
)
|
||||||||
December 31, 2014 Balance
|
$
|
—
|
|
|
$
|
770
|
|
|
$
|
—
|
|
|
$
|
(3,642
|
)
|
|
$
|
6,531
|
|
|
$
|
17,638
|
|
|
$
|
(277
|
)
|
|
$
|
21,020
|
|
Shares issued - stock-based
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
96
|
|
|
(32
|
)
|
|
—
|
|
|
—
|
|
|
64
|
|
||||||||
Shares repurchased
|
—
|
|
|
—
|
|
|
—
|
|
|
(8
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(8
|
)
|
||||||||
Stock-based compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
||||||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,204
|
)
|
|
—
|
|
|
(2,204
|
)
|
||||||||
Other comprehensive income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
142
|
|
|
142
|
|
||||||||
Dividends paid
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(460
|
)
|
|
—
|
|
|
(460
|
)
|
||||||||
December 31, 2015 Balance
|
$
|
—
|
|
|
$
|
770
|
|
|
$
|
—
|
|
|
$
|
(3,554
|
)
|
|
$
|
6,498
|
|
|
$
|
14,974
|
|
|
$
|
(135
|
)
|
|
$
|
18,553
|
|
Shares issued - stock-based
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
128
|
|
|
(86
|
)
|
|
—
|
|
|
—
|
|
|
42
|
|
||||||||
Shares repurchased
|
—
|
|
|
—
|
|
|
—
|
|
|
(5
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(5
|
)
|
||||||||
Stock-based compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(35
|
)
|
|
—
|
|
|
—
|
|
|
(35
|
)
|
||||||||
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,140
|
)
|
|
—
|
|
|
(2,140
|
)
|
||||||||
Other comprehensive income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
52
|
|
|
52
|
|
||||||||
Dividends paid
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(162
|
)
|
|
—
|
|
|
(162
|
)
|
||||||||
Common stock issuance
|
—
|
|
|
167
|
|
|
—
|
|
|
—
|
|
|
1,069
|
|
|
—
|
|
|
—
|
|
|
1,236
|
|
||||||||
December 31, 2016 Balance
|
$
|
—
|
|
|
$
|
937
|
|
|
$
|
—
|
|
|
$
|
(3,431
|
)
|
|
$
|
7,446
|
|
|
$
|
12,672
|
|
|
$
|
(83
|
)
|
|
$
|
17,541
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
(Shares in millions)
|
Preferred
Stock
|
|
Common
Stock
|
|
Securities
Exchangeable
into Common
Stock
|
|
Treasury
Stock
|
|
|
|
|
|
|
|
|
||||||||||||||||
December 31, 2013 Balance
|
—
|
|
|
770
|
|
|
—
|
|
|
73
|
|
|
|
|
|
|
|
|
|
||||||||||||
Shares issued - stock-based
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
(7
|
)
|
|
|
|
|
|
|
|
|
||||||||||||
Shares repurchased
|
—
|
|
|
—
|
|
|
—
|
|
|
29
|
|
|
|
|
|
|
|
|
|
||||||||||||
December 31, 2014 Balance
|
—
|
|
|
770
|
|
|
—
|
|
|
95
|
|
|
|
|
|
|
|
|
|
||||||||||||
Shares issued - stock-based
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
||||||||||||
Shares repurchased
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
||||||||||||
December 31, 2015 Balance
|
—
|
|
|
770
|
|
|
—
|
|
|
93
|
|
|
|
|
|
|
|
|
|
||||||||||||
Shares issued - stock-based
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
||||||||||||
Shares repurchased
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
||||||||||||
Common stock issuance
|
—
|
|
|
167
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
||||||||||||
December 31, 2016 Balance
|
—
|
|
|
937
|
|
|
—
|
|
|
90
|
|
|
|
|
|
|
|
|
|
Type of Asset
|
|
Range of Useful Lives
|
Office furniture, equipment and computer hardware
|
|
3 to 15 years
|
Pipelines
|
|
10 to 40 years
|
Plants, facilities, mine equipment and infrastructure
|
|
3 to 40 years
|
3.
|
Variable Interest Entities
|
|
Year Ended December 31,
|
||||||||||
(In millions, except per share data)
|
2016
|
|
2015
|
|
2014
|
||||||
Income (loss) from continuing operations
|
$
|
(2,140
|
)
|
|
$
|
(2,204
|
)
|
|
$
|
969
|
|
Discontinued operations
|
—
|
|
|
—
|
|
|
2,077
|
|
|||
Net income (loss)
|
$
|
(2,140
|
)
|
|
$
|
(2,204
|
)
|
|
$
|
3,046
|
|
|
|
|
|
|
|
||||||
Weighted average common shares outstanding
|
819
|
|
|
677
|
|
|
680
|
|
|||
Effect of dilutive securities
|
—
|
|
|
—
|
|
|
3
|
|
|||
Weighted average common shares, diluted
|
819
|
|
|
677
|
|
|
683
|
|
|||
Per basic share:
|
|
|
|
|
|
|
|
||||
Income (loss) from continuing operations
|
$
|
(2.61
|
)
|
|
$
|
(3.26
|
)
|
|
$
|
1.42
|
|
Discontinued operations
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3.06
|
|
Net income (loss)
|
$
|
(2.61
|
)
|
|
$
|
(3.26
|
)
|
|
$
|
4.48
|
|
Per diluted share:
|
|
|
|
|
|
||||||
Income (loss) from continuing operations
|
$
|
(2.61
|
)
|
|
$
|
(3.26
|
)
|
|
$
|
1.42
|
|
Discontinued operations
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3.04
|
|
Net income (loss)
|
$
|
(2.61
|
)
|
|
$
|
(3.26
|
)
|
|
$
|
4.46
|
|
(In millions)
|
Year Ended December 31, 2014
|
||
Revenues applicable to discontinued operations
|
$
|
1,981
|
|
Pretax income from discontinued operations
|
$
|
1,693
|
|
Pretax gain on disposition of discontinued operations
|
$
|
1,406
|
|
(In millions)
|
December 31, 2014
|
||
Revenues applicable to discontinued operations
|
$
|
58
|
|
Pretax income from discontinued operations
|
$
|
51
|
|
Pretax gain on disposition of discontinued operations
|
$
|
426
|
|
•
|
North America E&P ("N.A. E&P") – explores for, produces and markets crude oil and condensate, NGLs and natural gas in North America;
|
•
|
International E&P ("Int'l E&P") – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of North America and produces and markets products manufactured from natural gas, such as LNG and methanol, in E.G.; and
|
•
|
Oil Sands Mining (“OSM”) – mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and market synthetic crude oil and vacuum gas oil.
|
Year Ended December 31, 2016
|
|
|
Not Allocated
|
|
|
||||||||||||||
(In millions)
|
N.A. E&P
|
|
Int'l E&P
|
|
OSM
|
|
to Segments
|
|
Total
|
||||||||||
Sales and other operating revenues
|
$
|
2,375
|
|
|
$
|
665
|
|
|
$
|
823
|
|
|
$
|
(110
|
)
|
(c)
|
$
|
3,753
|
|
Marketing revenues
|
135
|
|
|
105
|
|
|
38
|
|
|
—
|
|
|
278
|
|
|||||
Total revenues
|
2,510
|
|
|
770
|
|
|
861
|
|
|
(110
|
)
|
|
4,031
|
|
|||||
Income from equity method investments
|
—
|
|
|
175
|
|
|
—
|
|
|
—
|
|
|
175
|
|
|||||
Net gain on disposal of assets and other income
|
28
|
|
|
32
|
|
|
2
|
|
|
382
|
|
(d)
|
444
|
|
|||||
Less:
|
|
|
|
|
|
|
|
|
|
||||||||||
Production expenses
|
486
|
|
|
226
|
|
|
601
|
|
|
—
|
|
|
1,313
|
|
|||||
Marketing costs
|
142
|
|
|
103
|
|
|
37
|
|
|
—
|
|
|
282
|
|
|||||
Exploration expenses
|
127
|
|
|
17
|
|
|
7
|
|
|
179
|
|
(e)
|
330
|
|
|||||
Depreciation, depletion and amortization
|
1,835
|
|
|
276
|
|
|
239
|
|
|
45
|
|
|
2,395
|
|
|||||
Impairments
|
20
|
|
|
—
|
|
|
—
|
|
|
47
|
|
(f)
|
67
|
|
|||||
Other expenses
(a)
|
422
|
|
|
78
|
|
|
33
|
|
|
462
|
|
(g)
|
995
|
|
|||||
Taxes other than income
|
149
|
|
|
—
|
|
|
17
|
|
|
2
|
|
|
168
|
|
|||||
Net interest and other
|
—
|
|
|
—
|
|
|
—
|
|
|
335
|
|
|
335
|
|
|||||
Income tax provision (benefit)
|
(228
|
)
|
|
49
|
|
|
(16
|
)
|
|
1,100
|
|
(h)
|
905
|
|
|||||
Segment income (loss) / Net income (loss)
|
$
|
(415
|
)
|
|
$
|
228
|
|
|
$
|
(55
|
)
|
|
$
|
(1,898
|
)
|
|
$
|
(2,140
|
)
|
Capital expenditures
(b)
|
$
|
936
|
|
|
$
|
82
|
|
|
$
|
33
|
|
|
$
|
18
|
|
|
$
|
1,069
|
|
(a)
|
Includes other operating expenses and general and administrative expenses.
|
(b)
|
Includes accruals.
|
(c)
|
Unrealized loss on commodity derivative instruments.
|
(d)
|
Primarily related to net gain on disposal of assets
(see Note
6
).
|
(f)
|
Proved property impairments (see Note
13
).
|
(g)
|
Includes termination payment on our Gulf of Mexico deepwater drilling rig contract of
$113 million
and includes pension settlement loss of
$103 million
(see Note
20
) and severance related expenses associated with workforce reductions of
$8 million
.
|
(h)
|
Increased valuation allowance on certain of our deferred tax assets
$1,346 million
(see Note
9
).
|
Year Ended December 31, 2015
|
|
|
Not Allocated
|
|
|
||||||||||||||
(In millions)
|
N.A. E&P
|
|
Int'l E&P
|
|
OSM
|
|
to Segments
|
|
Total
|
||||||||||
Sales and other operating revenues
|
$
|
3,358
|
|
|
$
|
728
|
|
|
$
|
815
|
|
|
$
|
50
|
|
(c)
|
$
|
4,951
|
|
Marketing revenues
|
396
|
|
|
103
|
|
|
72
|
|
|
—
|
|
|
571
|
|
|||||
Total revenues
|
3,754
|
|
|
831
|
|
|
887
|
|
|
50
|
|
|
5,522
|
|
|||||
Income (loss) from equity method investments
|
—
|
|
|
157
|
|
|
—
|
|
|
(12
|
)
|
(d)
|
145
|
|
|||||
Net gain on disposal of assets and other income
|
24
|
|
|
27
|
|
|
21
|
|
|
122
|
|
(e)
|
194
|
|
|||||
Less:
|
|
|
|
|
|
|
|
|
|
||||||||||
Production expenses
|
724
|
|
|
255
|
|
|
715
|
|
|
—
|
|
|
1,694
|
|
|||||
Marketing costs
|
401
|
|
|
99
|
|
|
69
|
|
|
—
|
|
|
569
|
|
|||||
Exploration expenses
|
362
|
|
|
101
|
|
|
—
|
|
|
855
|
|
(f)
|
1,318
|
|
|||||
Depreciation, depletion and amortization
|
2,377
|
|
|
295
|
|
|
236
|
|
|
49
|
|
|
2,957
|
|
|||||
Impairments
|
2
|
|
|
—
|
|
|
5
|
|
|
745
|
|
(g)
|
752
|
|
|||||
Other expenses
(a)
|
462
|
|
|
92
|
|
|
34
|
|
|
440
|
|
(h)
|
1,028
|
|
|||||
Taxes other than income
|
215
|
|
|
—
|
|
|
18
|
|
|
1
|
|
|
234
|
|
|||||
Net interest and other
|
—
|
|
|
—
|
|
|
—
|
|
|
267
|
|
|
267
|
|
|||||
Income tax provision (benefit)
|
(279
|
)
|
|
61
|
|
|
(56
|
)
|
|
(480
|
)
|
(i)
|
(754
|
)
|
|||||
Segment income (loss) / Net Income (loss)
|
$
|
(486
|
)
|
|
$
|
112
|
|
|
$
|
(113
|
)
|
|
$
|
(1,717
|
)
|
|
$
|
(2,204
|
)
|
Capital expenditures
(b)
|
$
|
2,553
|
|
|
$
|
368
|
|
|
$
|
(10
|
)
|
|
$
|
25
|
|
|
$
|
2,936
|
|
(a)
|
Includes other operating expenses and general and administrative expenses.
|
(b)
|
Includes accruals.
|
(c)
|
Unrealized gain on commodity derivative instruments.
|
(d)
|
Partial impairment of investment in equity method investee (See Note
15
).
|
(e)
|
Primarily related to gain on sale of our properties and interests in the Gulf of Mexico, partially offset by the loss on sale of East Africa exploration acreage
(see Note
6
).
|
(g)
|
Goodwill impairment (see Note
14
) and proved property impairments (see Note
15
).
|
(h)
|
Includes pension settlement loss of
$119 million
(see Note
20
) and severance related expenses associated with workforce reductions of
$55 million
.
|
Year Ended December 31, 2014
|
|
|
Not Allocated
|
|
|
||||||||||||||
(In millions)
|
N.A. E&P
|
|
Int'l E&P
|
|
OSM
|
|
to Segments
|
|
Total
|
||||||||||
Sales and other operating revenues
|
$
|
5,770
|
|
|
$
|
1,410
|
|
|
$
|
1,556
|
|
|
$
|
—
|
|
|
$
|
8,736
|
|
Marketing revenues
|
1,839
|
|
|
219
|
|
|
52
|
|
|
—
|
|
|
2,110
|
|
|||||
Total revenues
|
7,609
|
|
|
1,629
|
|
|
1,608
|
|
|
—
|
|
|
10,846
|
|
|||||
Income from equity method investments
|
—
|
|
|
424
|
|
|
—
|
|
|
—
|
|
|
424
|
|
|||||
Net gain (loss) on disposal of assets and other income
|
23
|
|
|
57
|
|
|
4
|
|
|
(96
|
)
|
(c)
|
(12
|
)
|
|||||
Less:
|
|
|
|
|
|
|
|
|
|
||||||||||
Production expenses
|
891
|
|
|
386
|
|
|
969
|
|
|
—
|
|
|
2,246
|
|
|||||
Marketing costs
|
1,836
|
|
|
217
|
|
|
52
|
|
|
—
|
|
|
2,105
|
|
|||||
Exploration expenses
|
608
|
|
|
185
|
|
|
—
|
|
|
—
|
|
|
793
|
|
|||||
Depreciation, depletion and amortization
|
2,342
|
|
|
269
|
|
|
206
|
|
|
44
|
|
|
2,861
|
|
|||||
Impairments
|
23
|
|
|
—
|
|
|
—
|
|
|
109
|
|
(d)
|
132
|
|
|||||
Other expenses
(a)
|
473
|
|
|
197
|
|
|
54
|
|
|
392
|
|
(e)
|
1,116
|
|
|||||
Taxes other than income
|
385
|
|
|
—
|
|
|
20
|
|
|
1
|
|
|
406
|
|
|||||
Net interest and other
|
—
|
|
|
—
|
|
|
—
|
|
|
238
|
|
|
238
|
|
|||||
Income tax provision (benefit)
|
381
|
|
|
288
|
|
|
76
|
|
|
(353
|
)
|
|
392
|
|
|||||
Segment income (loss) / Income from continuing operations
|
$
|
693
|
|
|
$
|
568
|
|
|
$
|
235
|
|
|
$
|
(527
|
)
|
|
$
|
969
|
|
Capital expenditures
(b)
|
$
|
4,698
|
|
|
$
|
534
|
|
|
$
|
212
|
|
|
$
|
51
|
|
|
$
|
5,495
|
|
|
Year Ended December 31,
|
||||||||||
(In millions)
|
2016
|
|
2015
|
|
2014
|
||||||
United States
|
$
|
2,400
|
|
|
$
|
3,804
|
|
|
$
|
7,609
|
|
Canada
|
861
|
|
|
887
|
|
|
1,608
|
|
|||
Libya
(a)
|
54
|
|
|
—
|
|
|
244
|
|
|||
Other international
|
716
|
|
|
831
|
|
|
1,385
|
|
|||
Total revenues
|
$
|
4,031
|
|
|
$
|
5,522
|
|
|
$
|
10,846
|
|
(a)
|
See Note
12
for discussion of Libya operations.
|
|
Year Ended December 31,
|
||||||||||
(In millions)
|
2016
|
|
2015
|
|
2014
|
||||||
Crude oil and condensate
|
$
|
2,605
|
|
|
$
|
3,963
|
|
|
$
|
8,170
|
|
Natural gas liquids
|
198
|
|
|
203
|
|
|
371
|
|
|||
Natural gas
|
356
|
|
|
464
|
|
|
693
|
|
|||
Synthetic crude oil
|
816
|
|
|
781
|
|
|
1,525
|
|
|||
Other
|
56
|
|
|
111
|
|
|
87
|
|
|||
Total revenues
|
$
|
4,031
|
|
|
$
|
5,522
|
|
|
$
|
10,846
|
|
|
December 31,
|
||||||
(In millions)
|
2016
|
|
2015
|
||||
United States
|
$
|
14,272
|
|
|
$
|
15,353
|
|
Canada
|
8,991
|
|
|
9,197
|
|
||
Equatorial Guinea
|
1,794
|
|
|
1,917
|
|
||
Other international
|
1,592
|
|
|
1,597
|
|
||
Total long-lived assets
|
$
|
26,649
|
|
|
$
|
28,064
|
|
|
Year Ended December 31,
|
||||||||||
(In millions)
|
2016
|
|
2015
|
|
2014
|
||||||
Interest:
|
|
|
|
|
|
||||||
Interest income
|
$
|
14
|
|
|
$
|
9
|
|
|
$
|
7
|
|
Interest expense
|
(402
|
)
|
|
(358
|
)
|
|
(309
|
)
|
|||
Income on interest rate swaps
|
13
|
|
|
11
|
|
|
12
|
|
|||
Interest capitalized
|
23
|
|
|
26
|
|
|
20
|
|
|||
Total interest
|
(352
|
)
|
|
(312
|
)
|
|
(270
|
)
|
|||
Other:
|
|
|
|
|
|
||||||
Net foreign currency gain (loss)
|
2
|
|
|
23
|
|
|
21
|
|
|||
Other
|
15
|
|
|
22
|
|
|
11
|
|
|||
Total other
|
17
|
|
|
45
|
|
|
32
|
|
|||
Net interest and other
|
$
|
(335
|
)
|
|
$
|
(267
|
)
|
|
$
|
(238
|
)
|
|
Year Ended December 31,
|
||||||||||
(In millions)
|
2016
|
|
2015
|
|
2014
|
||||||
Net interest and other
|
$
|
2
|
|
|
$
|
23
|
|
|
$
|
21
|
|
Provision for income taxes
|
(32
|
)
|
|
(11
|
)
|
|
(12
|
)
|
|||
Aggregate foreign currency gains
|
$
|
(30
|
)
|
|
$
|
12
|
|
|
$
|
9
|
|
|
Year Ended December 31,
|
||||||||||||||||||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||||||||||||||||||||||||||
(In millions)
|
Current
|
|
Deferred
|
|
Total
|
|
Current
|
|
Deferred
|
|
Total
|
|
Current
|
|
Deferred
|
|
Total
|
||||||||||||||||||
Federal
|
$
|
2
|
|
|
$
|
836
|
|
|
$
|
838
|
|
|
$
|
(43
|
)
|
|
$
|
(687
|
)
|
|
$
|
(730
|
)
|
|
$
|
15
|
|
|
$
|
62
|
|
|
$
|
77
|
|
State and local
|
2
|
|
|
8
|
|
|
10
|
|
|
(8
|
)
|
|
(18
|
)
|
|
(26
|
)
|
|
8
|
|
|
(58
|
)
|
|
(50
|
)
|
|||||||||
Foreign
|
90
|
|
|
(33
|
)
|
|
57
|
|
|
103
|
|
|
(101
|
)
|
|
2
|
|
|
281
|
|
|
84
|
|
|
365
|
|
|||||||||
Total
|
$
|
94
|
|
|
$
|
811
|
|
|
$
|
905
|
|
|
$
|
52
|
|
|
$
|
(806
|
)
|
|
$
|
(754
|
)
|
|
$
|
304
|
|
|
$
|
88
|
|
|
$
|
392
|
|
|
Year Ended December 31,
|
|||||||
|
2016
|
|
2015
|
|
2014
|
|||
Statutory rate applied to income (loss) from continuing operations before income taxes
|
(35
|
%)
|
|
(35
|
%)
|
|
35
|
%
|
Effects of foreign operations, including foreign tax credits
|
5
|
|
|
(2
|
)
|
|
(6
|
)
|
Change in permanent reinvestment assertion
|
—
|
|
|
—
|
|
|
(19
|
)
|
Adjustments to valuation allowances
|
102
|
|
|
3
|
|
|
21
|
|
Change in tax law
|
1
|
|
|
5
|
|
|
—
|
|
Goodwill impairment
|
—
|
|
|
4
|
|
|
—
|
|
Other
|
—
|
|
|
—
|
|
|
(2
|
)
|
Effective income tax expense (benefit) rate on continuing operations
|
73
|
%
|
|
(25
|
%)
|
|
29
|
%
|
|
Year Ended December 31,
|
||||||
(In millions)
|
2016
|
|
2015
|
||||
Deferred tax assets:
|
|
|
|
||||
Employee benefits
|
$
|
228
|
|
|
$
|
260
|
|
Operating loss carryforwards
|
1,065
|
|
|
563
|
|
||
Capital loss carryforwards
|
4
|
|
|
17
|
|
||
Foreign tax credits
|
4,430
|
|
|
4,335
|
|
||
Other credit carryforwards
|
35
|
|
|
35
|
|
||
Investments in subsidiaries and affiliates
|
91
|
|
|
17
|
|
||
Other
|
88
|
|
|
73
|
|
||
Valuation allowances:
|
|
|
|
||||
Federal
|
(4,166
|
)
|
|
(2,820
|
)
|
||
State, net of federal benefit
|
(53
|
)
|
|
(56
|
)
|
||
Foreign
|
(84
|
)
|
|
(162
|
)
|
||
Total deferred tax assets
|
1,638
|
|
|
2,262
|
|
||
Deferred tax liabilities:
|
|
|
|
||||
Property, plant and equipment
|
3,672
|
|
|
3,376
|
|
||
Other
|
68
|
|
|
105
|
|
||
Total deferred tax liabilities
|
3,740
|
|
|
3,481
|
|
||
Net deferred tax liabilities
|
$
|
2,102
|
|
|
$
|
1,219
|
|
|
December 31,
|
||||||
(In millions)
|
2016
|
|
2015
|
||||
Assets:
|
|
|
|
||||
Other current assets
|
$
|
—
|
|
|
$
|
—
|
|
Other noncurrent assets
|
336
|
|
|
1,222
|
|
||
Liabilities:
|
|
|
|
||||
Other current liabilities
|
—
|
|
|
—
|
|
||
Noncurrent deferred tax liabilities
|
2,438
|
|
|
2,441
|
|
||
Net deferred tax liabilities
|
$
|
2,102
|
|
|
$
|
1,219
|
|
United States
(a)
|
2008-2015
|
Canada
|
2010-2015
|
Equatorial Guinea
|
2007-2015
|
Libya
|
2012-2015
|
United Kingdom
|
2008-2015
|
(a)
|
Includes federal and state jurisdictions.
|
(In millions)
|
2016
|
|
2015
|
|
2014
|
||||||
Beginning balance
|
$
|
65
|
|
|
$
|
80
|
|
|
$
|
146
|
|
Additions for tax positions related to the current year
|
—
|
|
|
—
|
|
|
—
|
|
|||
Additions for tax positions of prior years
|
6
|
|
|
1
|
|
|
11
|
|
|||
Reductions for tax positions of prior years
|
(5
|
)
|
|
—
|
|
|
(68
|
)
|
|||
Settlements
|
—
|
|
|
(7
|
)
|
|
(9
|
)
|
|||
Statute of limitations
|
—
|
|
|
(9
|
)
|
|
—
|
|
|||
Ending balance
|
$
|
66
|
|
|
$
|
65
|
|
|
$
|
80
|
|
|
December 31,
|
||||||
(In millions)
|
2016
|
|
2015
|
||||
Crude oil, natural gas and bitumen
|
$
|
31
|
|
|
$
|
35
|
|
Supplies and other items
|
196
|
|
|
278
|
|
||
Inventories at cost
|
$
|
227
|
|
|
$
|
313
|
|
•
|
EGHoldings, in which we have a
60%
noncontrolling interest. EGHoldings is engaged in LNG production activity.
|
•
|
AMPCO, in which we have a
45%
interest. AMPCO is engaged in methanol production activity.
|
|
Ownership as of
|
|
December 31,
|
||||||
(In millions)
|
December 31, 2016
|
|
2016
|
|
2015
|
||||
EGHoldings
|
60%
|
|
$
|
550
|
|
|
$
|
603
|
|
Alba Plant LLC
|
52%
|
|
215
|
|
|
230
|
|
||
AMPCO
|
45%
|
|
165
|
|
|
169
|
|
||
Other investments
|
|
|
1
|
|
|
1
|
|
||
Total
|
|
|
$
|
931
|
|
|
$
|
1,003
|
|
(In millions)
|
2016
|
|
2015
|
|
2014
|
||||||
Income data – year:
|
|
|
|
|
|
||||||
Revenues and other income
|
$
|
770
|
|
|
$
|
769
|
|
|
$
|
1,349
|
|
Income from operations
|
346
|
|
|
313
|
|
|
826
|
|
|||
Net income
|
313
|
|
|
280
|
|
|
728
|
|
|||
Balance sheet data – December 31:
|
|
|
|
|
|
||||||
Current assets
|
$
|
525
|
|
|
$
|
467
|
|
|
|
||
Noncurrent assets
|
1,173
|
|
|
1,317
|
|
|
|
||||
Current liabilities
|
218
|
|
|
211
|
|
|
|
||||
Noncurrent liabilities
|
47
|
|
|
41
|
|
|
|
|
December 31,
|
||||||
(In millions)
|
2016
|
|
2015
|
||||
North America E&P
|
$
|
14,158
|
|
|
$
|
15,226
|
|
International E&P
|
2,470
|
|
|
2,533
|
|
||
Oil Sands Mining
|
8,991
|
|
|
9,197
|
|
||
Corporate
|
99
|
|
|
105
|
|
||
Net property, plant and equipment
|
$
|
25,718
|
|
|
$
|
27,061
|
|
|
December 31,
|
||||||||||
(In millions)
|
2016
|
|
2015
|
|
2014
|
||||||
Amounts capitalized less than one year after completion of drilling
|
$
|
131
|
|
|
$
|
352
|
|
|
$
|
484
|
|
Amounts capitalized greater than one year after completion of drilling
|
118
|
|
|
85
|
|
|
126
|
|
|||
Total deferred exploratory well costs
|
$
|
249
|
|
|
$
|
437
|
|
|
$
|
610
|
|
Number of projects with costs capitalized greater than one year after
|
|
|
|
|
|
||||||
completion of drilling
|
3
|
|
|
2
|
|
|
3
|
|
|||
|
|
||||||||||
|
|
|
|
|
|
||||||
(In millions)
|
2016
|
|
2015
|
|
2014
|
||||||
Beginning balance
|
$
|
437
|
|
|
$
|
610
|
|
|
$
|
793
|
|
Additions
|
299
|
|
|
610
|
|
|
647
|
|
|||
Charges to expense
|
(23
|
)
|
|
(148
|
)
|
|
(45
|
)
|
|||
Transfers to development
|
(388
|
)
|
|
(635
|
)
|
|
(579
|
)
|
|||
Dispositions
(a)
|
(76
|
)
|
|
—
|
|
|
(206
|
)
|
|||
Ending balance
|
$
|
249
|
|
|
$
|
437
|
|
|
$
|
610
|
|
(a)
|
Includes sale of GOM assets in 2016, and the sale of Angola assets and Norway business in 2014.
|
|
Year Ended December 31,
|
||||||||||
(in millions)
|
2016
|
|
2015
|
|
2014
|
||||||
Total impairments
|
$
|
67
|
|
|
$
|
752
|
|
|
$
|
132
|
|
•
|
2016
-
Impairments of
$67 million
consisted primarily of proved properties in Oklahoma and the Gulf of Mexico as a result of lower forecasted commodity prices and revisions to estimated abandonment costs.
|
•
|
2015
- Impairments included
$340 million
for the goodwill impairment of the North America E&P reporting unit, and
$335 million
related to proved properties (primarily in Colorado and the Gulf of Mexico) as a result of lower forecasted commodity prices, and
$44 million
associated with our disposition of natural gas assets in East Texas, North Louisiana and Wilburton, Oklahoma.
|
•
|
2014
-
Impairments of
$132 million
consisted primarily of proved properties in the Gulf of Mexico, Texas and North Dakota as a result of revisions to estimated abandonment costs and lower forecasted commodity prices.
|
|
Year Ended December 31,
|
||||||||||
(In millions)
|
2016
|
|
2015
|
|
2014
|
||||||
Exploration Expenses
|
|
|
|
|
|
||||||
Unproved property impairments
|
$
|
195
|
|
|
$
|
964
|
|
|
$
|
306
|
|
Dry well costs
|
32
|
|
|
250
|
|
|
317
|
|
|||
Geological and geophysical
|
5
|
|
|
31
|
|
|
85
|
|
|||
Other
|
98
|
|
|
73
|
|
|
85
|
|
|||
Total exploration expenses
|
$
|
330
|
|
|
$
|
1,318
|
|
|
$
|
793
|
|
•
|
2016
- Primarily a result of our decision to not drill any of our remaining Gulf of Mexico undeveloped leases and also includes certain other unproved properties in North America.
|
•
|
2015
-
Primarily due to changes in our conventional exploration strategy (Gulf of Mexico, Canadian in-situ assets and Harir block in the Kurdistan Region of Iraq), relinquishment of certain properties in the Gulf of Mexico, the operated Solomon exploration well in the Gulf of Mexico and our unproved property in Colorado as a result of the proved property impairment mentioned above.
|
•
|
2014
- Primarily consists of Eagle Ford and Bakken leases that either expired or we decided not to drill or extend.
|
•
|
2016
- Lower dry well expense as a result of the strategic decision to transition out of our conventional exploration program in the previous year.
|
•
|
2015
- Includes the operated Solomon exploration well in the Gulf of Mexico, our operated Sodalita West #1 exploratory well in E.G. and suspended well costs related our Canadian in-situ assets at Birchwood.
|
•
|
2014
- Includes the operated Key Largo well, outside-operated Perseus well and the outside-operated second Shenandoah appraisal well, all of which are located in the Gulf of Mexico. In addition, 2014 also includes our exploration programs in the Kurdistan Region of Iraq, Ethiopia and Kenya.
|
(In millions)
|
N.A. E&P
|
|
Int'l E&P
|
|
OSM
|
|
Total
|
||||||||
2015
|
|
|
|
|
|
|
|
||||||||
Beginning balance, gross
|
$
|
344
|
|
|
$
|
115
|
|
|
$
|
1,412
|
|
|
$
|
1,871
|
|
Less: accumulated impairments
|
—
|
|
|
—
|
|
|
(1,412
|
)
|
|
(1,412
|
)
|
||||
Beginning balance, net
|
344
|
|
|
115
|
|
|
—
|
|
|
459
|
|
||||
Dispositions
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
||||
Impairment
|
(340
|
)
|
|
—
|
|
|
—
|
|
|
(340
|
)
|
||||
Ending balance, net
|
$
|
—
|
|
|
$
|
115
|
|
|
$
|
—
|
|
|
$
|
115
|
|
2016
|
|
|
|
|
|
|
|
||||||||
Beginning balance, gross
|
$
|
—
|
|
|
$
|
115
|
|
|
$
|
1,412
|
|
|
$
|
1,527
|
|
Less: accumulated impairments
|
—
|
|
|
—
|
|
|
(1,412
|
)
|
|
(1,412
|
)
|
||||
Beginning balance, net
|
—
|
|
|
115
|
|
|
—
|
|
|
115
|
|
||||
Dispositions
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Impairment
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Ending balance, net
|
$
|
—
|
|
|
$
|
115
|
|
|
$
|
—
|
|
|
$
|
115
|
|
|
December 31, 2016
|
||||||||||||||
(In millions)
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
Derivative instruments, assets
|
|
|
|
|
|
|
|
||||||||
Commodity
(a)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Interest rate
|
—
|
|
|
68
|
|
|
—
|
|
|
68
|
|
||||
Derivative instruments, assets
|
$
|
—
|
|
|
$
|
68
|
|
|
$
|
—
|
|
|
$
|
68
|
|
Derivative instruments, liabilities
|
|
|
|
|
|
|
|
||||||||
Commodity
|
$
|
—
|
|
|
$
|
60
|
|
|
$
|
—
|
|
|
$
|
60
|
|
Derivative instruments, liabilities
|
$
|
—
|
|
|
$
|
60
|
|
|
$
|
—
|
|
|
$
|
60
|
|
|
|
|
|
|
|
|
|
||||||||
|
December 31, 2015
|
||||||||||||||
(In millions)
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
Derivative instruments, assets
|
|
|
|
|
|
|
|
||||||||
Commodity
(a)
|
$
|
—
|
|
|
$
|
51
|
|
|
$
|
—
|
|
|
$
|
51
|
|
Interest rate
|
$
|
—
|
|
|
$
|
8
|
|
|
$
|
—
|
|
|
$
|
8
|
|
Derivative instruments, assets
|
$
|
—
|
|
|
$
|
59
|
|
|
$
|
—
|
|
|
$
|
59
|
|
Derivative instruments, liabilities
|
|
|
|
|
|
|
|
||||||||
Commodity
(a)
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
1
|
|
Derivative instruments, liabilities
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
1
|
|
|
2016
|
|
2015
|
|
2014
|
||||||||||||||||||
(In millions)
|
Fair Value
|
|
Impairment
|
|
Fair Value
|
|
Impairment
|
|
Fair Value
|
|
Impairment
|
||||||||||||
Long-lived assets held for use
|
$
|
15
|
|
|
$
|
67
|
|
|
$
|
56
|
|
|
$
|
412
|
|
|
$
|
43
|
|
|
$
|
132
|
|
|
December 31,
|
||||||||||||||
|
2016
|
|
2015
|
||||||||||||
(In millions)
|
Fair
Value
|
|
Carrying
Amount
|
|
Fair
Value
|
|
Carrying
Amount
|
||||||||
Financial assets
|
|
|
|
|
|
|
|
||||||||
Other current assets
|
$
|
7
|
|
|
$
|
7
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Other noncurrent assets
|
119
|
|
|
121
|
|
|
104
|
|
|
118
|
|
||||
Total financial assets
|
$
|
126
|
|
|
$
|
128
|
|
|
$
|
104
|
|
|
$
|
118
|
|
Financial liabilities
|
|
|
|
|
|
|
|
||||||||
Other current liabilities
|
$
|
68
|
|
|
$
|
75
|
|
|
$
|
34
|
|
|
$
|
33
|
|
Long-term debt, including current portion
(a)
|
7,449
|
|
|
7,292
|
|
|
6,723
|
|
|
7,291
|
|
||||
Deferred credits and other liabilities
|
114
|
|
|
107
|
|
|
97
|
|
|
95
|
|
||||
Total financial liabilities
|
$
|
7,631
|
|
|
$
|
7,474
|
|
|
$
|
6,854
|
|
|
$
|
7,419
|
|
(a)
|
Excludes capital leases, debt issuance costs and interest rate swap adjustments.
|
|
December 31, 2016
|
|
|
||||||||||
(In millions)
|
Asset
|
|
Liability
|
|
Net Asset
|
|
Balance Sheet Location
|
||||||
Fair Value Hedges
|
|
|
|
|
|
|
|
|
|||||
Interest rate
|
$
|
3
|
|
|
$
|
—
|
|
|
$
|
3
|
|
|
Other current assets
|
Interest rate
|
1
|
|
|
—
|
|
|
1
|
|
|
Other noncurrent assets
|
|||
Cash Flow Hedges
|
|
|
|
|
|
|
|
||||||
Interest rate
|
$
|
64
|
|
|
$
|
—
|
|
|
$
|
64
|
|
|
Other noncurrent assets
|
Total Designated Hedges
|
$
|
68
|
|
|
$
|
—
|
|
|
$
|
68
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Not Designated as Hedges
|
|
|
|
|
|
|
|
||||||
Commodity
|
$
|
—
|
|
|
$
|
60
|
|
|
$
|
(60
|
)
|
|
Other current liabilities
|
Total Not Designated as Hedges
|
$
|
—
|
|
|
$
|
60
|
|
|
$
|
(60
|
)
|
|
|
Total
|
$
|
68
|
|
|
$
|
60
|
|
|
$
|
8
|
|
|
|
|
December 31, 2015
|
|
|
||||||||||
(In millions)
|
Asset
|
|
Liability
|
|
Net Asset
|
|
Balance Sheet Location
|
||||||
Fair Value Hedges
|
|
|
|
|
|
|
|
||||||
Interest rate
|
$
|
8
|
|
|
$
|
—
|
|
|
$
|
8
|
|
|
Other noncurrent assets
|
Total Designated Hedges
|
$
|
8
|
|
|
$
|
—
|
|
|
$
|
8
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Not Designated as Hedges
|
|
|
|
|
|
|
|
||||||
Commodity
|
$
|
51
|
|
|
$
|
1
|
|
|
$
|
50
|
|
|
Other current assets
|
Total Not Designated as Hedges
|
51
|
|
|
1
|
|
|
50
|
|
|
|
|||
Total
|
$
|
59
|
|
|
$
|
1
|
|
|
$
|
58
|
|
|
|
|
December 31, 2016
|
|
December 31, 2015
|
||||||||
|
Aggregate Notional Amount
|
Weighted Average, LIBOR-Based,
|
|
Aggregate Notional Amount
|
Weighted Average, LIBOR-Based,
|
||||||
Maturity Dates
|
(in millions)
|
Floating Rate
|
|
(in millions)
|
Floating Rate
|
||||||
October 1, 2017
|
$
|
600
|
|
5.10
|
%
|
|
$
|
600
|
|
4.73
|
%
|
March 15, 2018
|
$
|
300
|
|
5.04
|
%
|
|
$
|
300
|
|
4.66
|
%
|
|
|
Gain (Loss)
|
||||||||||
|
|
Year Ended December 31,
|
||||||||||
(In millions)
|
Income Statement Location
|
2016
|
|
2015
|
|
2014
|
||||||
Derivative
|
|
|
|
|
|
|
||||||
Interest rate
|
Net interest and other
|
$
|
(4
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
Foreign currency
|
Discontinued operations
|
—
|
|
|
—
|
|
|
(36
|
)
|
|||
Hedged Item
|
|
|
|
|
|
|
|
|
||||
Debt
|
Net interest and other
|
$
|
4
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Accrued taxes
|
Discontinued operations
|
—
|
|
|
—
|
|
|
36
|
|
|
|
December 31, 2016
|
||||
|
|
Aggregate Notional Amount
|
|
Weighted Average, LIBOR
|
||
Maturity Dates
|
|
(in millions)
|
|
Fixed Rate
|
||
March 15, 2018
|
|
$
|
750
|
|
|
1.57%
|
|
|
December 31,
|
|||||||
(In millions)
|
|
2016
|
|
2015
|
|||||
Cash Flow Hedges
|
|
|
|
|
|||||
Beginning balance
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Change in fair value recognized in accumulated other comprehensive loss
|
|
64
|
|
|
—
|
|
|||
Reclassification from other comprehensive income (loss)
|
|
(4
|
)
|
|
—
|
|
|||
Ending balance
|
|
$
|
60
|
|
|
$
|
—
|
|
Crude Oil
(a)
|
|||||||
|
2017
|
||||||
|
First Quarter
|
|
Second Quarter
|
|
Third Quarter
|
|
Fourth Quarter
|
Three-Way Collars
(b)
|
|
|
|
|
|
|
|
Volume (Bbls/day)
|
50,000
|
|
50,000
|
|
30,000
|
|
30,000
|
Price per Bbl:
|
|
|
|
|
|
|
|
Ceiling
|
$58.42
|
|
$58.42
|
|
$59.60
|
|
$59.60
|
Floor
|
$50.30
|
|
$50.30
|
|
$54.00
|
|
$54.00
|
Sold put
|
$43.50
|
|
$43.50
|
|
$47.00
|
|
$47.00
|
Sold Call Options
(c)
|
|
|
|
|
|
|
|
Volume (Bbls/day)
|
35,000
|
|
35,000
|
|
35,000
|
|
35,000
|
Price per Bbl
|
$61.91
|
|
$61.91
|
|
$61.91
|
|
$61.91
|
Natural Gas
|
|||||
|
2017
|
|
|||
|
First Quarter
|
Second Quarter
|
Third Quarter
|
Fourth Quarter
|
2018
|
Three-Way Collars
(a)
|
|
|
|
|
|
Volume (MMBtu/day)
|
60,000
|
90,000
|
90,000
|
90,000
|
20,000
|
Price per MMBtu
|
|
|
|
|
|
Ceiling
|
$3.46
|
$3.54
|
$3.54
|
$3.61
|
$3.56
|
Floor
|
$2.84
|
$3.01
|
$3.01
|
$3.04
|
$3.00
|
Sold put
|
$2.35
|
$2.48
|
$2.48
|
$2.52
|
$2.50
|
Swaps
|
|
|
|
|
|
Volume (MMBtu/day)
|
20,000
|
20,000
|
20,000
|
20,000
|
—
|
Price per MMBtu
|
$2.93
|
$2.93
|
$2.93
|
$2.93
|
$—
|
|
December 31,
|
||||||
(In millions)
|
2016
|
|
2015
|
||||
Senior unsecured notes:
|
|
|
|
||||
6.000% notes due 2017
(a)
|
682
|
|
|
682
|
|
||
5.900% notes due 2018
(a)
|
854
|
|
|
854
|
|
||
7.500% notes due 2019
(a)
|
228
|
|
|
228
|
|
||
2.700% notes due 2020
(a)
|
600
|
|
|
600
|
|
||
2.800% notes due 2022
(a)
|
1,000
|
|
|
1,000
|
|
||
9.375% notes due 2022
(b)
|
32
|
|
|
32
|
|
||
Series A notes due 2022
(b)
|
3
|
|
|
3
|
|
||
8.500% notes due 2023
(b)
|
70
|
|
|
70
|
|
||
8.125% notes due 2023
(b)
|
131
|
|
|
131
|
|
||
3.850% notes due 2025
(a)
|
900
|
|
|
900
|
|
||
6.800% notes due 2032
(a)
|
550
|
|
|
550
|
|
||
6.600% notes due 2037
(a)
|
750
|
|
|
750
|
|
||
5.200% notes due 2045
(a)
|
500
|
|
|
500
|
|
||
Capital leases:
|
|
|
|
||||
Capital lease obligation of consolidated subsidiary due 2017 – 2049
|
9
|
|
|
9
|
|
||
Other obligations:
|
|
|
|
||||
5.125% obligation relating to revenue bonds due 2037
|
1,000
|
|
|
1,000
|
|
||
Total
(b)
|
7,309
|
|
|
7,309
|
|
||
Unamortized discount
|
(9
|
)
|
|
(10
|
)
|
||
Fair value adjustments
(c)
|
7
|
|
|
17
|
|
||
Unamortized debt issuance cost
|
(35
|
)
|
|
(39
|
)
|
||
Amounts due within one year
|
(683
|
)
|
|
(1
|
)
|
||
Total long-term debt
|
$
|
6,589
|
|
|
$
|
7,276
|
|
(a)
|
These notes contain a make-whole provision allowing us to repay the debt at a premium to market price.
|
(b)
|
In the event of a change in control, as defined in the related agreements, debt obligations totaling
$236 million
at
December 31, 2016
may be declared immediately due and payable.
|
(c)
|
See Notes
15
and
16
for information on interest rate swaps.
|
|
For Year Ended December 31,
|
||||||
(In millions)
|
2016
|
|
2015
|
||||
Beginning balance
|
$
|
1,635
|
|
|
$
|
1,958
|
|
Incurred liabilities, including acquisitions
|
15
|
|
|
47
|
|
||
Settled liabilities, including dispositions
|
(74
|
)
|
|
(289
|
)
|
||
Accretion expense (included in depreciation, depletion and amortization)
|
85
|
|
|
105
|
|
||
Revisions of estimates
|
94
|
|
|
(132
|
)
|
||
Held for sale
|
(7
|
)
|
|
(54
|
)
|
||
Ending balance
|
$
|
1,748
|
|
|
$
|
1,635
|
|
•
|
Settled liabilities
include dispositions, primarily related to the Gulf of Mexico and Wyoming as well as retirements in the Gulf of Mexico.
|
•
|
Revisions of estimates
were primarily due to changes in timing of abandonment activities as well as changes in cost estimated in the U.K.
|
•
|
Ending balance
includes
$50 million
classified as short-term at
December 31, 2016
.
|
•
|
Settled liabilities
include dispositions, primarily in the Gulf of Mexico and the East Texas, North Louisiana and Wilburton, Oklahoma as well as retirements in the Gulf of Mexico and the U.K.
|
•
|
Revisions of estimates
were primarily due to changes in timing of activities in the U.K. and lower estimated costs across the assets.
|
•
|
Held for sale
is related to our Neptune field in the Gulf of Mexico.
|
•
|
Ending balance
includes
$34 million
classified as short-term at
December 31, 2015
.
|
|
Year Ended December 31,
|
||||||||||
(In millions)
|
2016
|
|
2015
|
|
2014
|
||||||
Net cash used in operating activities:
|
|
|
|
|
|
||||||
Interest paid (net of amounts capitalized)
|
$
|
(375
|
)
|
|
$
|
(325
|
)
|
|
$
|
(279
|
)
|
Income taxes paid to taxing authorities
(a)
|
(84
|
)
|
|
(171
|
)
|
|
(1,679
|
)
|
|||
Net cash provided by (used in) financing activities:
|
|
|
|
|
|
||||||
Commercial paper, net:
|
|
|
|
|
|
||||||
Issuances
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2,345
|
|
Repayments
|
—
|
|
|
—
|
|
|
(2,480
|
)
|
|||
Commercial paper, net
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(135
|
)
|
Noncash investing activities, related to continuing operations:
|
|
|
|
|
|
||||||
Asset retirement cost increase (decrease)
|
$
|
111
|
|
|
$
|
(85
|
)
|
|
$
|
151
|
|
Asset retirement obligations assumed by buyer
|
40
|
|
|
251
|
|
|
359
|
|
|||
Increase in capital expenditure accrual
|
—
|
|
|
—
|
|
|
335
|
|
(a)
|
Income taxes paid to taxing authorities includes
$1,312 million
in
2014
related to discontinued operations.
|
(a)
|
The plan amendment in 2015 was a freeze of the final average pay used in the legacy formula of the defined benefit pension plan.
|
(b)
|
Related to workforce reductions, which reduced the future expected years of service for employees participating in the plans and the impact of discontinuing accruals for future benefits under the U.K. pension plan effective December 31, 2015.
|
|
Pension Benefits
|
|
Other Benefits
|
||||||||||||||||||||||||||||||||
|
Year Ended December 31,
|
|
Year Ended December 31,
|
||||||||||||||||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
2016
|
|
2015
|
|
2014
|
||||||||||||||||||||||||
(In millions)
|
U.S.
|
|
Int’l
|
|
U.S.
|
|
Int’l
|
|
U.S.
|
|
Int’l
|
|
U.S.
|
|
U.S.
|
|
U.S.
|
||||||||||||||||||
Components of net periodic benefit cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||
Service cost
|
$
|
25
|
|
|
$
|
—
|
|
|
$
|
29
|
|
|
$
|
14
|
|
|
$
|
31
|
|
|
$
|
16
|
|
|
$
|
2
|
|
|
$
|
3
|
|
|
$
|
3
|
|
Interest cost
|
16
|
|
|
23
|
|
|
25
|
|
|
25
|
|
|
35
|
|
|
27
|
|
|
11
|
|
|
11
|
|
|
13
|
|
|||||||||
Expected return on plan assets
|
(18
|
)
|
|
(35
|
)
|
|
(30
|
)
|
|
(37
|
)
|
|
(34
|
)
|
|
(32
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||
- prior service cost (credit)
|
(10
|
)
|
|
1
|
|
|
(7
|
)
|
|
1
|
|
|
5
|
|
|
1
|
|
|
(3
|
)
|
|
(4
|
)
|
|
(6
|
)
|
|||||||||
- actuarial loss
|
14
|
|
|
—
|
|
|
22
|
|
|
2
|
|
|
29
|
|
|
1
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|||||||||
Net curtailment loss (gain)
(a)
|
—
|
|
|
—
|
|
|
(5
|
)
|
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(7
|
)
|
|
—
|
|
|||||||||
Net settlement loss
(b)
|
97
|
|
|
6
|
|
|
119
|
|
|
—
|
|
|
99
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Net periodic benefit cost
(c)
|
$
|
124
|
|
|
$
|
(5
|
)
|
|
$
|
153
|
|
|
$
|
9
|
|
|
$
|
165
|
|
|
$
|
13
|
|
|
$
|
10
|
|
|
$
|
4
|
|
|
$
|
10
|
|
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss (pretax):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||
Actuarial loss (gain)
(d)
|
$
|
70
|
|
|
$
|
41
|
|
|
$
|
30
|
|
|
$
|
(25
|
)
|
|
$
|
149
|
|
|
$
|
33
|
|
|
$
|
11
|
|
|
$
|
(21
|
)
|
|
$
|
42
|
|
Amortization of actuarial gain (loss)
|
(111
|
)
|
|
(6
|
)
|
|
(134
|
)
|
|
(2
|
)
|
|
(128
|
)
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|||||||||
Prior service cost (credit)
|
—
|
|
|
1
|
|
|
(89
|
)
|
|
1
|
|
|
—
|
|
|
—
|
|
|
(38
|
)
|
|
—
|
|
|
(42
|
)
|
|||||||||
Amortization of prior service credit (cost)
|
10
|
|
|
(1
|
)
|
|
7
|
|
|
(5
|
)
|
|
(5
|
)
|
|
(1
|
)
|
|
3
|
|
|
13
|
|
|
6
|
|
|||||||||
Total recognized in other comprehensive (income) loss
|
$
|
(31
|
)
|
|
$
|
35
|
|
|
$
|
(186
|
)
|
|
$
|
(31
|
)
|
|
$
|
16
|
|
|
$
|
31
|
|
|
$
|
(24
|
)
|
|
$
|
(9
|
)
|
|
$
|
6
|
|
Total recognized in net periodic benefit cost and other comprehensive (income) loss
|
$
|
93
|
|
|
$
|
30
|
|
|
$
|
(33
|
)
|
|
$
|
(22
|
)
|
|
$
|
181
|
|
|
$
|
44
|
|
|
$
|
(14
|
)
|
|
$
|
(5
|
)
|
|
$
|
16
|
|
(a)
|
Related to workforce reductions, which reduced the future expected years of service for employees participating in the plans and the impact of discontinuing accruals for future benefits under the U.K. pension plan effective December 31, 2015.
|
(b)
|
Settlement losses are recorded when lump sum payments from a plan in a period exceed the plan’s total service and interest costs for the period.
|
(c)
|
Net periodic benefit cost reflects a calculated market-related value of plan assets which recognizes changes in fair value over three years.
|
(d)
|
Activity in 2014 includes the impact of the sale of our Norway business in the fourth quarter of 2014.
|
|
Pension Benefits
|
|
Other Benefits
|
|||||||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
2016
|
|
2015
|
|
2014
|
|||||||||||||||
(In millions)
|
U.S.
|
|
Int’l
|
|
U.S.
|
|
Int’l
|
|
U.S.
|
|
Int’l
|
|
U.S.
|
|
U.S.
|
|
U.S.
|
|||||||||
Weighted average assumptions used to determine benefit obligation:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Discount rate
|
4.02
|
%
|
|
2.70
|
%
|
|
4.04
|
%
|
|
3.90
|
%
|
|
3.71
|
%
|
|
3.70
|
%
|
|
3.98
|
%
|
|
4.36
|
%
|
|
4.01
|
%
|
Rate of compensation increase
(a)
|
4.00
|
%
|
|
—
|
|
|
4.00
|
%
|
|
—
|
|
|
4.00
|
%
|
|
3.60
|
%
|
|
4.00
|
%
|
|
4.00
|
%
|
|
4.00
|
%
|
Weighted average assumptions used to determine net periodic benefit cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Discount rate
|
3.66
|
%
|
|
3.90
|
%
|
|
3.79
|
%
|
|
3.70
|
%
|
|
3.98
|
%
|
|
4.60
|
%
|
|
4.36
|
%
|
|
3.93
|
%
|
|
4.69
|
%
|
Expected long-term return on plan assets
|
6.75
|
%
|
|
5.50
|
%
|
|
6.75
|
%
|
|
5.70
|
%
|
|
6.75
|
%
|
|
5.70
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
Rate of compensation increase
(a)
|
4.00
|
%
|
|
—
|
|
|
4.00
|
%
|
|
3.60
|
%
|
|
5.00
|
%
|
|
4.90
|
%
|
|
4.00
|
%
|
|
4.00
|
%
|
|
5.00
|
%
|
(a)
|
No future benefits will be incurred for the U.K. plan after December 31, 2015. Therefore, rate of compensation increase is no longer applicable to this plan.
|
|
December 31, 2016
|
||||||||||||||||||||||||||||||
(In millions)
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||||||||||||||||||
|
U.S.
|
|
Int’l
|
|
U.S.
|
|
Int’l
|
|
U.S.
|
|
Int’l
|
|
U.S.
|
|
Int’l
|
||||||||||||||||
Cash and cash equivalents
|
$
|
8
|
|
|
$
|
5
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
8
|
|
|
$
|
5
|
|
Equity securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Common and preferred stock
|
82
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
82
|
|
|
—
|
|
||||||||
REIT and private equity
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
20
|
|
|
—
|
|
|
20
|
|
|
—
|
|
||||||||
Mutual and pooled funds
|
—
|
|
|
201
|
|
|
—
|
|
|
159
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
360
|
|
||||||||
Fixed income securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
U.S. treasury notes and ETFs
|
11
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11
|
|
|
—
|
|
||||||||
Corporate and other bonds
|
—
|
|
|
—
|
|
|
60
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
60
|
|
|
—
|
|
||||||||
Pooled funds
|
—
|
|
|
—
|
|
|
11
|
|
|
230
|
|
|
—
|
|
|
—
|
|
|
11
|
|
|
230
|
|
||||||||
REIT and swaps
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Other
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
21
|
|
|
—
|
|
|
21
|
|
|
—
|
|
||||||||
Total investments, at fair value
|
101
|
|
|
206
|
|
|
71
|
|
|
389
|
|
|
41
|
|
|
—
|
|
|
213
|
|
|
595
|
|
||||||||
Commingled funds
(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
14
|
|
|
—
|
|
||||||||||||||
Total investments
|
$
|
101
|
|
|
$
|
206
|
|
|
$
|
71
|
|
|
$
|
389
|
|
|
$
|
41
|
|
|
$
|
—
|
|
|
$
|
227
|
|
|
$
|
595
|
|
|
December 31, 2015
|
||||||||||||||||||||||||||||||
(In millions)
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||||||||||||||||||
|
U.S.
|
|
Int’l
|
|
U.S.
|
|
Int’l
|
|
U.S.
|
|
Int’l
|
|
U.S.
|
|
Int’l
|
||||||||||||||||
Cash and cash equivalents
|
$
|
47
|
|
|
$
|
6
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
48
|
|
|
$
|
6
|
|
Equity securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Common and preferred stock
|
115
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
115
|
|
|
—
|
|
||||||||
REIT and private equity
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
23
|
|
|
—
|
|
|
24
|
|
|
—
|
|
||||||||
Mutual and pooled funds
|
—
|
|
|
218
|
|
|
—
|
|
|
152
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
370
|
|
||||||||
Fixed income securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
U.S. treasury notes and ETFs
|
12
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
12
|
|
|
—
|
|
||||||||
Corporate and other bonds
|
—
|
|
|
—
|
|
|
105
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
105
|
|
|
—
|
|
||||||||
Pooled funds
|
—
|
|
|
—
|
|
|
—
|
|
|
232
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
232
|
|
||||||||
REIT and Swaps
|
—
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
—
|
|
||||||||
Other
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
25
|
|
|
—
|
|
|
25
|
|
|
—
|
|
||||||||
Total investments, at fair value
|
175
|
|
|
224
|
|
|
108
|
|
|
384
|
|
|
48
|
|
|
—
|
|
|
331
|
|
|
608
|
|
||||||||
Commingled funds
(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
23
|
|
|
—
|
|
||||||||||||||
Total investments
|
$
|
175
|
|
|
$
|
224
|
|
|
$
|
108
|
|
|
$
|
384
|
|
|
$
|
48
|
|
|
$
|
—
|
|
|
$
|
354
|
|
|
$
|
608
|
|
(a)
|
After the adoption of the FASB update for the fair value hierarchy, we separately report the investments for which fair value was measured using the net asset value per share as a practical expedient. Amounts presented in this table are intended to reconcile the fair value hierarchy to the pension plan assets. See Note 2 for further information on the FASB update.
|
|
Pension Benefits
|
|
Other Benefits
|
||||||||
(In millions)
|
U.S.
|
|
Int’l
|
|
U.S.
|
||||||
2017
|
$
|
34
|
|
|
$
|
17
|
|
|
$
|
21
|
|
2018
|
35
|
|
|
17
|
|
|
21
|
|
|||
2019
|
34
|
|
|
18
|
|
|
20
|
|
|||
2020
|
35
|
|
|
18
|
|
|
19
|
|
|||
2021
|
34
|
|
|
20
|
|
|
19
|
|
|||
2022 through 2025
|
163
|
|
|
116
|
|
|
78
|
|
|
2016
|
|
2015
|
|
2014
|
|||
Exercise price per share
|
$7.22
|
|
$29.06
|
|
$34.49
|
|||
Expected annual dividend yield
|
2.8
|
%
|
|
2.9
|
%
|
|
2.3
|
%
|
Expected life in years
|
6.3
|
|
|
6.2
|
|
|
5.9
|
|
Expected volatility
|
36
|
%
|
|
32
|
%
|
|
38
|
%
|
Risk-free interest rate
|
1.4
|
%
|
|
1.7
|
%
|
|
1.8
|
%
|
Weighted average grant date fair value of stock option awards granted
|
$1.97
|
|
$6.84
|
|
$10.50
|
|
Number
|
|
Weighted Average
|
|
Weighted Average
Remaining
|
|
Average Intrinsic Value
|
|||
|
of Shares
|
|
Exercise Price
|
|
Contractual Term
|
|
(in millions)
|
|||
Outstanding at beginning of year
|
12,665,419
|
|
$29.97
|
|
|
|
|
|||
Granted
|
1,680,000
|
|
$7.22
|
|
|
|
|
|||
Exercised
|
(46,191)
|
|
$17.44
|
|
|
|
|
|||
Canceled
|
(2,383,695)
|
|
$25.47
|
|
|
|
|
|||
Outstanding at end of year
|
11,915,533
|
|
$27.71
|
|
4 years
|
|
$
|
—
|
|
|
Exercisable at end of year
|
9,856,556
|
|
|
$30.15
|
|
3 years
|
|
$
|
—
|
|
Expected to vest
|
2,051,140
|
|
|
$16.05
|
|
9 years
|
|
$
|
—
|
|
|
Awards
|
|
Weighted Average
Grant Date
Fair Value
|
|
Unvested at beginning of year
|
4,017,344
|
|
|
$30.76
|
Granted
|
5,725,655
|
|
|
$8.57
|
Vested & Exercised
|
(1,498,431
|
)
|
|
$31.67
|
Canceled
|
(1,311,035
|
)
|
|
$19.13
|
Unvested at end of year
|
6,933,533
|
|
|
$14.44
|
|
2016
|
|
2015
|
|
2014
(a)
|
||
Valuation date stock price
|
$17.31
|
|
$17.31
|
|
n/a
|
||
Expected annual dividend yield
|
1.1
|
%
|
|
1.1
|
%
|
|
n/a
|
Expected volatility
|
58
|
%
|
|
68
|
%
|
|
n/a
|
Risk-free interest rate
|
1.3
|
%
|
|
0.9
|
%
|
|
n/a
|
Fair value of stock-based performance units outstanding
|
$19.37
|
|
$11.17
|
|
n/a
|
(In millions)
|
Capital Lease Obligations
|
|
Operating Lease Obligations
|
||||
2017
|
$
|
2
|
|
|
$
|
28
|
|
2018
|
1
|
|
|
28
|
|
||
2019
|
1
|
|
|
27
|
|
||
2020
|
1
|
|
|
27
|
|
||
2021
|
1
|
|
|
26
|
|
||
Later years
|
15
|
|
|
19
|
|
||
Sublease rentals
|
—
|
|
|
—
|
|
||
Total minimum lease payments
|
$
|
21
|
|
|
$
|
155
|
|
Less imputed interest costs
|
(12
|
)
|
|
|
|||
Present value of net minimum lease payments
|
$
|
9
|
|
|
|
|
2016
|
|
2015
|
||||||||||||||||||||||||||||
(In millions, except per share data)
|
1st Qtr.
|
|
2nd Qtr.
|
|
3rd Qtr.
|
|
4th Qtr.
|
|
1st Qtr.
|
|
2nd Qtr.
|
|
3rd Qtr.
|
|
4th Qtr.
|
||||||||||||||||
Revenues
|
$
|
772
|
|
|
$
|
959
|
|
|
$
|
1,100
|
|
|
$
|
1,200
|
|
|
$
|
1,484
|
|
|
$
|
1,490
|
|
|
$
|
1,384
|
|
|
$
|
1,164
|
|
Income (loss) before income taxes
(a)
|
(683
|
)
|
|
(238
|
)
|
|
(290
|
)
|
|
(24
|
)
|
|
(420
|
)
|
|
(392
|
)
|
|
(1,145
|
)
|
|
(1,001
|
)
|
||||||||
Net income (loss)
(b)
|
$
|
(407
|
)
|
|
$
|
(170
|
)
|
|
$
|
(192
|
)
|
|
$
|
(1,371
|
)
|
|
$
|
(276
|
)
|
|
$
|
(386
|
)
|
|
$
|
(749
|
)
|
|
$
|
(793
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Basic net income (loss) per share
|
($0.56)
|
|
($0.20)
|
|
($0.23)
|
|
($1.62)
|
|
($0.41)
|
|
($0.57)
|
|
($1.11)
|
|
($1.17)
|
||||||||||||||||
Diluted net income (loss) per share
|
($0.56)
|
|
($0.20)
|
|
($0.23)
|
|
($1.62)
|
|
($0.41)
|
|
($0.57)
|
|
($1.11)
|
|
($1.17)
|
||||||||||||||||
Dividends paid per share
|
$0.05
|
|
$0.05
|
|
$0.05
|
|
$0.05
|
|
$0.21
|
|
$0.21
|
|
$0.21
|
|
$0.05
|
(a)
|
Includes impairments to producing properties of
$47 million
in the third quarter of 2016,
$28 million
in the 4th quarter of 2015,
$333 million
in the third quarter of 2015, and
$44 million
in the second quarter of 2015. Also includes unproved property impairments of
$118 million
in the second quarter of 2016,
$302 million
in the fourth quarter of 2015, and
$553 million
in the third quarter of 2015 (see Item 8. Financial Statements and Supplementary Data – Note
13
to the consolidated financial statements). Includes a goodwill impairment of
$340 million
in 2015 related to the N.A. E&P reporting unit. (see Item 8. Financial Statements and Supplementary Data – Note
14
to the consolidated financial statements).
|
(b)
|
Includes the increase of a valuation allowance on certain of our deferred tax assets for
$1,346 million
in the fourth quarter of 2016 (see Item 8. Financial Statements and Supplementary Data – Note 9 to the consolidated financial statements).
|
|
SEC Pricing 2016
|
||
WTI Crude oil
(per bbl)
|
$
|
42.75
|
|
Henry Hub natural gas
(per mmbtu)
|
$
|
2.49
|
|
Brent crude oil
(per bbl)
|
$
|
43.53
|
|
Mont Belvieu NGLs
(per bbl)
|
$
|
15.89
|
|
(mmbbl)
|
U.S.
|
|
Canada
|
|
E.G.
(a)
|
|
Other
Africa
|
|
Other Int'l
|
|
Cont Ops
|
|
Disc Ops
|
|
Total
|
||||||||
Crude oil and condensate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Proved developed and undeveloped reserves:
|
|||||||||||||||||||||||
Beginning of year - 2014
|
497
|
|
|
—
|
|
|
64
|
|
|
215
|
|
|
25
|
|
|
801
|
|
|
91
|
|
|
892
|
|
Revisions of previous estimates
|
36
|
|
|
—
|
|
|
(1
|
)
|
|
(4
|
)
|
|
1
|
|
|
32
|
|
|
10
|
|
|
42
|
|
Improved recovery
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
2
|
|
Purchases of reserves in place
|
6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6
|
|
|
—
|
|
|
6
|
|
Extensions, discoveries and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
other additions
|
153
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
7
|
|
|
161
|
|
|
3
|
|
|
164
|
|
Production
|
(57
|
)
|
|
—
|
|
|
(7
|
)
|
|
(3
|
)
|
|
(4
|
)
|
|
(71
|
)
|
|
(17
|
)
|
|
(88
|
)
|
Sales of reserves in place
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3
|
)
|
|
(87
|
)
|
|
(90
|
)
|
End of year - 2014
|
634
|
|
|
—
|
|
|
57
|
|
|
208
|
|
|
29
|
|
|
928
|
|
|
—
|
|
|
928
|
|
Revisions of previous estimates
|
(109
|
)
|
|
—
|
|
|
2
|
|
|
(7
|
)
|
|
(2
|
)
|
|
(116
|
)
|
|
—
|
|
|
(116
|
)
|
Improved recovery
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
Purchases of reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Extensions, discoveries and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
other additions
|
122
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
122
|
|
|
—
|
|
|
122
|
|
Production
|
(62
|
)
|
|
—
|
|
|
(7
|
)
|
|
—
|
|
|
(5
|
)
|
|
(74
|
)
|
|
—
|
|
|
(74
|
)
|
Sales of reserves in place
|
(6
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6
|
)
|
|
—
|
|
|
(6
|
)
|
End of year - 2015
|
580
|
|
|
—
|
|
|
52
|
|
|
201
|
|
|
22
|
|
|
855
|
|
|
—
|
|
|
855
|
|
Revisions of previous estimates
|
(97
|
)
|
|
—
|
|
|
1
|
|
|
(28
|
)
|
|
3
|
|
|
(121
|
)
|
|
—
|
|
|
(121
|
)
|
Improved recovery
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
—
|
|
|
4
|
|
Purchases of reserves in place
|
12
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
12
|
|
|
—
|
|
|
12
|
|
Extensions, discoveries and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
other additions
|
189
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
190
|
|
|
—
|
|
|
190
|
|
Production
|
(48
|
)
|
|
—
|
|
|
(8
|
)
|
|
(1
|
)
|
|
(4
|
)
|
|
(61
|
)
|
|
—
|
|
|
(61
|
)
|
Sales of reserves in place
|
(77
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(77
|
)
|
|
—
|
|
|
(77
|
)
|
End of year - 2016
|
563
|
|
|
—
|
|
|
45
|
|
|
172
|
|
|
22
|
|
|
802
|
|
|
—
|
|
|
802
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Beginning of year - 2014
|
241
|
|
|
—
|
|
|
37
|
|
|
176
|
|
|
19
|
|
|
473
|
|
|
77
|
|
|
550
|
|
End of year - 2014
|
294
|
|
|
—
|
|
|
30
|
|
|
175
|
|
|
19
|
|
|
518
|
|
|
—
|
|
|
518
|
|
End of year - 2015
|
327
|
|
|
—
|
|
|
25
|
|
|
173
|
|
|
16
|
|
|
541
|
|
|
—
|
|
|
541
|
|
End of year - 2016
|
238
|
|
|
—
|
|
|
45
|
|
|
172
|
|
|
13
|
|
|
468
|
|
|
—
|
|
|
468
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Beginning of year - 2014
|
256
|
|
|
—
|
|
|
27
|
|
|
39
|
|
|
6
|
|
|
328
|
|
|
14
|
|
|
342
|
|
End of year - 2014
|
340
|
|
|
—
|
|
|
27
|
|
|
33
|
|
|
10
|
|
|
410
|
|
|
—
|
|
|
410
|
|
End of year - 2015
|
253
|
|
|
—
|
|
|
27
|
|
|
28
|
|
|
6
|
|
|
314
|
|
|
—
|
|
|
314
|
|
End of year - 2016
|
325
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9
|
|
|
334
|
|
|
—
|
|
|
334
|
|
(mmbbl)
|
U.S.
|
|
Canada
|
|
E.G.
(a)
|
|
Other
Africa
|
|
Other Int'l
|
|
Cont Ops
|
|
Disc Ops
|
|
Total
|
||||||||
Natural gas liquids
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Proved developed and undeveloped reserves:
|
|||||||||||||||||||||||
Beginning of year - 2014
|
119
|
|
|
—
|
|
|
34
|
|
|
—
|
|
|
1
|
|
|
154
|
|
|
—
|
|
|
154
|
|
Revisions of previous estimates
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
—
|
|
|
4
|
|
Improved recovery
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Purchases of reserves in place
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
Extensions, discoveries and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
other additions
|
48
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
48
|
|
|
—
|
|
|
48
|
|
Production
|
(11
|
)
|
|
—
|
|
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
(15
|
)
|
|
—
|
|
|
(15
|
)
|
Sales of reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
End of year - 2014
|
161
|
|
|
—
|
|
|
30
|
|
|
—
|
|
|
1
|
|
|
192
|
|
|
—
|
|
|
192
|
|
Revisions of previous estimates
|
(31
|
)
|
|
—
|
|
|
2
|
|
|
—
|
|
|
(1
|
)
|
|
(30
|
)
|
|
—
|
|
|
(30
|
)
|
Improved recovery
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Purchases of reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Extensions, discoveries and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
other additions
|
57
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
57
|
|
|
—
|
|
|
57
|
|
Production
|
(14
|
)
|
|
—
|
|
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
(18
|
)
|
|
—
|
|
|
(18
|
)
|
Sales of reserves in place
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
End of year - 2015
|
172
|
|
|
—
|
|
|
28
|
|
|
—
|
|
|
—
|
|
|
200
|
|
|
—
|
|
|
200
|
|
Revisions of previous estimates
|
(51
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(51
|
)
|
|
—
|
|
|
(51
|
)
|
Improved recovery
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Purchases of reserves in place
|
12
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
12
|
|
|
—
|
|
|
12
|
|
Extensions, discoveries and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
other additions
|
54
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
54
|
|
|
—
|
|
|
54
|
|
Production
|
(14
|
)
|
|
—
|
|
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
(18
|
)
|
|
—
|
|
|
(18
|
)
|
Sales of reserves in place
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3
|
)
|
|
—
|
|
|
(3
|
)
|
End of year - 2016
|
170
|
|
|
—
|
|
|
24
|
|
|
—
|
|
|
—
|
|
|
194
|
|
|
—
|
|
|
194
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Beginning of year - 2014
|
51
|
|
|
—
|
|
|
18
|
|
|
—
|
|
|
1
|
|
|
70
|
|
|
—
|
|
|
70
|
|
End of year - 2014
|
68
|
|
|
—
|
|
|
15
|
|
|
—
|
|
|
—
|
|
|
83
|
|
|
—
|
|
|
83
|
|
End of year - 2015
|
92
|
|
|
—
|
|
|
12
|
|
|
—
|
|
|
—
|
|
|
104
|
|
|
—
|
|
|
104
|
|
End of year - 2016
|
78
|
|
|
—
|
|
|
24
|
|
|
—
|
|
|
—
|
|
|
102
|
|
|
—
|
|
|
102
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Beginning of year - 2014
|
68
|
|
|
—
|
|
|
16
|
|
|
—
|
|
|
—
|
|
|
84
|
|
|
—
|
|
|
84
|
|
End of year - 2014
|
93
|
|
|
—
|
|
|
15
|
|
|
—
|
|
|
1
|
|
|
109
|
|
|
—
|
|
|
109
|
|
End of year - 2015
|
80
|
|
|
—
|
|
|
16
|
|
|
—
|
|
|
—
|
|
|
96
|
|
|
—
|
|
|
96
|
|
End of year - 2016
|
92
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
92
|
|
|
—
|
|
|
92
|
|
(bcf)
|
U.S.
|
|
Canada
|
|
E.G.
(a)
|
|
Other
Africa
|
|
Other Int'l
|
|
Cont Ops
|
|
Disc Ops
|
|
Total
|
||||||||
Natural gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Proved developed and undeveloped reserves:
|
|||||||||||||||||||||||
Beginning of year - 2014
|
1,025
|
|
|
—
|
|
|
1,320
|
|
|
205
|
|
|
28
|
|
|
2,578
|
|
|
93
|
|
|
2,671
|
|
Revisions of previous estimates
|
(24
|
)
|
|
—
|
|
|
1
|
|
|
5
|
|
|
2
|
|
|
(16
|
)
|
|
7
|
|
|
(9
|
)
|
Improved recovery
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Purchases of reserves in place
|
5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|
—
|
|
|
5
|
|
Extensions, discoveries and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
other additions
|
290
|
|
|
—
|
|
|
44
|
|
|
—
|
|
|
—
|
|
|
334
|
|
|
2
|
|
|
336
|
|
Production
(b)
|
(113
|
)
|
|
—
|
|
|
(160
|
)
|
|
(1
|
)
|
|
(8
|
)
|
|
(282
|
)
|
|
(13
|
)
|
|
(295
|
)
|
Sales of reserves in place
|
(39
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(39
|
)
|
|
(89
|
)
|
|
(128
|
)
|
End of year - 2014
|
1,144
|
|
|
—
|
|
|
1,205
|
|
|
209
|
|
|
22
|
|
|
2,580
|
|
|
—
|
|
|
2,580
|
|
Revisions of previous estimates
|
(191
|
)
|
|
—
|
|
|
35
|
|
|
(3
|
)
|
|
1
|
|
|
(158
|
)
|
|
—
|
|
|
(158
|
)
|
Improved recovery
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Purchases of reserves in place
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
Extensions, discoveries and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
other additions
|
394
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
394
|
|
|
—
|
|
|
394
|
|
Production
(b)
|
(128
|
)
|
|
—
|
|
|
(150
|
)
|
|
—
|
|
|
(8
|
)
|
|
(286
|
)
|
|
—
|
|
|
(286
|
)
|
Sales of reserves in place
|
(69
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(69
|
)
|
|
—
|
|
|
(69
|
)
|
End of year - 2015
|
1,151
|
|
|
—
|
|
|
1,090
|
|
|
206
|
|
|
15
|
|
|
2,462
|
|
|
—
|
|
|
2,462
|
|
Revisions of previous estimates
|
(146
|
)
|
|
—
|
|
|
8
|
|
|
(1
|
)
|
|
3
|
|
|
(136
|
)
|
|
—
|
|
|
(136
|
)
|
Improved recovery
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Purchases of reserves in place
|
61
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
61
|
|
|
—
|
|
|
61
|
|
Extensions, discoveries and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
other additions
|
362
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
362
|
|
|
—
|
|
|
362
|
|
Production
(b)
|
(115
|
)
|
|
—
|
|
|
(155
|
)
|
|
—
|
|
|
(8
|
)
|
|
(278
|
)
|
|
—
|
|
|
(278
|
)
|
Sales of reserves in place
|
(25
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(25
|
)
|
|
—
|
|
|
(25
|
)
|
End of year - 2016
|
1,288
|
|
|
—
|
|
|
943
|
|
|
205
|
|
|
10
|
|
|
2,446
|
|
|
—
|
|
|
2,446
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Beginning of year - 2014
|
540
|
|
|
—
|
|
|
823
|
|
|
95
|
|
|
21
|
|
|
1,479
|
|
|
20
|
|
|
1,499
|
|
End of year - 2014
|
575
|
|
|
—
|
|
|
664
|
|
|
94
|
|
|
17
|
|
|
1,350
|
|
|
—
|
|
|
1,350
|
|
End of year - 2015
|
640
|
|
|
—
|
|
|
552
|
|
|
94
|
|
|
11
|
|
|
1,297
|
|
|
—
|
|
|
1,297
|
|
End of year - 2016
|
648
|
|
|
—
|
|
|
943
|
|
|
95
|
|
|
5
|
|
|
1,691
|
|
|
—
|
|
|
1,691
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Beginning of year - 2014
|
485
|
|
|
—
|
|
|
497
|
|
|
110
|
|
|
7
|
|
|
1,099
|
|
|
73
|
|
|
1,172
|
|
End of year - 2014
|
569
|
|
|
—
|
|
|
541
|
|
|
115
|
|
|
5
|
|
|
1,230
|
|
|
—
|
|
|
1,230
|
|
End of year - 2015
|
511
|
|
|
—
|
|
|
538
|
|
|
112
|
|
|
4
|
|
|
1,165
|
|
|
—
|
|
|
1,165
|
|
End of year - 2016
|
640
|
|
|
—
|
|
|
—
|
|
|
110
|
|
|
5
|
|
|
755
|
|
|
—
|
|
|
755
|
|
(mmbbl)
|
U.S.
|
|
Canada
|
|
E.G.
(a)
|
|
Other
Africa
|
|
Other Int'l
|
|
Cont Ops
|
|
Disc Ops
|
|
Total
|
||||||||
Synthetic crude oil
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Proved developed and undeveloped reserves:
|
|||||||||||||||||||||||
Beginning of year - 2014
|
—
|
|
|
680
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
680
|
|
|
—
|
|
|
680
|
|
Revisions of previous estimates
|
—
|
|
|
(55
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(55
|
)
|
|
—
|
|
|
(55
|
)
|
Improved recovery
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Purchases of reserves in place
|
—
|
|
|
38
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
38
|
|
|
—
|
|
|
38
|
|
Extensions, discoveries and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
other additions
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Production
|
—
|
|
|
(15
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(15
|
)
|
|
—
|
|
|
(15
|
)
|
Sales of reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
End of year - 2014
|
—
|
|
|
648
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
648
|
|
|
—
|
|
|
648
|
|
Revisions of previous estimates
|
—
|
|
|
67
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
67
|
|
|
—
|
|
|
67
|
|
Improved recovery
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Purchases of reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Extensions, discoveries and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
other additions
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Production
|
—
|
|
|
(17
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(17
|
)
|
|
—
|
|
|
(17
|
)
|
Sales of reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
End of year - 2015
|
—
|
|
|
698
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
698
|
|
|
—
|
|
|
698
|
|
Revisions of previous estimates
|
—
|
|
|
12
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
12
|
|
|
—
|
|
|
12
|
|
Improved recovery
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Purchases of reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Extensions, discoveries and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
—
|
|
|||||||
other additions
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
—
|
|
|
—
|
|
||
Production
|
—
|
|
|
(18
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(18
|
)
|
|
—
|
|
|
(18
|
)
|
Sales of reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
End of year - 2016
|
—
|
|
|
692
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
692
|
|
|
—
|
|
|
692
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Beginning of year - 2014
|
—
|
|
|
674
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
674
|
|
|
—
|
|
|
674
|
|
End of year - 2014
|
—
|
|
|
644
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
644
|
|
|
—
|
|
|
644
|
|
End of year - 2015
|
—
|
|
|
698
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
698
|
|
|
—
|
|
|
698
|
|
End of year - 2016
|
—
|
|
|
692
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
692
|
|
|
—
|
|
|
692
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Beginning of year - 2014
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
End of year - 2014
|
—
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
—
|
|
|
4
|
|
End of year - 2015
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
End of year - 2016
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
(mmboe)
|
U.S.
|
|
Canada
|
|
E.G.
(a)
|
|
Other
Africa
|
|
Other Int'l
|
|
Cont Ops
|
|
Disc Ops
|
|
Total
|
||||||||
Total Proved Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Proved developed and undeveloped reserves:
|
|||||||||||||||||||||||
Beginning of year - 2014
|
787
|
|
|
680
|
|
|
318
|
|
|
249
|
|
|
31
|
|
|
2,065
|
|
|
106
|
|
|
2,171
|
|
Revisions of previous estimates
|
36
|
|
|
(55
|
)
|
|
—
|
|
|
(3
|
)
|
|
—
|
|
|
(22
|
)
|
|
11
|
|
|
(11
|
)
|
Improved recovery
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
2
|
|
Purchases of reserves in place
|
8
|
|
|
38
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
46
|
|
|
—
|
|
|
46
|
|
Extensions, discoveries and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
other additions
|
250
|
|
|
—
|
|
|
8
|
|
|
—
|
|
|
7
|
|
|
265
|
|
|
3
|
|
|
268
|
|
Production
(b)
|
(87
|
)
|
|
(15
|
)
|
|
(38
|
)
|
|
(3
|
)
|
|
(5
|
)
|
|
(148
|
)
|
|
(19
|
)
|
|
(167
|
)
|
Sales of reserves in place
|
(10
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
(10
|
)
|
|
(101
|
)
|
|
(111
|
)
|
|
End of year - 2014
|
986
|
|
|
648
|
|
|
288
|
|
|
243
|
|
|
33
|
|
|
2,198
|
|
|
—
|
|
|
2,198
|
|
Revisions of previous estimates
|
(173
|
)
|
|
67
|
|
|
8
|
|
|
(8
|
)
|
|
(2
|
)
|
|
(108
|
)
|
|
—
|
|
|
(108
|
)
|
Improved recovery
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
Purchases of reserves in place
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
Extensions, discoveries and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
—
|
|
|||||
other additions
|
245
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
246
|
|
|
—
|
|
|
246
|
|
Production
(b)
|
(98
|
)
|
|
(17
|
)
|
|
(36
|
)
|
|
—
|
|
|
(6
|
)
|
|
(157
|
)
|
|
—
|
|
|
(157
|
)
|
Sales of reserves in place
|
(18
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(18
|
)
|
|
—
|
|
|
(18
|
)
|
End of year - 2015
|
944
|
|
|
698
|
|
|
261
|
|
|
235
|
|
|
25
|
|
|
2,163
|
|
|
—
|
|
|
2,163
|
|
Revisions of previous estimates
|
(171
|
)
|
|
12
|
|
|
2
|
|
|
(28
|
)
|
|
4
|
|
|
(181
|
)
|
|
—
|
|
|
(181
|
)
|
Improved recovery
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
—
|
|
|
4
|
|
Purchases of reserves in place
|
34
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
34
|
|
|
—
|
|
|
34
|
|
Extensions, discoveries and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
other additions
|
303
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
304
|
|
|
—
|
|
|
304
|
|
Production
(b)
|
(82
|
)
|
|
(18
|
)
|
|
(37
|
)
|
|
(1
|
)
|
|
(6
|
)
|
|
(144
|
)
|
|
—
|
|
|
(144
|
)
|
Sales of reserves in place
|
(84
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(84
|
)
|
|
—
|
|
|
(84
|
)
|
End of year - 2016
|
948
|
|
|
692
|
|
|
226
|
|
|
206
|
|
|
24
|
|
|
2,096
|
|
|
—
|
|
|
2,096
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Beginning of year - 2014
|
382
|
|
|
674
|
|
|
193
|
|
|
192
|
|
|
23
|
|
|
1,464
|
|
|
80
|
|
|
1,544
|
|
End of year - 2014
|
458
|
|
|
644
|
|
|
155
|
|
|
191
|
|
|
22
|
|
|
1,470
|
|
|
—
|
|
|
1,470
|
|
End of year - 2015
|
526
|
|
|
698
|
|
|
129
|
|
|
189
|
|
|
18
|
|
|
1,560
|
|
|
—
|
|
|
1,560
|
|
End of year - 2016
|
424
|
|
|
692
|
|
|
226
|
|
|
188
|
|
|
14
|
|
|
1,544
|
|
|
—
|
|
|
1,544
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Beginning of year - 2014
|
405
|
|
|
6
|
|
|
125
|
|
|
57
|
|
|
8
|
|
|
601
|
|
|
26
|
|
|
627
|
|
End of year - 2014
|
528
|
|
|
4
|
|
|
133
|
|
|
52
|
|
|
11
|
|
|
728
|
|
|
—
|
|
|
728
|
|
End of year - 2015
|
418
|
|
|
—
|
|
|
132
|
|
|
46
|
|
|
7
|
|
|
603
|
|
|
—
|
|
|
603
|
|
End of year - 2016
|
524
|
|
|
—
|
|
|
—
|
|
|
18
|
|
|
10
|
|
|
552
|
|
|
—
|
|
|
552
|
|
(a)
|
Consists of estimated reserves from properties governed by production sharing contracts.
|
(b)
|
Excludes the resale of purchased natural gas used in reservoir management.
|
•
|
Revisions of previous estimates:
Decrease of 181 mmboe due primarily to 93 mmboe of revision associated with the deferral of lower economic value wells in the U.S. unconventional resource plays outside of the 5-year plan and a decrease of 64 mmboe due to U.S. technical reevaluations.
|
•
|
Extensions, discoveries, and other additions:
Increased by 308 mmboe primarily in our U.S unconventional resource plays associated with the acceleration of higher economic wells into the 5-year plan, the expansion of proved areas in Oklahoma, and new wells to sales from unproved categories.
|
•
|
Purchases of reserves in place:
Acquisition of STACK assets in Oklahoma.
|
•
|
Production:
Decrease of 144 mmboe.
|
•
|
Sales of reserves in place:
Decrease of 84 mmboe associated with the divestitures of our Wyoming and certain Gulf of Mexico assets. See Item 8. Financial Statements and Supplementary Data - Note
6
to the consolidated financial statements for information regarding these dispositions.
|
•
|
Revisions of previous estimates:
Decrease of 173 mmboe which was largely due to reductions to our capital development program and adherence to the SEC 5-year rule and partially offset by a positive revision of 67 mmboe in OSM due to technical reevaluation and lower royalty percentages related to lower realized prices. Royalties paid in Canada are determined on a progressive scale; as the sales price of our synthetic crude oil rises, the royalty rate rises as well.
|
•
|
Extensions, discoveries, and other additions:
Increased 245 mmboe as a result of drilling programs in our U.S. resource plays.
|
•
|
Production:
Decrease of 157 mmboe.
|
•
|
Sales of reserves in place:
U.S. conventional assets sales contributed to a decrease of 18 mmboe.
|
•
|
Revisions of previous estimates:
Negative revisions of 55 mmboe to OSM synthetic crude oil reserves were impacted by technical changes, calculation of estimated royalty volumes, and development plan changes in mineable areas. This downward revision was offset by positive revisions from U.S. resource play development activity.
|
•
|
Extensions, discoveries, and other additions:
Increased 250 mmboe primarily as a result of development activity in the U.S.
|
•
|
Production:
Decrease of 167 mmboe.
|
•
|
Sales of reserves in place:
Decrease of 101 mmboe primarily related to the sale of our assets in Norway and Angola (reflected in discontinued operations).
|
(mmboe)
|
|
|
Beginning of year
|
603
|
|
Revisions of previous estimates
|
(144
|
)
|
Improved recovery
|
4
|
|
Purchases of reserves in place
|
20
|
|
Extensions, discoveries, and other additions
|
264
|
|
Dispositions
|
(14
|
)
|
Transfers to proved developed
|
(181
|
)
|
End of year
|
552
|
|
|
Year Ended December 31,
|
||||||||||||||||||||||
(In millions)
|
U.S.
|
|
Canada
|
|
E.G.
|
|
Other
Africa
|
|
Other Int'l
|
|
Total
|
||||||||||||
2016 Capitalized Costs:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Proved properties
|
$
|
25,497
|
|
|
$
|
9,571
|
|
|
$
|
1,978
|
|
|
$
|
756
|
|
|
$
|
5,864
|
|
|
$
|
43,666
|
|
Unproved properties
|
1,473
|
|
|
1,379
|
|
|
119
|
|
|
417
|
|
|
183
|
|
|
3,571
|
|
||||||
Total
|
26,970
|
|
|
10,950
|
|
|
2,097
|
|
|
1,173
|
|
|
6,047
|
|
|
47,237
|
|
||||||
Accumulated depreciation,
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
depletion and amortization:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Proved properties
|
12,526
|
|
|
1,649
|
|
|
1,216
|
|
|
269
|
|
|
5,246
|
|
|
20,906
|
|
||||||
Unproved properties
(a)
|
382
|
|
|
310
|
|
|
2
|
|
|
—
|
|
|
113
|
|
|
807
|
|
||||||
Total
|
12,908
|
|
|
1,959
|
|
|
1,218
|
|
|
269
|
|
|
5,359
|
|
|
21,713
|
|
||||||
Net capitalized costs
|
$
|
14,062
|
|
|
$
|
8,991
|
|
|
$
|
879
|
|
|
$
|
904
|
|
|
$
|
688
|
|
|
$
|
25,524
|
|
2015 Capitalized Costs:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Proved properties
|
$
|
27,816
|
|
|
$
|
9,538
|
|
|
$
|
1,955
|
|
|
$
|
828
|
|
|
$
|
5,741
|
|
|
$
|
45,878
|
|
Unproved properties
|
1,625
|
|
|
1,389
|
|
|
86
|
|
|
465
|
|
|
242
|
|
|
3,807
|
|
||||||
Total
|
29,441
|
|
|
10,927
|
|
|
2,041
|
|
|
1,293
|
|
|
5,983
|
|
|
49,685
|
|
||||||
Accumulated depreciation,
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
depletion and amortization:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Proved properties
|
13,656
|
|
|
1,420
|
|
|
1,105
|
|
|
263
|
|
|
5,195
|
|
|
21,639
|
|
||||||
Unproved properties
(a)
|
675
|
|
|
310
|
|
|
—
|
|
|
107
|
|
|
114
|
|
|
1,206
|
|
||||||
Total
|
14,331
|
|
|
1,730
|
|
|
1,105
|
|
|
370
|
|
|
5,309
|
|
|
22,845
|
|
||||||
Net capitalized costs
|
$
|
15,110
|
|
|
$
|
9,197
|
|
|
$
|
936
|
|
|
$
|
923
|
|
|
$
|
674
|
|
|
$
|
26,840
|
|
(In millions)
|
U.S.
|
|
Canada
|
|
E.G.
|
|
Other
Africa
|
|
Other Int'l
|
|
Cont Ops
|
|
Disc Ops
|
|
Total
|
||||||||||||||||
December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Property acquisition:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Proved
|
$
|
276
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
276
|
|
|
$
|
—
|
|
|
$
|
276
|
|
Unproved
|
642
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
(11
|
)
|
|
632
|
|
|
—
|
|
|
632
|
|
||||||||
Exploration
|
525
|
|
|
—
|
|
|
1
|
|
|
10
|
|
|
3
|
|
|
539
|
|
|
—
|
|
|
539
|
|
||||||||
Development
|
456
|
|
|
31
|
|
|
55
|
|
|
3
|
|
|
121
|
|
(c)
|
666
|
|
|
—
|
|
|
666
|
|
||||||||
Total
|
$
|
1,899
|
|
|
$
|
31
|
|
|
$
|
56
|
|
|
$
|
14
|
|
|
$
|
113
|
|
|
$
|
2,113
|
|
|
$
|
—
|
|
|
$
|
2,113
|
|
December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Property acquisition:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Proved
|
$
|
4
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
4
|
|
|
$
|
—
|
|
|
$
|
4
|
|
Unproved
|
61
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
62
|
|
|
—
|
|
|
62
|
|
||||||||
Exploration
|
959
|
|
|
1
|
|
|
60
|
|
|
38
|
|
|
50
|
|
|
1,108
|
|
|
—
|
|
|
1,108
|
|
||||||||
Development
|
1,477
|
|
|
—
|
|
|
150
|
|
|
13
|
|
|
31
|
|
(c)
|
1,671
|
|
|
—
|
|
|
1,671
|
|
||||||||
Total
|
$
|
2,501
|
|
|
$
|
1
|
|
(b)
|
$
|
210
|
|
|
$
|
52
|
|
|
$
|
81
|
|
|
$
|
2,845
|
|
|
$
|
—
|
|
|
$
|
2,845
|
|
December 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Property acquisition:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Proved
|
$
|
26
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
26
|
|
|
$
|
—
|
|
|
$
|
26
|
|
Unproved
|
202
|
|
|
3
|
|
|
—
|
|
|
53
|
|
|
2
|
|
|
260
|
|
|
1
|
|
|
261
|
|
||||||||
Exploration
|
1,140
|
|
|
4
|
|
|
35
|
|
|
119
|
|
|
119
|
|
|
1,417
|
|
|
6
|
|
|
1,423
|
|
||||||||
Development
|
3,532
|
|
|
196
|
|
|
139
|
|
|
16
|
|
|
94
|
|
|
3,977
|
|
|
418
|
|
|
4,395
|
|
||||||||
Total
|
$
|
4,900
|
|
|
$
|
203
|
|
|
$
|
174
|
|
|
$
|
188
|
|
|
$
|
215
|
|
|
$
|
5,680
|
|
|
$
|
425
|
|
|
$
|
6,105
|
|
(a)
|
Includes costs incurred whether capitalized or expensed.
|
(b)
|
Reflects reimbursements earned from the governments of Canada and Alberta related to funds previously expended for Quest CCS capital equipment.
|
(c)
|
Includes revisions to asset retirement costs primarily due to changes in timing of these activities in the U.K.
|
|
U.S.
|
|
Canada
|
|
E.G.
|
|
Other
Africa
|
|
Other Int'l
|
|
Cont Ops
|
|
Disc Ops
|
|
Total
|
||||||||||||||||
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Revenues and other income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Sales
|
$
|
2,249
|
|
|
$
|
724
|
|
|
$
|
42
|
|
|
$
|
54
|
|
|
$
|
237
|
|
|
$
|
3,306
|
|
|
$
|
—
|
|
|
$
|
3,306
|
|
Transfers
|
—
|
|
|
—
|
|
|
291
|
|
|
—
|
|
|
—
|
|
|
291
|
|
|
—
|
|
|
291
|
|
||||||||
Other income
(a)
|
387
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
389
|
|
|
—
|
|
|
389
|
|
||||||||
Total revenues and other income
|
2,636
|
|
|
724
|
|
|
333
|
|
|
54
|
|
|
239
|
|
|
3,986
|
|
|
—
|
|
|
3,986
|
|
||||||||
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Production costs
|
(952
|
)
|
|
(544
|
)
|
|
(81
|
)
|
|
(36
|
)
|
|
(140
|
)
|
|
(1,753
|
)
|
|
—
|
|
|
(1,753
|
)
|
||||||||
Exploration expenses
(b)
|
(306
|
)
|
|
(7
|
)
|
|
(1
|
)
|
|
(14
|
)
|
|
(2
|
)
|
|
(330
|
)
|
|
—
|
|
|
(330
|
)
|
||||||||
Depreciation, depletion and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
amortization
(c)
|
(1,901
|
)
|
|
(239
|
)
|
|
(114
|
)
|
|
(7
|
)
|
|
(132
|
)
|
|
(2,393
|
)
|
|
—
|
|
|
(2,393
|
)
|
||||||||
Technical support and other
|
(21
|
)
|
|
(1
|
)
|
|
(4
|
)
|
|
(3
|
)
|
|
(2
|
)
|
|
(31
|
)
|
|
—
|
|
|
(31
|
)
|
||||||||
Total expenses
|
(3,180
|
)
|
|
(791
|
)
|
|
(200
|
)
|
|
(60
|
)
|
|
(276
|
)
|
|
(4,507
|
)
|
|
—
|
|
|
(4,507
|
)
|
||||||||
Results before income taxes
|
(544
|
)
|
|
(67
|
)
|
|
133
|
|
|
(6
|
)
|
|
(37
|
)
|
|
(521
|
)
|
|
—
|
|
|
(521
|
)
|
||||||||
Income tax provision
|
195
|
|
|
15
|
|
|
(26
|
)
|
|
(2
|
)
|
|
57
|
|
|
239
|
|
|
—
|
|
|
239
|
|
||||||||
Results of operations
|
$
|
(349
|
)
|
|
$
|
(52
|
)
|
|
$
|
107
|
|
|
$
|
(8
|
)
|
|
$
|
20
|
|
|
$
|
(282
|
)
|
|
$
|
—
|
|
|
$
|
(282
|
)
|
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Revenues and other income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Sales
|
$
|
3,374
|
|
|
$
|
700
|
|
|
$
|
40
|
|
|
$
|
—
|
|
|
$
|
329
|
|
|
$
|
4,443
|
|
|
$
|
—
|
|
|
$
|
4,443
|
|
Transfers
|
—
|
|
|
—
|
|
|
296
|
|
|
—
|
|
|
—
|
|
|
296
|
|
|
—
|
|
|
296
|
|
||||||||
Other income
(a)
|
230
|
|
|
—
|
|
|
—
|
|
|
(109
|
)
|
|
1
|
|
|
122
|
|
|
—
|
|
|
122
|
|
||||||||
Total revenues and other income
|
3,604
|
|
|
700
|
|
|
336
|
|
|
(109
|
)
|
|
330
|
|
|
4,861
|
|
|
—
|
|
|
4,861
|
|
||||||||
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Production costs
|
(1,259
|
)
|
|
(660
|
)
|
|
(84
|
)
|
|
(31
|
)
|
|
(177
|
)
|
|
(2,211
|
)
|
|
—
|
|
|
(2,211
|
)
|
||||||||
Exploration expenses
(b)
|
(750
|
)
|
|
(348
|
)
|
|
(41
|
)
|
|
(36
|
)
|
|
(143
|
)
|
|
(1,318
|
)
|
|
—
|
|
|
(1,318
|
)
|
||||||||
Depreciation, depletion and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
amortization
(c)
|
(2,758
|
)
|
|
(266
|
)
|
|
(92
|
)
|
|
(5
|
)
|
|
(163
|
)
|
|
(3,284
|
)
|
|
—
|
|
|
(3,284
|
)
|
||||||||
Technical support and other
|
(47
|
)
|
|
(2
|
)
|
|
(6
|
)
|
|
(2
|
)
|
|
(3
|
)
|
|
(60
|
)
|
|
—
|
|
|
(60
|
)
|
||||||||
Total expenses
|
(4,814
|
)
|
|
(1,276
|
)
|
|
(223
|
)
|
|
(74
|
)
|
|
(486
|
)
|
|
(6,873
|
)
|
|
—
|
|
|
(6,873
|
)
|
||||||||
Results before income taxes
|
(1,210
|
)
|
|
(576
|
)
|
|
113
|
|
|
(183
|
)
|
|
(156
|
)
|
|
(2,012
|
)
|
|
—
|
|
|
(2,012
|
)
|
||||||||
Income tax provision
(d)
|
437
|
|
|
31
|
|
|
(33
|
)
|
|
87
|
|
|
86
|
|
|
608
|
|
|
—
|
|
|
608
|
|
||||||||
Results of operations
|
$
|
(773
|
)
|
|
$
|
(545
|
)
|
|
$
|
80
|
|
|
$
|
(96
|
)
|
|
$
|
(70
|
)
|
|
$
|
(1,404
|
)
|
|
$
|
—
|
|
|
$
|
(1,404
|
)
|
Year Ended December 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Revenues and other income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Sales
|
$
|
5,754
|
|
|
$
|
1,316
|
|
|
$
|
43
|
|
|
$
|
244
|
|
|
$
|
440
|
|
|
$
|
7,797
|
|
|
$
|
189
|
|
|
$
|
7,986
|
|
Transfers
|
3
|
|
|
—
|
|
|
588
|
|
|
—
|
|
|
3
|
|
|
594
|
|
|
1,848
|
|
|
2,442
|
|
||||||||
Other income
(a)
|
(85
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(85
|
)
|
|
1,832
|
|
|
1,747
|
|
||||||||
Total revenues and other income
|
5,672
|
|
|
1,316
|
|
|
631
|
|
|
244
|
|
|
443
|
|
|
8,306
|
|
|
3,869
|
|
|
12,175
|
|
||||||||
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Production costs
|
(1,544
|
)
|
|
(803
|
)
|
|
(154
|
)
|
|
(79
|
)
|
|
(253
|
)
|
|
(2,833
|
)
|
|
(181
|
)
|
|
(3,014
|
)
|
||||||||
Exploration expenses
(b)
|
(607
|
)
|
|
(1
|
)
|
|
(26
|
)
|
|
(103
|
)
|
|
(56
|
)
|
|
(793
|
)
|
|
(5
|
)
|
|
(798
|
)
|
||||||||
Depreciation, depletion and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
—
|
|
|||||||||||||
amortization
(c)
|
(2,474
|
)
|
|
(206
|
)
|
|
(93
|
)
|
|
(9
|
)
|
|
(115
|
)
|
|
(2,897
|
)
|
|
(105
|
)
|
|
(3,002
|
)
|
||||||||
Technical support and other
|
(193
|
)
|
|
(15
|
)
|
|
(31
|
)
|
|
(21
|
)
|
|
(14
|
)
|
|
(274
|
)
|
|
(7
|
)
|
|
(281
|
)
|
||||||||
Total expenses
|
(4,818
|
)
|
|
(1,025
|
)
|
|
(304
|
)
|
|
(212
|
)
|
|
(438
|
)
|
|
(6,797
|
)
|
|
(298
|
)
|
|
(7,095
|
)
|
||||||||
Results before income taxes
|
854
|
|
|
291
|
|
|
327
|
|
|
32
|
|
|
5
|
|
|
1,509
|
|
|
3,571
|
|
|
5,080
|
|
||||||||
Income tax provision
|
(302
|
)
|
|
(71
|
)
|
|
(117
|
)
|
|
(32
|
)
|
|
(18
|
)
|
|
(540
|
)
|
|
(1,496
|
)
|
|
(2,036
|
)
|
||||||||
Results of operations
|
$
|
552
|
|
|
$
|
220
|
|
|
$
|
210
|
|
|
$
|
—
|
|
|
$
|
(13
|
)
|
|
$
|
969
|
|
|
$
|
2,075
|
|
|
$
|
3,044
|
|
(a)
|
Includes net gain (loss) on dispositions (see Note
6
).
|
(b)
|
Includes unproved property impairments (see Note
13
).
|
(c)
|
Includes long-lived asset impairments (see Note
13
).
|
|
Year Ended December 31,
|
||||||||||
(In millions)
|
2016
|
|
2015
|
|
2014
|
||||||
Results of operations
|
$
|
(282
|
)
|
|
$
|
(1,404
|
)
|
|
$
|
3,044
|
|
Discontinued operations
|
—
|
|
|
—
|
|
|
(2,075
|
)
|
|||
Results of continuing operations
|
(282
|
)
|
|
(1,404
|
)
|
|
969
|
|
|||
Items not included in results of oil and gas operations, net of tax:
|
|
|
|
|
|
||||||
Marketing income and other non-oil and gas producing related activities
|
(43
|
)
|
|
(75
|
)
|
|
73
|
|
|||
Income from equity method investments
|
142
|
|
|
127
|
|
|
327
|
|
|||
Items not allocated to segment income, net of tax:
|
|
|
|
|
|
||||||
Loss (gain) on asset dispositions
|
(248
|
)
|
|
(57
|
)
|
|
58
|
|
|||
Long-lived asset impairments
|
149
|
|
|
819
|
|
|
69
|
|
|||
Unrealized loss (gain) on derivatives
|
72
|
|
|
(32
|
)
|
|
—
|
|
|||
Alberta provincial corporate tax rate increase
|
—
|
|
|
135
|
|
|
—
|
|
|||
Foreign tax valuation allowance increase
|
(32
|
)
|
|
—
|
|
|
—
|
|
|||
Segment income
|
$
|
(242
|
)
|
|
$
|
(487
|
)
|
|
$
|
1,496
|
|
(In millions)
|
U.S.
|
|
Canada
|
|
E.G.
|
|
Other
Africa
|
|
Other Int'l
|
|
Total
|
||||||||||||
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Future cash inflows
|
$
|
27,610
|
|
|
$
|
26,803
|
|
|
$
|
1,977
|
|
|
$
|
8,511
|
|
|
$
|
921
|
|
|
$
|
65,822
|
|
Future production and support costs
|
(12,758
|
)
|
|
(20,208
|
)
|
|
(824
|
)
|
|
(930
|
)
|
|
(673
|
)
|
|
(35,393
|
)
|
||||||
Future development costs
|
(7,233
|
)
|
|
(3,209
|
)
|
|
(13
|
)
|
|
(296
|
)
|
|
(1,345
|
)
|
|
(12,096
|
)
|
||||||
Future income tax expenses
|
—
|
|
|
(446
|
)
|
|
(251
|
)
|
|
(6,884
|
)
|
|
514
|
|
|
(7,067
|
)
|
||||||
Future net cash flows
|
$
|
7,619
|
|
|
$
|
2,940
|
|
|
$
|
889
|
|
|
$
|
401
|
|
|
$
|
(583
|
)
|
(a)
|
$
|
11,266
|
|
10% annual discount for timing of cash flows
|
(4,355
|
)
|
|
(1,864
|
)
|
|
(264
|
)
|
|
(143
|
)
|
|
313
|
|
|
(6,313
|
)
|
||||||
Standardized measure of discounted future net cash flows-
|
|||||||||||||||||||||||
-related to continuing operations
|
$
|
3,264
|
|
|
$
|
1,076
|
|
|
$
|
625
|
|
|
$
|
258
|
|
|
$
|
(270
|
)
|
|
$
|
4,953
|
|
-related to discontinued operations
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
—
|
|
||
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Future cash inflows
|
$
|
31,026
|
|
|
$
|
31,087
|
|
|
$
|
2,671
|
|
|
$
|
12,157
|
|
|
$
|
1,281
|
|
|
$
|
78,222
|
|
Future production and support costs
|
(12,270
|
)
|
|
(27,459
|
)
|
|
(1,095
|
)
|
|
(901
|
)
|
|
(902
|
)
|
|
(42,627
|
)
|
||||||
Future development costs
|
(6,637
|
)
|
|
(2,929
|
)
|
|
(94
|
)
|
|
(689
|
)
|
|
(1,537
|
)
|
|
(11,886
|
)
|
||||||
Future income tax expenses
|
(778
|
)
|
|
—
|
|
|
(369
|
)
|
|
(9,857
|
)
|
|
602
|
|
|
(10,402
|
)
|
||||||
Future net cash flows
|
$
|
11,341
|
|
|
$
|
699
|
|
|
$
|
1,113
|
|
|
$
|
710
|
|
|
$
|
(556
|
)
|
(a)
|
$
|
13,307
|
|
10% annual discount for timing of cash flows
|
(6,082
|
)
|
|
(534
|
)
|
|
(380
|
)
|
|
(441
|
)
|
|
352
|
|
|
(7,085
|
)
|
||||||
Standardized measure of discounted future net cash flows-
|
|||||||||||||||||||||||
-related to continuing operations
|
$
|
5,259
|
|
|
$
|
165
|
|
|
$
|
733
|
|
|
$
|
269
|
|
|
$
|
(204
|
)
|
|
$
|
6,222
|
|
-related to discontinued operations
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Year Ended December 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Future cash inflows
|
$
|
66,307
|
|
|
$
|
55,675
|
|
|
$
|
5,027
|
|
|
$
|
23,803
|
|
|
$
|
3,040
|
|
|
$
|
153,852
|
|
Future production and support costs
|
(19,504
|
)
|
|
(34,838
|
)
|
|
(1,270
|
)
|
|
(803
|
)
|
|
(1,452
|
)
|
|
(57,867
|
)
|
||||||
Future development costs
|
(14,626
|
)
|
|
(9,754
|
)
|
|
(259
|
)
|
|
(680
|
)
|
|
(1,669
|
)
|
|
(26,988
|
)
|
||||||
Future income tax expenses
|
(8,124
|
)
|
|
(2,190
|
)
|
|
(922
|
)
|
|
(21,008
|
)
|
|
(9
|
)
|
|
(32,253
|
)
|
||||||
Future net cash flows
|
$
|
24,053
|
|
|
$
|
8,893
|
|
|
$
|
2,576
|
|
|
$
|
1,312
|
|
|
$
|
(90
|
)
|
|
$
|
36,744
|
|
10% annual discount for timing of cash flows
|
(12,138
|
)
|
|
(6,613
|
)
|
|
(915
|
)
|
|
(742
|
)
|
|
221
|
|
|
(20,187
|
)
|
||||||
Standardized measure of discounted future net cash flows-
|
|||||||||||||||||||||||
-related to continuing operations
|
$
|
11,915
|
|
|
$
|
2,280
|
|
|
$
|
1,661
|
|
|
$
|
570
|
|
|
$
|
131
|
|
|
$
|
16,557
|
|
-related to discontinued operations
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(a)
|
Future cash flows for Other International reflects the impact of future abandonment costs related to the U.K.
|
|
Year Ended December 31,
|
||||||||||
(In millions)
|
2016
|
|
2015
|
|
2014
|
||||||
Sales and transfers of oil and gas produced, net of production and support costs
|
$
|
(1,813
|
)
|
|
$
|
(2,460
|
)
|
|
$
|
(5,284
|
)
|
Net changes in prices and production and support costs related to future production
|
(3,173
|
)
|
(b)
|
(25,239
|
)
|
(b)
|
(2,688
|
)
|
|||
Extensions, discoveries and improved recovery, less related costs
|
238
|
|
|
1,100
|
|
|
3,539
|
|
|||
Development costs incurred during the period
|
700
|
|
|
1,694
|
|
|
4,088
|
|
|||
Changes in estimated future development costs
|
2,492
|
|
|
9,397
|
|
|
(1,423
|
)
|
|||
Revisions of previous quantity estimates
(a)
|
(1,088
|
)
|
|
(7,625
|
)
|
|
(3,193
|
)
|
|||
Net changes in purchases and sales of minerals in place
|
(651
|
)
|
|
(460
|
)
|
|
(168
|
)
|
|||
Accretion of discount
|
1,020
|
|
|
2,967
|
|
|
3,132
|
|
|||
Net change in income taxes
|
1,006
|
|
|
10,291
|
|
|
3,312
|
|
|||
Net change for the year
|
(1,269
|
)
|
|
(10,335
|
)
|
|
1,315
|
|
|||
Beginning of the year related to continuing operations
|
6,222
|
|
|
16,557
|
|
|
15,242
|
|
|||
End of the year related to continuing operations
|
$
|
4,953
|
|
|
$
|
6,222
|
|
|
$
|
16,557
|
|
Net change for the year related to discontinued operations
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(2,530
|
)
|
(a)
|
Includes amounts resulting from changes in the timing of production.
|
(b)
|
Decrease primarily due to lower realized prices.
|
•
|
Marathon Oil Corporation 2016 Incentive Compensation Plan (the "2016 Plan")
|
•
|
Marathon Oil Corporation 2012 Incentive Compensation Plan (the "2012 Plan") – No additional awards will be granted under this plan.
|
•
|
Marathon Oil Corporation 2007 Incentive Compensation Plan (the "2007 Plan") – No additional awards will be granted under this plan.
|
•
|
Marathon Oil Corporation 2003 Incentive Compensation Plan (the "2003 Plan") – No additional awards will be granted under this plan.
|
•
|
Deferred Compensation Plan for Non-Employee Directors – No additional awards will be granted under this plan.
|
Plan category
|
Number of securities to be issued upon
exercise of outstanding options, warrants and rights
|
|
Weighted-average
exercise price of
outstanding options,
warrants and rights
(c)
|
|
Number of securities
remaining available for future issuance
under equity compensation plans
|
|
||
Equity compensation plans approved by stockholders
|
13,566,560
|
|
(a)
|
$27.31
|
|
53,818,078
|
|
(d)
|
Equity compensation plans not approved by stockholders
|
12,291
|
|
(b)
|
N/A
|
|
—
|
|
|
Total
|
13,578,851
|
|
|
N/A
|
|
53,818,078
|
|
|
(a)
|
Includes the following:
|
•
|
4,214,949
stock options outstanding under the 2012 Plan;
7,700,584
stock options outstanding under the 2007 Plan;
|
•
|
353,503
common stock units that have been credited to non-employee directors pursuant to the non-employee director deferred compensation program and the annual director stock award program established under the 2012 Plan, 2007 Plan and 2003 Plan. Common stock units credited under the 2012 Plan, 2007 Plan and 2003 Plan were
166,680
,
152,828
and
33,995
, respectively;
|
•
|
1,297,524
restricted stock units granted to non-officers under the 2012 Plan and 2016 Plan and outstanding as of
December 31, 2016
.
|
•
|
In addition to the awards reported above
60,716
and
429,708
shares of restricted stock were issued and outstanding as of
December 31, 2016
, but subject to forfeiture restrictions under the 2016 Plan. In addition to the awards reported above 5,206,301 shares of restricted stock were issued and outstanding as of
December 31, 2016
, but subject to forfeiture restrictions under the 2012 Plan.
|
(b)
|
Reflects awards of common stock units made to non-employee directors under the Deferred Compensation Plan for Non-Employee Directors prior to April 30, 2003. When a non-employee director leaves the Board, he or she will be issued actual shares of Marathon Oil common stock in place of the common stock units.
|
(c)
|
The weighted-average exercise prices do not take the restricted stock units or common stock units into account as these awards have no exercise price.
|
(d)
|
Reflects the shares available for issuance under the 2016 Plan. No more than
22,331,152
of these shares may be issued for awards other than stock options or stock appreciation rights. In addition, shares related to grants that are forfeited, terminated, canceled or expire unexercised shall again immediately become available for issuance.
|
February 24, 2017
|
|
MARATHON OIL CORPORATION
|
|
|
|
|
|
By: /s/ GARY E. WILSON
|
|
|
Gary E. Wilson
|
|
|
Vice President, Controller and Chief Accounting Officer
|
Signature
|
|
Title
|
|
|
|
/
S
/ LEE M. TILLMAN
|
|
President and Chief Executive Officer and Director
|
Lee M. Tillman
|
|
|
|
|
|
/
S
/ PATRICK J. WAGNER
|
|
Interim Chief Financial Officer and Vice President Corporate Development and Strategy
|
Patrick J. Wagner
|
|
|
|
|
|
/s/ GARY E. WILSON
|
|
Vice President, Controller and Chief Accounting Officer
|
Gary E. Wilson
|
|
|
|
|
|
/
S
/ DENNIS H. REILLEY
|
|
Chairman of the Board
|
Dennis H. Reilley
|
|
|
|
|
|
/s/ GAURDIE E. BANISTER, JR.
|
|
Director
|
Gaurdie E. Banister, Jr.
|
|
|
|
|
|
/
S
/ GREGORY H. BOYCE
|
|
Director
|
Gregory H. Boyce
|
|
|
|
|
|
/S/ CHADWICK C. DEATON
|
|
Director
|
Chadwick C. Deaton
|
|
|
|
|
|
/
S
/ MARCELA E. DONADIO
|
|
Director
|
Marcela E. Donadio
|
|
|
|
|
|
/
S
/ PHILIP LADER
|
|
Director
|
Philip Lader
|
|
|
|
|
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/
S
/ MICHAEL E. J. PHELPS
|
|
Director
|
Michael E. J. Phelps
|
|
|
Exhibit
|
|
|
Incorporated by Reference (File No. 001-05153, unless otherwise indicated)
|
||||
Number
|
|
Exhibit Description
|
Form
|
|
Exhibit
|
|
Filing Date
|
3
|
|
Articles of Incorporation and By-laws
|
|||||
3.1
|
|
Restated Certificate of Incorporation of Marathon Oil Corporation
|
10-Q
|
|
3.1
|
|
8/8/2013
|
3.2
|
|
Marathon Oil Corporation By-laws (Amended and restated as of February 24, 2016)
|
8-K
|
|
3.1
|
|
3/1/2016
|
3.3
|
|
Specimen of Common Stock Certificate
|
10-K
|
|
3.3
|
|
2/28/2014
|
4
|
|
Instruments Defining the Rights of Security Holders, Including Indentures
|
|||||
4.1
|
|
Indenture, dated as of February 26, 2002, between Marathon Oil Corporation and The Bank of New York Trust Company, N.A., successor in interest to JPMorgan Chase Bank as Trustee, relating to senior debt securities of Marathon Oil Corporation. Pursuant to CFR 229.601(b)(4)(iii), instruments with respect to long-term debt issues have been omitted where the amount of securities authorized under such instruments does not exceed 10% of the total consolidated assets of Marathon Oil. Marathon Oil hereby agrees to furnish a copy of any such instrument to the Securities and Exchange Commission upon its request
|
10-K
|
|
4.2
|
|
2/28/2014
|
10
|
|
Material Contracts
|
|
|
|
|
|
10.1
|
|
Amended and Restated Credit Agreement, dated as of May 28, 2014, among Marathon Oil Corporation, as borrower, The Royal Bank of Scotland plc, as syndication agent, Citibank, N.A., Morgan Stanley Senior Funding, Inc. and The Bank of Nova Scotia, as documentation agents, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions named therein
|
8-K
|
|
4.1
|
|
6/2/2014
|
10.2
|
|
First Amendment, dated as of May 5, 2015, to the Amended and Restated Credit Agreement dated as of May 28, 2014, by and among Marathon Oil Corporation, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and certain other financial institutions named therein
|
10-Q
|
|
10.1
|
|
5/7/2015
|
10.3
|
|
Incremental Commitments Supplement, dated as of March 4, 2016, to the Amended and Restated Credit Agreement dated as of May 28, 2014, as amended by the First Amendment dated as of May 5, 2015, among Marathon Oil Corporation, as borrower, the lenders party thereto, The Royal Bank of Scotland Plc, as syndication agent, Citibank, N.A., Morgan Stanley Senior Funding, Inc. and The Bank of Nova Scotia, as documentation agents, and JPMorgan Chase Bank, N.A., as administrative agent.
|
8-K
|
|
99.1
|
|
3/8/2016
|
10.4
†
|
|
Marathon Oil Corporation 2016 Incentive Compensation Plan
|
DEF 14A
|
|
App. A
|
|
4/7/2016
|
10.5†
|
|
Form of Marathon Oil Corporation 2016 Incentive Compensation Plan Restricted Stock Award Agreement for Section 16 Officers (3-year cliff vesting)
|
8-K/A
|
|
10.1
|
|
10/6/2016
|
10.6†
*
|
|
Form of Marathon Oil Corporation 2016 Incentive Compensation Plan Restricted Stock Award Agreement for Section 16 Officers (3-year prorata vesting)
|
|
|
|
|
|
10.7†*
|
|
Form of Marathon Oil Corporation 2016 Incentive Compensation Plan Nonqualified Stock Option Award Agreement for Section 16 Officers
|
|
|
|
|
|
10.8†*
|
|
Form of Marathon Oil Corporation 2016 Incentive Compensation Plan Restricted Stock Unit Award Agreement for Non-Employee Directors (3-year cliff vesting)
|
|
|
|
|
|
Exhibit
|
|
|
Incorporated by Reference (File No. 001-05153, unless otherwise indicated)
|
||||
Number
|
|
Exhibit Description
|
Form
|
|
Exhibit
|
|
Filing Date
|
10.9†*
|
|
Form of Marathon Oil Corporation 2016 Incentive Compensation Plan Restricted Stock Unit Award Agreement for Non-Employee Canadian Directors (3-year cliff vesting)
|
|
|
|
|
|
10.10†
|
|
Marathon Oil Corporation 2012 Incentive Compensation Plan
|
DEF 14A
|
|
App. III
|
|
3/8/2012
|
10.11†
|
|
Form of Marathon Oil Corporation 2012 Incentive Compensation Plan Non-Qualified Stock Option Award Agreement
|
8-K
|
|
10.1
|
|
8/1/2014
|
10.12
†
|
|
Form of Marathon Oil Corporation 2012 Incentive Compensation Plan Performance Unit Award Agreement
|
10-Q
|
|
10.1
|
|
5/7/2014
|
10.13
†
|
|
Form of Marathon Oil Corporation 2012 Incentive Compensation Plan Performance Unit Award Agreement
|
10-Q
|
|
10.2
|
|
5/7/2014
|
10.14†
|
|
Form of Marathon Oil Corporation 2012 Incentive Compensation Plan Initial CEO Option Grant Agreement
|
10-Q
|
|
10.1
|
|
11/6/2013
|
10.15†
|
|
Form of Marathon Oil Corporation 2012 Incentive Compensation Plan CEO Restricted Stock Agreement (3-year prorata vesting)
|
10-Q
|
|
10.2
|
|
11/6/2013
|
10.16†
|
|
Form of Marathon Oil Corporation 2012 Incentive Compensation Plan CEO Restricted Stock Award Agreement granted (3-year cliff vesting)
|
10-Q
|
|
10.3
|
|
11/6/2013
|
10.17†
|
|
Form of Marathon Oil Corporation 2012 Incentive Compensation Plan Nonqualified Stock Option Award Agreement for Section 16 Officers (3-year prorata vesting)
|
10-K
|
|
10.5
|
|
2/22/2013
|
10.18†
|
|
Form of Marathon Oil Corporation 2012 Incentive Compensation Plan Nonqualified Stock Option Award Agreement for Officers (3-year prorata vesting)
|
10-K
|
|
10.6
|
|
2/22/2013
|
10.19†
|
|
Form of Marathon Oil Corporation 2012 Incentive Compensation Plan Restricted Stock Award Agreement for Section 16 Officers (3-year cliff vesting)
|
10-K
|
|
10.7
|
|
2/22/2013
|
10.20†
|
|
Form of Marathon Oil Corporation 2012 Incentive Compensation Plan Restricted Stock Award Agreement for Officers (3-year cliff vesting)
|
10-K
|
|
10.8
|
|
2/22/2013
|
10.21
†
|
|
Form of Marathon Oil Corporation 2012 Incentive Compensation Plan Restricted Stock Award Agreement for Section 16 Officers (3-year prorata vesting)
|
10-K
|
|
10.9
|
|
2/22/2013
|
10.22
†
|
|
Form of Marathon Oil Corporation 2012 Incentive Compensation Plan Restricted Stock Award Agreement for Officers (3-year prorata vesting)
|
10-K
|
|
10.10
|
|
2/22/2013
|
10.23
†
|
|
Marathon Oil Corporation 2007 Incentive Compensation Plan
|
10-K
|
|
10.5
|
|
2/29/2012
|
10.24†
|
|
Form of Marathon Oil Corporation 2007 Incentive Compensation Plan Nonqualified Stock Option Award Agreement for Officers
|
10-K
|
|
10.6
|
|
2/29/2012
|
10.25
†
|
|
Form of Marathon Oil Corporation 2007 Incentive Compensation Plan Nonqualified Stock Option Award Agreement for Section 16 Officers
|
10-K
|
|
10.5
|
|
2/28/2011
|
10.26†
|
|
Form of Marathon Oil Corporation 2007 Incentive Compensation Plan Nonqualified Stock Option Award Agreement for Section 16 Officers
|
10-K
|
|
10.26
|
|
2/26/2010
|
10.27†
|
|
Marathon Oil Corporation 2003 Incentive Compensation Plan
|
10-K
|
|
10.9
|
|
2/26/2010
|
Exhibit
|
|
|
Incorporated by Reference (File No. 001-05153, unless otherwise indicated)
|
||||
Number
|
|
Exhibit Description
|
Form
|
|
Exhibit
|
|
Filing Date
|
10.28†
|
|
Form of Marathon Oil Corporation 2003 Incentive Compensation Plan Nonqualified Stock Option Award Agreement for Officers
|
10-K
|
|
10.22
|
|
2/26/2010
|
10.29†*
|
|
Marathon Oil Corporation Deferred Compensation Plan for Non-Employee Directors (Amended and Restated as of December 20, 2016)
|
|
|
|
|
|
10.30†
|
|
Marathon Oil Company Deferred Compensation Plan Amended and Restated Effective June 30, 2011
|
10-K
|
|
10.32
|
|
2/29/2012
|
10.31†
|
|
Marathon Oil Company Excess Benefit Plan Amended and Restated
|
10-K
|
|
10.31
|
|
2/29/2012
|
10.32†
|
|
Marathon Oil Corporation 2011 Officer Change in Control Severance Benefits Plan (as amended, effective November 1, 2014)
|
10-K
|
|
10.36
|
|
3/2/2015
|
10.33
†
|
|
Marathon Oil Corporation Policy for Repayment of Annual Cash Bonus Amounts
|
10-K
|
|
10.10
|
|
2/28/2011
|
10.34
†
|
|
Marathon Oil Corporation Executive Tax, Estate, and Financial Planning Program, Amended and Restated, Effective January 1, 2009
|
10-K
|
|
10.32
|
|
2/27/2009
|
10.35
|
|
Tax Sharing Agreement dated as of May 25, 2011 among Marathon Oil Corporation, Marathon Petroleum Corporation and MPC Investment LLC
|
8-K
|
|
10.1
|
|
5/26/2011
|
10.36
|
|
Separation Agreement with John R. Sult, dated September 23, 2016
|
8-K
|
|
10.1
|
|
9/29/2016
|
10.37
|
|
Consulting Services Agreement with John R. Sult, dated September 23, 2016
|
8-K
|
|
10.2
|
|
9/29/2016
|
10.38
|
|
Separation Agreement with Lance W. Robertson, dated September 23, 2016
|
8-K
|
|
10.3
|
|
9/29/2016
|
12.1*
|
|
Computation of Ratio of Earnings to Fixed Charges
|
|
|
|
|
|
21.1*
|
|
List of Significant Subsidiaries
|
|
|
|
|
|
23.1*
|
|
Consent of Independent Registered Public Accounting Firm
|
|
|
|
|
|
23.2*
|
|
Consent of GLJ Petroleum Consultants LTD., independent petroleum engineers and geologists
|
|
|
|
|
|
23.3*
|
|
Consent of Ryder Scott Company, L.P., independent petroleum engineers and geologists
|
|
|
|
|
|
23.4*
|
|
Consent of Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists
|
|
|
|
|
|
31.1*
|
|
Certification of President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934
|
|
|
|
|
|
31.2*
|
|
Certification of Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934
|
|
|
|
|
|
32.1*
|
|
Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350
|
|
|
|
|
|
32.2*
|
|
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350
|
|
|
|
|
|
99.1
|
|
Report of GLJ Petroleum Consultants LTD., independent petroleum engineers and geologists for 2015
|
10-K
|
|
99.1
|
|
2/25/2016
|
2.
|
Vesting and Forfeiture of Restricted Shares.
|
11.
|
Definitions.
For purposes of this Award Agreement:
|
|
|
Deanna L. Jones
|
|
Vice President, Human Resources &
|
|
Administrative Service
|
2.
|
Exercise and Vesting Schedule.
|
3.
|
Expiration of Option.
|
5.
|
Forfeiture or Repayment Resulting from Forfeiture Event.
|
13.
|
Definitions.
For purposes of this Award Agreement:
|
|
|
Deanna L. Jones
|
|
Vice President, Human Resources &
|
|
Administrative Service
|
2.
|
Vesting and Forfeiture of Restricted Units.
|
2.
|
Vesting and Forfeiture of Restricted Units.
|
1.
|
Purpose
|
2.
|
Definitions
|
(a)
|
409A Benefit
means that portion of a Participant’s Deferred Cash Account and Deferred Stock Account that was deferred or became vested after December 31, 2004, with earnings and losses attributable thereto pursuant to Sections 5 and 6.
|
(b)
|
Award Date
means the first business day of the calendar year.
|
(c)
|
Beneficiary or Beneficiaries
means a person or persons or other entity designated on a beneficiary designation form by a Participant as allowed in this Plan to receive Deferred Benefit payments. If there is no valid designation by the Participant, or if the designated Beneficiary or Beneficiaries fail to survive the Participant or otherwise fail to take the Benefit, the Participant's Beneficiary is the Participant's surviving spouse or, if there is no surviving spouse, the Participant's estate. A Participant may use a beneficiary designation form (in the form and manner acceptable to the Committee) to designate one or more Beneficiaries for all of the Participant’s Deferred Benefit; such designations are revocable.
|
(d)
|
Board
means the Board of Directors of Marathon Oil Corporation.
|
(e)
|
Code
means the Internal Revenue Code of 1986 as amended, including regulations and other guidance of general applicability promulgated thereunder.
|
(f)
|
Code section 409A
means, collectively, section 409A of the Code and any Treasury and Internal Revenue Service regulations and guidance issued thereunder.
|
(g)
|
Committee
means the Corporate Governance & Nominating Committee of the Board or such other committee of the Board as the Board may designate to administer the Plan. In the event the Committee has delegated any authority or responsibility under the Plan in accordance with Section 12, the term “Committee” where used herein shall also refer to the applicable delegate.
|
(h)
|
Common Stock
means the common stock of the Corporation.
|
(i)
|
Common Stock Unit
means a book-entry unit equal in value to a share of Common Stock. A Participant shall be credited with one Common Stock Unit for each stock unit or hypothetical share of Common Stock that was (a) granted to a Participant under the 2007 Incentive Compensation Plan, the 2012 Incentive Compensation Plan and the 2016 Incentive Compensation Plan, as well as other predecessor or successor plans or arrangements and (b) deferred under this Plan.
|
(j)
|
Corporation
means Marathon Oil Corporation or any successor thereto.
|
(k)
|
Deferral Election Form
means a document designated by the Committee for the purpose of allowing a Participant to elect deferrals under Section 3.
|
(l)
|
Deferral Year
means the calendar year for which a Participant has elected to defer amounts under this Plan.
|
(m)
|
Deferred Benefit
means a Participant’s Deferred Cash Account and Deferred Stock Account under the Plan.
|
(n)
|
Deferred Cash Account
means that bookkeeping record established for each Participant to reflect the status of the Participant’s Deferred Cash Benefit under this Plan. A Deferred Cash Account: (i) is established only for purposes of measuring a Deferred Cash Benefit and not to segregate assets or to identify assets that may or must be used to satisfy a Deferred Cash Benefit; (ii) will be credited with that portion of the Participant's Retainer Fee deferred as a Deferred Cash Benefit according to a Deferral Election Form; and (iii) will be credited periodically with earnings and losses as provided under Section 5.
|
(o)
|
Deferred Cash Benefit
means the amount of Retainer Fees deferred by a Participant under Section 3.
|
(p)
|
Deferred Stock Account
means that bookkeeping record established for each Participant to reflect the status of the Participant’s Deferred Stock Benefit under this Plan. A Deferred Stock Account is established only for purposes of measuring Common Stock Units and not to segregate assets or to identify assets that may or must be used to satisfy a Deferred Stock Benefit. A Deferred Stock Account will be credited with the Common Stock Units that comprise a Participant’s Deferred Stock Benefit.
|
(q)
|
Deferred Stock Benefit
means the number of Common Stock Units that were (a) granted to a Participant under the 2007 Incentive Compensation Plan, the 2012 Incentive Compensation Plan and the 2016 Incentive Compensation Plan, as well as other predecessor or successor plans or arrangements and (b) deferred under this Plan.
|
(r)
|
Directors
means those duly named members of the Board.
|
(s)
|
Election Date
means the date established by this Plan as the date before which a Participant must submit a valid Deferral Election Form to the Committee. For each Deferral Year, the Election Date is December 31 of the preceding calendar year. Notwithstanding the foregoing, the Committee may set an earlier date as the Election Date for any Deferral Year. All Election Dates shall be established in conformity with Code section 409A.
|
(t)
|
Grandfathered Benefit
means that portion of a Participant’s Deferred Cash Account and Deferred Stock Account that is exempt from Code section 409A because it was deferred and vested as of December 31, 2004, as adjusted to reflect any earnings or losses thereto pursuant to Sections 5 and 6.
|
(u)
|
Participant
means a Director who is not simultaneously an employee of the Corporation.
|
(v)
|
Retainer Fee
means that portion of a Participant's compensation that is fixed and paid without regard to the Participant’s attendance at meetings or position as chair of a committee of the Board.
|
(w)
|
Separation from Service
shall have the same meaning as set forth under Code section 409A.
|
(x)
|
Specified Employee
shall have the same meaning as set forth under Code section 409A and as determined by the Corporation in accordance with its established policy.
|
(y)
|
Thrift Plan
shall mean the Marathon Oil Company Thrift Plan or any successor to such plan.
|
3.
|
Deferral Election
|
(a)
|
Retainer Fee.
No later than each Deferral Year's Election Date, each Participant may submit a Deferral Election Form to defer until after Separation from Service the receipt of any portion up to 100 percent of the Participant’s Retainer Fee for the Deferral Year in the form of a Deferred Cash Benefit.
|
(b)
|
Common Stock Units Awarded after 2016.
No later than each Deferral Year's Election Date, each Participant may submit a Deferral Election Form to defer until after Separation from Service the receipt of any portion up to 100 percent of the Participant’s stock units or other equity-based compensation awarded for a subsequent Deferral Year in the form of a Deferred Stock Benefit.
|
(c)
|
Common Stock Units Awarded before 2017.
Common Stock Units awarded to Participants prior to 2017 are automatically deferred and accounted for in a Deferred Stock Account and are not subject to any additional Deferral Election.
|
(d)
|
Elections by New Directors.
In the event an individual becomes a Director and is first eligible to participate during a Deferral Year, such Director may submit a Deferral Election Form no later than thirty (30) days following the effective date of the individual’s position as a Director, provided that, to the extent required by Code section 409A, the Retainer Fee or stock unit or other equity-based compensation award subject to the election shall be prorated in accordance with Code section 409A.
|
(e)
|
Committee Right to Reject or Modify Deferral Election.
If it does so before the last business day preceding the Deferral Year, the Committee may reject or modify any Deferral Election Form for such Deferral Year and the Committee is not required to state a reason for such action. However, the Committee's rejection or modification of any Deferral Election Form must be based upon action taken without regard to any vote of the Participant whose Deferral Election Form is under consideration, and the Committee's rejections or modifications must be made on a uniform basis with respect to similarly situated Participants. If the Committee rejects or modifies a Deferral Election Form, the Participant must be paid the Retainer Fee that the Participant is entitled to receive after taking into account the rejected or modified Deferral Election Form. Similarly, stock units or other equity-based compensation awards that the Participant is entitled to receive shall be settled after taking into account the rejected or modified Deferral Election Form.
|
(f)
|
Elections Irrevocable during Deferral Year.
A Participant may not revoke a Deferral Election Form after the Deferral Year begins. Any writing signed by a Participant expressing an intention to revoke the Participant’s Deferral Election Form before the close of business on the
|
4.
|
Effect of No Election
|
5.
|
Deferred Cash Benefits
|
(a)
|
The Deferred Cash Account for each Participant will be credited with deemed investment returns as provided in section 5(b). Deferred Cash Benefits are credited to the applicable Participant's Deferred Cash Account as of the day the Retainer Fees would have been paid but for the deferral.
|
(b)
|
Except as provided in Section 6(c), a Participant may select one or more investment options approved by the Committee for the Participant’s Deferred Cash Benefits, and earnings and loses from such investment options will be credited to the Participant’s Deferred Cash Account at periods determined by the Committee. A Participant may change the investment allocation of the Participant’s Deferred Cash Account at any time. The Committee has approved the core investment options and lifecycle investment options available to participants in the Thrift Plan, as such investment options may be changed from time to time, as the investment options available under this Plan. The Committee hereby directs that earnings and losses from such investment options shall be credited to a Participant’s Deferred Cash Account in a manner similar to crediting of investment gains and losses to accounts of participants in the Thrift Plan.
|
6.
|
Deferred Stock Benefit
|
(a)
|
Each Common Stock Unit held in a Deferred Stock Account will increase or decrease in value by the same amount and with the same frequency as the fair market value of a share of Common Stock. Except as provided in Section 6(b), each Deferred Stock Account will be credited with Common Stock Units as of the applicable Award Date for an award of Common Stock Units.
|
(b)
|
If, on a record date, a Participant’s Deferred Stock Account contains Common Stock Units that were granted and deferred before 2012 or after
|
(c)
|
If, on a record date, a Participant’s Deferred Stock Account contains Common Stock Units that were granted during or after 2012 and before 2017, then such Participant’s Deferred Cash Account will be credited on or about each Common Stock dividend payment date with an amount equal to the dividends payable on the quantity of shares equal to the number of such Common Stock Units in such account. Such amount shall be accrued in the manner established by the Corporation from time to time, and no interest or earnings or losses from investment options shall be credited with respect to such amounts.
|
(d)
|
In the event of a reorganization, recapitalization, stock split, stock dividend, combination of shares, merger, consolidation, rights offering or any other change in the corporate structure, the number and kind of Common Stock Units credited to each Participant’s Deferred Stock Account shall be adjusted accordingly.
|
7.
|
Distributions
|
(a)
|
A Deferred Cash Benefit must be distributed in cash. A Deferred Stock Benefit must be distributed in shares of Common Stock and such distribution will correspond to, and equal the number of whole Common Stock Units credited to the Participant's Deferred Stock Account that are eligible for distribution. Fractional Common Stock Units shall neither be distributed nor settled by payment and shall be forfeited.
|
(b)
|
Except as otherwise provided in this Section 7, both a Participant’s Deferred Cash Benefit and Deferred Stock Benefit shall be paid to the Participant in a lump sum on the first day of the calendar month following the expiration of 45 days after the Participant’s Separation from Service for any reason other than death.
|
(c)
|
Except as otherwise provided in this Section 7, a Participant’s Deferred Stock Benefit consisting of Common Stock Units granted during or after 2012 and before 2017 and dividends credited with respect to such Common Stock Units pursuant to Section 6(c) of this Plan, shall be paid to the Participant in a lump sum on the earlier of (i) the date on which such Common Stock Units would otherwise be payable as provided in this Section 7 or (ii) the first day of the calendar month following the third anniversary of the date such Common Stock Units were credited under Section 6(a) of this Plan.
|
(d)
|
In the event of the death of a Participant, the Participant’s Deferred Benefit shall be paid to the Participant’s Beneficiary (or Beneficiaries) in a lump sum on the first day of the calendar month following the expiration of 45 days after the Participant’s Separation from Service (or, in the event of a Separation from Service of a Specified Employee not on account of death, within the 45-day period described in Section 7(e)).
|
(e)
|
Distribution of the Deferred Benefit of a Participant who the Committee determines is a Specified Employee (other than the Participant’s Grandfathered Benefit) shall commence within the 45-day period following the first of the month following 6 months after Separation from Service (other than a Separation from Service on account of the death of Participant). In the event of a Separation from Service of a Specified Employee on account of death, payment shall be made pursuant to Section 7(d). Payment of a Specified Employee’s Grandfathered Benefit shall be made pursuant to Section 7(b).
|
8.
|
Corporation's Obligation
|
(a)
|
The Plan is unfunded. A Deferred Benefit is at all times solely a contractual obligation of the Corporation. A Participant and the Participant’s Beneficiaries have no right, title or interest in the Participant’s Deferred Benefit or any claim against them. Except according to Section 8(b), the Corporation will not segregate any funds or assets for Deferred Benefits nor issue any notes or security for the payment of any Deferred Benefit.
|
(b)
|
The Corporation may establish a grantor trust and transfer to that trust shares of the Common Stock or other assets. The governing trust agreement must require a separate account to be established for each electing Participant. The governing trust agreement must also require that all Corporation assets held in trust remain at all times subject to the Corporation's creditors.
|
9.
|
Control by Participant
|
10.
|
Claims Against Participant's Deferred Benefit
|
11.
|
Amendment or Termination
|
12.
|
Administration
|
(a)
|
The Committee shall have the full and exclusive power and authority to administer this Plan and to take all actions that are specifically contemplated hereby or are necessary or appropriate in connection with the administration hereof. The Committee shall also have full and exclusive power to interpret this Plan, to adopt such rules, regulations and guidelines for carrying out this Plan as it may deem necessary or proper, and to delegate some or all of its authority or responsibilities under this Plan to any other person or entity. The Committee may correct any defect or supply an omission or reconcile any inconsistency in this Plan in the manner and to the extent the Committee deems necessary or desirable to further the Plan purposes. Any decision of the Committee in the interpretation and administration of this Plan shall lie within its sole and absolute discretion and shall be final, conclusive and binding on all parties concerned.
|
(b)
|
The Committee has delegated responsibility for ministerial acts and day-to-day administration of the Plan to the Vice President, Human Resources & Administrative Services and expects that he or she shall further delegate responsibility for such functions to employees of the Corporation or its subsidiaries or to such outside service providers as he or she may engage for such purposes.
|
13.
|
Notices
|
14.
|
Waiver
|
15.
|
Construction
|
16.
|
Effective Date
|
(a)
|
Affiliate
means an affiliate of the Corporation as the term "affiliate" is defined in paragraph 2.1 of Canada Revenue Agency Income Tax Folio S2-F1-C2,
Retiring Allowances
, dated November 8, 2016, as such publication may be amended, restated or replaced from time to time.
|
(b)
|
Canadian Director
means a Director who is, at any material time, a residentof Canada for the purposes of the ITA or otherwise subject to Canadian federal income tax under the ITA with respect to Awards under the Plan.
|
(c)
|
ITA
means the
Income Tax Act
(Canada) and the regulations thereto, as may be amended from time to time.
|
(d)
|
Termination Date
means, with respect to a Canadian Director, the earliest date on which both of the following conditions are met: (i) the Canadian Director has ceased to serve as a Director and is not a director of an Affiliate of the Corporation; and (ii) the Canadian Director is not an employee (within the meaning of the ITA) of the Corporation or any Affiliate thereof.
|
1.
|
Common Stock Units Awarded after 2016
|
(i)
|
the terms and conditions of such Common Stock Units, at the time of their grant, were such that such Common Stock Units are settled only in shares of Common Stock newly issued by the Corporation or previously owned by the Corporation and such Common Stock Units were governed by the provisions of section 7 of the ITA;
|
(ii)
|
the Deferral Election Form contemplated under Section 3(b) of the Plan is made prior to the date that the Canadian Director would otherwise be entitled to receive or call for a payment in respect of such Common Stock Units; and
|
(iii)
|
once made, the Deferral Election is irrevocable.
|
2.
|
Common Stock Units Awarded before 2017
|
(i)
|
the terms and conditions of such Common Stock Units, at the time of their grant, were such that such Common Stock Units are settled only in shares of Common Stock newly issued by the Corporation or previously owned by the Corporation and such Common Stock Units were governed by the provisions of section 7 of the ITA; and
|
(ii)
|
the automatic deferral occurs prior to the date that the Canadian Director would otherwise be entitled to receive or call for a payment in respect of such Common Stock Units.
|
3.
|
Value of Deferred Stock Benefit
|
|
|
Year Ended
|
||||||||||||||||||||||
|
|
December 31,
|
||||||||||||||||||||||
(In millions)
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
|
2011
|
||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Income (loss) from continuing operations before income taxes
|
|
$
|
(1,235
|
)
|
|
$
|
(2,958
|
)
|
|
$
|
1,361
|
|
|
$
|
2,393
|
|
|
$
|
3,104
|
|
|
$
|
1,615
|
|
Income from equity method investments
|
|
175
|
|
|
145
|
|
|
424
|
|
|
423
|
|
|
370
|
|
|
462
|
|
||||||
Income (loss) from continuing operations before income taxes and income from equity method investments
|
|
(1,410
|
)
|
|
(3,103
|
)
|
|
937
|
|
|
1,970
|
|
|
2,734
|
|
|
1,153
|
|
||||||
Add (deduct)
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Fixed charges
|
|
421
|
|
|
382
|
|
|
352
|
|
|
360
|
|
|
338
|
|
|
504
|
|
||||||
Capitalized interest
|
|
(23
|
)
|
|
(26
|
)
|
|
(33
|
)
|
|
(27
|
)
|
|
(68
|
)
|
|
(208
|
)
|
||||||
Amortization of capitalized interest
|
|
7
|
|
|
5
|
|
|
8
|
|
|
21
|
|
|
45
|
|
|
107
|
|
||||||
Distributed income from equity investees
|
|
192
|
|
|
178
|
|
|
454
|
|
|
430
|
|
|
382
|
|
|
499
|
|
||||||
Earnings as defined
|
|
(813
|
)
|
|
(2,564
|
)
|
|
1,718
|
|
|
2,754
|
|
|
3,431
|
|
|
2,055
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net interest expense (including discontinued operations)
|
|
367
|
|
|
321
|
|
|
277
|
|
|
297
|
|
|
236
|
|
|
245
|
|
||||||
Capitalized interest (including discontinued operations)
|
|
23
|
|
|
26
|
|
|
33
|
|
|
27
|
|
|
68
|
|
|
208
|
|
||||||
Interest portion of rental expense (including discontinued operations)
|
|
31
|
|
|
35
|
|
|
42
|
|
|
36
|
|
|
34
|
|
|
51
|
|
||||||
Fixed charges as defined
|
|
421
|
|
|
382
|
|
|
352
|
|
|
360
|
|
|
338
|
|
|
504
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Ratio of earnings to fixed charges
|
|
(1.93
|
)
|
|
(6.71
|
)
|
|
4.88
|
|
|
7.65
|
|
|
10.15
|
|
|
4.08
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Amount by which earnings were insufficient to cover fixed charges
|
|
$
|
1,234
|
|
|
$
|
2,946
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Subsidiaries of Marathon Oil
|
Exhibit 21.1
|
Company Name
|
Country
|
Country Region
|
Alba Associates LLC
|
Cayman Islands
|
|
Alba Equatorial Guinea Partnership, L.P.
|
United States
|
Delaware
|
Alba Plant LLC
|
Cayman Islands
|
|
AMPCO Marketing, L.L.C.
|
United States
|
Michigan
|
AMPCO Services, L.L.C.
|
United States
|
Michigan
|
Atlantic Methanol Associates LLC
|
Cayman Islands
|
|
Atlantic Methanol Production Company LLC
|
Cayman Islands
|
|
E.G. Global LNG Services, Ltd.
|
United States
|
Delaware
|
Equatorial Guinea LNG Company, S.A.
|
Equatorial Guinea
|
|
Equatorial Guinea LNG Holdings Limited
|
Bahamas
|
|
Equatorial Guinea LNG Operations, S.A.
|
Equatorial Guinea
|
|
Equatorial Guinea LNG Train 1, S.A.
|
Equatorial Guinea
|
|
In-Depth Systems, Inc.
|
United States
|
Texas
|
Marathon Alpha Holdings LLC
|
United States
|
Delaware
|
Marathon Canada Investment Coöperatief U.A.
|
Netherlands
|
|
Marathon Delta Investment Limited
|
Cayman Islands
|
|
Marathon E.G. Alba Limited
|
Cayman Islands
|
|
Marathon E.G. Holding Limited
|
Cayman Islands
|
|
Marathon E.G. International Limited
|
Cayman Islands
|
|
Marathon E.G. LNG Holding Limited
|
Cayman Islands
|
|
Marathon E.G. LPG Limited
|
Cayman Islands
|
|
Marathon E.G. Offshore Limited
|
Cayman Islands
|
|
Marathon E.G. Oil Operations Limited
|
Cayman Islands
|
|
Marathon E.G. Production Limited
|
Cayman Islands
|
|
Marathon Eagle Ford Midstream LLC
|
United States
|
Delaware
|
Marathon East Texas Holdings LLC
|
United States
|
Delaware
|
Marathon Ethiopia Limited B.V.
|
Netherlands
|
|
Marathon Global Services, Ltd.
|
United States
|
Delaware
|
Marathon GTF Technology, Ltd.
|
United States
|
Delaware
|
Marathon International Oil (G.B.) Limited
|
United Kingdom
|
England and Wales
|
Marathon International Oil Angola Block 31 Limited
|
Cayman Islands
|
|
Marathon International Oil Angola Block 32 Limited
|
Cayman Islands
|
|
Marathon International Oil Company
|
United States
|
Delaware
|
Marathon International Oil Holdings LLC
|
United States
|
Delaware
|
Marathon International Oil Libya Limited
|
Cayman Islands
|
|
Marathon International Oil Supply Company (G.B.) Limited
|
United Kingdom
|
England and Wales
|
Marathon International Oil Ventures Limited
|
Cayman Islands
|
|
Marathon International Petroleum Asia Pacific Limited
|
Cayman Islands
|
|
Marathon International Petroleum Indonesia Limited
|
Cayman Islands
|
|
Marathon International Services Limited
|
Cayman Islands
|
|
Marathon International Upstream, Ltd.
|
United States
|
Delaware
|
Marathon Kenya Limited B.V.
|
Netherlands
|
|
Marathon LNG Marketing LLC
|
United States
|
Delaware
|
Marathon Methanol Holding LLC
|
United States
|
Delaware
|
Marathon Offshore Alpha Limited
|
Cayman Islands
|
|
Marathon Offshore Investment Limited
|
Cayman Islands
|
|
Marathon Offshore Libya Service Company, Ltd.
|
United States
|
Delaware
|
Marathon Oil (East Texas) L.P.
|
United States
|
Texas
|
Marathon Oil (Suisse) SA
|
Switzerland
|
|
Marathon Oil (West Texas) L.P.
|
United States
|
Texas
|
Marathon Oil Canada Corporation
|
Canada
|
Alberta
|
Marathon Oil Canada Investment LLC
|
United States
|
Delaware
|
Marathon Oil Cap Bon, Ltd.
|
United States
|
Delaware
|
Marathon Oil Company
|
United States
|
Ohio
|
Marathon Oil Corporation
|
United States
|
Delaware
|
Marathon Oil Decommissioning Services LLC
|
United States
|
Delaware
|
Marathon Oil Dutch Holdings B.V.
|
Netherlands
|
|
Marathon Oil Dutch Holdings Coöperatief U.A.
|
Netherlands
|
|
Marathon Oil Dutch Investment C.V.
|
Netherlands
|
|
Marathon Oil EF II LLC
|
United States
|
Delaware
|
Marathon Oil EF LLC
|
United States
|
Delaware
|
Marathon Oil Exploration Limited
|
Cayman Islands
|
|
Marathon Oil Holdings (Barbados) Inc.
|
Barbados
|
|
Marathon Oil Holdings U.K. Limited
|
United Kingdom
|
England and Wales
|
Marathon Oil International Holding C.V.
|
Netherlands
|
|
Marathon Oil International LLC
|
United States
|
Delaware
|
Marathon Oil Investment LLC
|
United States
|
Delaware
|
Marathon Oil Jenein Limited
|
Cayman Islands
|
|
Marathon Oil KDV B.V.
|
Netherlands
|
|
Marathon Oil Libya Limited
|
Cayman Islands
|
|
Marathon Oil Marketing, Ltd.
|
United States
|
Delaware
|
Marathon Oil North Sea (G.B.) Limited
|
United Kingdom
|
England and Wales
|
Marathon Oil Switzerland B.V.
|
Netherlands
|
|
Marathon Oil Timor Gap West, Ltd.
|
United States
|
Delaware
|
Marathon Oil U.K. LLC
|
United States
|
Delaware
|
Marathon Oil West of Shetlands Limited
|
United Kingdom
|
England and Wales
|
Marathon Service (G.B.) Limited
|
United Kingdom
|
England and Wales
|
Marathon Service Company
|
United States
|
Delaware
|
Marathon Upstream Gabon Limited
|
Cayman Islands
|
|
Marathon Upstream Nigeria Limited
|
Nigeria
|
|
Marathon West Texas Holdings LLC
|
United States
|
Delaware
|
Marathon Western Saudi Arabia Limited
|
Cayman Islands
|
|
Miltiades Limited
|
United Kingdom
|
England and Wales
|
MOC Portfolio Delaware, Inc.
|
United States
|
Delaware
|
Navatex Gathering LLC
|
United States
|
Delaware
|
Oil Casualty Insurance, Ltd.
|
Bermuda
|
|
Old Main Assurance Ltd.
|
Bermuda
|
|
Palmyra Petroleum Company
|
Syrian Arab Republic
|
|
Pan Ocean Energy LLC
|
United States
|
Delaware
|
Pennaco Energy, Inc.
|
United States
|
Delaware
|
St. James Assurance, LLC
|
|
|
Western Bluewater Resources (Trinidad) Limited
|
Trinidad and Tobago
|
|
Yorktown Assurance Corporation
|
United States
|
Vermont
|
|
|
|
Form S-3ASR:
|
Relating to:
|
|
|
|
|
Reg. No
|
333-194226
|
Marathon Oil Corporation Debt Securities, Common Stock, Preferred Stock, Warrants and Stock Purchase Contracts/Units
|
Form S-8:
|
Relating to:
|
|
|
|
|
Reg. No.
|
33-56828
|
Marathon Oil Company Thrift Plan
|
|
333-29709
|
Marathon Oil Company Thrift Plan
|
|
333-104910
|
Marathon Oil Corporation 2003 Incentive Compensation Plan
|
|
333-143010
|
Marathon Oil Corporation 2007 Incentive Compensation Plan
|
|
333-181301
|
Marathon Oil Corporation 2012 Incentive Compensation Plan
|
|
333-211611
|
Marathon Oil Corporation 2016 Incentive Compensation Plan
|
Form S-3ASR:
|
|
Relating to:
|
|
|
|
|
|
||
Reg. No.
|
|
333-215733
|
|
Marathon Oil Corporation Debt Securities, Common Stock, Preferred Stock, Warrants and Stock Purchase Contracts/Units
|
Reg. No.
|
|
333-194226
|
|
Marathon Oil Corporation Debt Securities, Common Stock, Preferred Stock, Warrants and Stock Purchase Contracts/Units
|
|
|
|
|
|
|
|
|
||
Form S-8:
|
|
Relating to:
|
|
|
|
|
|
||
Reg. No.
|
|
33-56828
|
|
Marathon Oil Company Thrift Plan
|
|
|
333-29709
|
|
Marathon Oil Company Thrift Plan
|
|
|
333-104910
|
|
Marathon Oil Corporation 2003 Incentive Compensation Plan
|
|
|
333-143010
|
|
Marathon Oil Corporation 2007 Incentive Compensation Plan
|
|
|
333-181301
|
|
Marathon Oil Corporation 2012 Incentive Compensation Plan
|
|
|
333-211611
|
|
Marathon Oil Corporation 2016 Incentive Compensation Plan
|
|
|
|
Yours truly,
|
|
|
|
|
|
|
|
GLJ PETROLEUM CONSULTANTS LTD.
|
|
|
|
|
|
|
|
"Originally Signed By"
|
|
|
|
|
|
|
|
Tim R. Freeborn, P. Eng.
|
|
|
|
Vice President
|
Form S-3ASR:
|
|
Relating to:
|
|
|
|
|
|
||
Reg. No.
|
|
333-215733
|
|
Marathon Oil Corporation Debt Securities, Common Stock, Preferred Stock, Warrants and Stock Purchase Contracts/Units
|
Reg. No.
|
|
333-194226
|
|
Marathon Oil Corporation Debt Securities, Common Stock, Preferred Stock, Warrants and Stock Purchase Contracts/Units
|
|
|
|
|
|
|
|
|
||
Form S-8:
|
|
Relating to:
|
|
|
|
|
|
||
Reg. No.
|
|
33-56828
|
|
Marathon Oil Company Thrift Plan
|
|
|
333-29709
|
|
Marathon Oil Company Thrift Plan
|
|
|
333-104910
|
|
Marathon Oil Corporation 2003 Incentive Compensation Plan
|
|
|
333-143010
|
|
Marathon Oil Corporation 2007 Incentive Compensation Plan
|
|
|
333-181301
|
|
Marathon Oil Corporation 2012 Incentive Compensation Plan
|
|
|
333-211611
|
|
Marathon Oil Corporation 2016 Incentive Compensation Plan
|
|
|
|
/s/ Ryder Scott Company, L.P.
|
|
|
|
|
|
|
|
RYDER SCOTT COMPANY, L.P
|
|
|
|
TBPE Firm Registration No. F-1580
|
Form S-3ASR:
|
|
Relating to:
|
|
|
|
|
|
||
Reg. No.
|
|
333-215733
|
|
Marathon Oil Corporation Debt Securities, Common Stock, Preferred Stock, Warrants and Stock Purchase Contracts/Units
|
Reg. No.
|
|
333-194226
|
|
Marathon Oil Corporation Debt Securities, Common Stock, Preferred Stock, Warrants and Stock Purchase Contracts/Units
|
|
|
|
|
|
|
|
|
||
Form S-8:
|
|
Relating to:
|
|
|
|
|
|
||
Reg. No.
|
|
33-56828
|
|
Marathon Oil Company Thrift Plan
|
|
|
333-29709
|
|
Marathon Oil Company Thrift Plan
|
|
|
333-104910
|
|
Marathon Oil Corporation 2003 Incentive Compensation Plan
|
|
|
333-143010
|
|
Marathon Oil Corporation 2007 Incentive Compensation Plan
|
|
|
333-181301
|
|
Marathon Oil Corporation 2012 Incentive Compensation Plan
|
|
|
333-211611
|
|
Marathon Oil Corporation 2016 Incentive Compensation Plan
|
|
|
|
NETHERLAND, SEWELL & ASSOCIATES, INC.
|
|
|
|
|
|
|
|
/s/ Danny D. Simmons
|
|
|
|
By:
|
|
|
|
Danny D. Simmons, P.E.
|
|
|
|
President and Chief Operating Officer
|
1.
|
I have reviewed this Annual Report on Form 10-K for the fiscal year ended December 31, 2016, of Marathon Oil Corporation;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
Date:
|
February 24, 2017
|
|
/s/ Lee M. Tillman
|
|
|
|
Lee M. Tillman
|
|
|
|
President and Chief Executive Officer
|
1.
|
I have reviewed this Annual Report on Form 10-K for the fiscal year ended December 31, 2016, of Marathon Oil Corporation;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
Date:
|
February 24, 2017
|
|
/s/ Patrick J. Wagner
|
|
|
|
Patrick J. Wagner
|
|
|
|
Interim Chief Financial Officer and Vice President- Corporate Development and Strategy
|
(1)
|
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
|
(2)
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
February 24, 2017
|
|
|
|
/s/ Lee M. Tillman
|
|
Lee M. Tillman
|
|
President and Chief Executive Officer
|
|
(1)
|
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
|
(2)
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
February 24, 2017
|
|
|
|
/s/ Patrick J. Wagner
|
|
Patrick J. Wagner
|
|
Interim Chief Financial Officer and Vice President- Corporate Development and Strategy
|
|
\s\ D. John MacDonald
|
D. John MacDonald, P.Eng.
|
APEGA Member Number 32634
|
Vice President
|
|
|
|
|
|
TBPE REGISTERED ENGINEERING FIRM F-1580
|
|
|
|
FAX (713) 651-0849
|
1100 LOUISIANA SUITE 4600
|
|
HOUSTON, TEXAS 77002-5294
|
|
TELEPHONE (713) 651-9191
|
As of December 31, 2016
|
|
|
Total
|
|
|
Proved
|
|
|
Developed
|
Net Reserves of Properties
Audited by Ryder Scott
|
|
|
Synthetic Crude Oil (SCO) Net of Synthetic Gas Consumed in Operations – MM Barrels
|
|
691.9
|
Synthetic Gas Consumed in Operations – SCO Equivalent – MM Barrels
|
|
0.4
|
Synthetic Crude Oil (SCO) Total – MM Barrels
|
|
692.3
|
|
Product
|
Price
Reference
|
Average Benchmark Price
($US/bbl)
|
Average Realized Sales Price
($US/bbl)
|
Geographic Area
|
||||
North America
|
|
|
|
|
Canada
|
Synthetic Crude Oil
|
WTI Cushing
|
41.68
|
35.66
|
(1)
|
completion intervals which are open at the time of the estimate, but which have not started producing;
|
(2)
|
wells which were shut-in for market conditions or pipeline connections; or
|
(3)
|
wells not capable of production for mechanical reasons.
|
(i)
|
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
|
\s\ Daniel R. Olds
|
Daniel R. Olds
|
TBPE License No. 60996
|
Managing Senior Vice President
|
|
|
|
|
|
TBPE REGISTERED ENGINEERING FIRM F-1580
|
|
|
|
FAX (713) 651-0849
|
1100 LOUISIANA SUITE 4600
|
|
HOUSTON, TEXAS 77002-5294
|
|
TELEPHONE (713) 651-9191
|
As of December 31, 2015
|
|
|
Proved
|
|||||||
|
|
|
|
|
|
Total
|
|||
|
|
Developed
|
|
Undeveloped
|
|
Proved
|
|||
Net Reserves of Properties
Audited by Ryder Scott
|
|
|
|
|
|
|
|||
Oil/Condensate - Mbbl
|
|
134,578
|
|
111,497
|
|
246,075
|
|||
Plant Products – Mbbl
|
|
49,127
|
|
37,654
|
|
86,781
|
|||
Gas – MMcf
|
|
259,365
|
|
218,522
|
|
477,887
|
|||
MBOE
|
|
226,933
|
|
185,571
|
|
412,504
|
Geographic Area
|
Product
|
Price
Reference
|
Average Benchmark Prices
|
Average Realized
Prices
|
North America
|
|
|
|
|
|
Oil/Condensate
|
WTI Cushing
|
$50.28/bbl
|
$46.33/bbl
|
Eagle Ford Area
|
NGL
|
Mont Belvieu
|
$17.32/bbl
|
$8.04/bbl
|
|
Gas
|
Henry Hub
|
$2.58/MMBtu
|
$2.48/Mcf
|
(1)
|
completion intervals which are open at the time of the estimate, but which have not started producing;
|
(2)
|
wells which were shut-in for market conditions or pipeline connections; or
|
(3)
|
wells not capable of production for mechanical reasons.
|
(i)
|
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
|
|
|
Gross (100%) Reserves
|
||||
|
|
Gas
|
|
Condensate
|
|
LPG
|
Category
|
|
(BCF)
|
|
(MMBBL)
|
|
(MMBBL)
|
|
|
|
|
|
|
|
Proved Developed (PD)
|
|
1,111
|
|
50
|
|
27
|
Proved (1P)
|
|
1,834
|
|
81
|
|
45
|
|
|
|
|
NETHERLAND, SEWELL & ASSOCIATES, INC.
|
|
|
|
|
Texas Registered Engineering Firm F-2699
|
|
|
|
|
|
|
|
|
By:
|
/s/ C.H. (Scott) Rees III
|
|
|
|
|
C.H. (Scott) Rees III, P.E.
|
|
|
|
|
Chairman and Chief Executive Officer
|
|
|
|
|
|
By:
|
/s/ John R. Cliver
|
|
By:
|
/s/ Zachary R. Long
|
|
John R. Cliver, P.E. 107216
|
|
|
Zachary R. Long, P.G. 11792
|
|
Vice President
|
|
|
Vice President
|
|
Date Signed: December 22, 2016
|
|
|
Date Signed: December 22, 2016
|
(i)
|
Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
|
(ii)
|
Same environment of deposition;
|
(iii)
|
Similar geological structure; and
|
(iv)
|
Same drive mechanism.
|
(i)
|
Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
|
(ii)
|
Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
|
(i)
|
Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.
|
(ii)
|
Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
|
(iii)
|
Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.
|
(iv)
|
Provide improved recovery systems.
|
(i)
|
Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.
|
(ii)
|
Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.
|
(iii)
|
Dry hole contributions and bottom hole contributions.
|
(iv)
|
Costs of drilling and equipping exploratory wells.
|
(v)
|
Costs of drilling exploratory-type stratigraphic test wells.
|
(i)
|
Oil and gas producing activities include:
|
(A)
|
The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;
|
(B)
|
The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;
|
(C)
|
The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:
|
(1)
|
Lifting the oil and gas to the surface; and
|
(2)
|
Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and
|
(D)
|
Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.
|
a.
|
The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and
|
b.
|
In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.
|
(ii)
|
Oil and gas producing activities do not include:
|
(A)
|
Transporting, refining, or marketing oil and gas;
|
(B)
|
Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;
|
(C)
|
Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or
|
(D)
|
Production of geothermal steam.
|
(i)
|
When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods
|
(ii)
|
Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
|
(iii)
|
Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
|
(iv)
|
The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
|
(v)
|
Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
|
(vi)
|
Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.
|
(i)
|
When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
|
(ii)
|
Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
|
(iii)
|
Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
|
(iv)
|
See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.
|
(i)
|
Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:
|
(A)
|
Costs of labor to operate the wells and related equipment and facilities.
|
(B)
|
Repairs and maintenance.
|
(C)
|
Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.
|
(D)
|
Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.
|
(E)
|
Severance taxes.
|
(ii)
|
Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.
|
(i)
|
The area of the reservoir considered as proved includes:
|
(A)
|
The area identified by drilling and limited by fluid contacts, if any, and
|
(B)
|
Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
|
(ii)
|
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
|
(iii)
|
Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
|
(iv)
|
Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
|
(A)
|
Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
|
(B)
|
The project has been approved for development by all necessary parties and entities, including governmental entities.
|
(v)
|
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
|
(i)
|
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
|
(ii)
|
Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
|
(iii)
|
Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
|