þ
|
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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¨
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|
Delaware
|
|
76-0146568
|
(State or other jurisdiction of incorporation or organization)
|
|
(I.R.S. Employer Identification No.)
|
1201 Lake Robbins Drive, The Woodlands, Texas
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|
77380-1046
|
(Address of principal executive offices)
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(Zip Code)
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Title of each class
|
|
Name of each exchange on which registered
|
Common Stock, par value $0.10 per share
|
|
New York Stock Exchange
|
7.50% Tangible Equity Units
|
|
New York Stock Exchange
|
Title of Class
|
|
Number of Shares Outstanding
|
Common Stock, par value $0.10 per share
|
|
532,487,194
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|
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Page
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PART I
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Items 1 and 2.
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Regulatory and Environmental
Matters
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Item 1A.
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Item 1B.
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Item 3.
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Item 4.
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PART II
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Item 5.
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Item 6.
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Item 7.
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Item 7A.
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Item 8.
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Item 9.
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Item 9A.
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Item 9B.
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PART III
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Item 10.
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Item 11.
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Item 12.
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Item 13.
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Item 14.
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PART IV
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Item 15.
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Item 16.
|
|
Oil
(MMBbls)
|
|
Natural Gas
(Bcf)
|
|
NGLs
(MMBbls)
|
|
Total
(MMBOE)
|
||||
December 31, 2017
|
|
|
|
|
|
|
|
||||
Proved
|
|
|
|
|
|
|
|
||||
Developed
|
|
|
|
|
|
|
|
||||
United States
|
361
|
|
|
2,640
|
|
|
176
|
|
|
977
|
|
International
|
136
|
|
|
24
|
|
|
10
|
|
|
150
|
|
Undeveloped
|
|
|
|
|
|
|
|
||||
United States
|
140
|
|
|
553
|
|
|
56
|
|
|
288
|
|
International
|
21
|
|
|
13
|
|
|
1
|
|
|
24
|
|
Total proved
|
658
|
|
|
3,230
|
|
|
243
|
|
|
1,439
|
|
|
|
|
|
|
|
|
|
||||
December 31, 2016
|
|
|
|
|
|
|
|
||||
Proved
|
|
|
|
|
|
|
|
||||
Developed
|
|
|
|
|
|
|
|
||||
United States
|
360
|
|
|
3,637
|
|
|
193
|
|
|
1,159
|
|
International
|
147
|
|
|
25
|
|
|
15
|
|
|
166
|
|
Undeveloped
|
|
|
|
|
|
|
|
||||
United States
|
181
|
|
|
762
|
|
|
75
|
|
|
383
|
|
International
|
14
|
|
|
—
|
|
|
—
|
|
|
14
|
|
Total proved
|
702
|
|
|
4,424
|
|
|
283
|
|
|
1,722
|
|
|
|
|
|
|
|
|
|
||||
December 31, 2015
|
|
|
|
|
|
|
|
||||
Proved
|
|
|
|
|
|
|
|
||||
Developed
|
|
|
|
|
|
|
|
||||
United States
|
332
|
|
|
5,184
|
|
|
257
|
|
|
1,453
|
|
International
|
159
|
|
|
30
|
|
|
15
|
|
|
179
|
|
Undeveloped
|
|
|
|
|
|
|
|
||||
United States
|
193
|
|
|
807
|
|
|
68
|
|
|
396
|
|
International
|
29
|
|
|
—
|
|
|
—
|
|
|
29
|
|
Total proved
|
713
|
|
|
6,021
|
|
|
340
|
|
|
2,057
|
|
MMBOE
|
2017
|
|
2016
|
|
2015
|
|||
Proved Reserves
|
|
|
|
|
|
|||
January 1
|
1,722
|
|
|
2,057
|
|
|
2,858
|
|
Reserves additions and revisions
|
|
|
|
|
|
|||
Discoveries and extensions
|
114
|
|
|
40
|
|
|
29
|
|
Infill-drilling additions
(1)
|
71
|
|
|
69
|
|
|
89
|
|
Drilling-related reserves additions and revisions
|
185
|
|
|
109
|
|
|
118
|
|
Other non-price-related revisions
(1)
|
59
|
|
|
191
|
|
|
289
|
|
Net organic reserves additions
|
244
|
|
|
300
|
|
|
407
|
|
Acquisition of proved reserves in place
|
3
|
|
|
97
|
|
|
1
|
|
Price-related revisions
(1)
|
92
|
|
|
(147
|
)
|
|
(624
|
)
|
Total reserves additions and revisions
|
339
|
|
|
250
|
|
|
(216
|
)
|
Sales in place
|
(379
|
)
|
|
(294
|
)
|
|
(279
|
)
|
Production
|
(243
|
)
|
|
(291
|
)
|
|
(306
|
)
|
December 31
|
1,439
|
|
|
1,722
|
|
|
2,057
|
|
Proved Developed Reserves
|
|
|
|
|
|
|||
January 1
|
1,325
|
|
|
1,632
|
|
|
1,969
|
|
December 31
|
1,127
|
|
|
1,325
|
|
|
1,632
|
|
(1)
|
Combined and reported as revisions of prior estimates in the Company’s
Supplemental Information on Oil and Gas Exploration and Production Activities (Supplemental Information)
under Item 8 of this Form 10-K. Reserves related to infill-drilling additions are treated as positive revisions. Price-related revisions reflect the impact of current prices on the reserves balance at the beginning of each year. Other non-price-related revisions reflect the net change of performance and cost updates, updates to development plans, and all other year-end updates.
|
MMBOE
|
|
|
PUDs at January 1, 2017
|
397
|
|
Revisions of prior estimates
|
103
|
|
Extensions, discoveries, and other additions
|
22
|
|
Conversions to developed
|
(132
|
)
|
Purchases
|
1
|
|
Sales
|
(79
|
)
|
PUDs at December 31, 2017
|
312
|
|
•
|
Performance
The Company experienced an overall increase in PUDs of 32 MMBOE due to performance. Upward revisions of 39 MMBOE were driven primarily by performance improvements in the DJ and Delaware basin areas. Downward revisions of 7 MMBOE were primarily due to performance based reductions in various areas in the Gulf of Mexico.
|
•
|
Infill-drilling activities
The Company added 64 MMBOE of PUDs associated with infill-drilling activities, of which 46 MMBOE was in the DJ basin, 13 MMBOE in the Lucius and Holstein areas in the Gulf of Mexico and the remaining in the Ghana Jubilee field.
|
•
|
Development plan updates
The majority of revisions associated with updates to development plans occurred in the DJ basin due to ongoing optimization of development activity.
|
|
Sales Volumes
|
|
Average Sales Prices
(1)
|
|
Average
Production Costs
(2)
(Per BOE)
|
||||||||||||||||||
|
Oil
(MMBbls)
|
|
Natural Gas
(Bcf)
|
|
NGLs
(MMBbls)
|
|
Barrels of Oil
Equivalent
(MMBOE)
|
|
Oil
(Per Bbl)
|
|
Natural Gas
(Per Mcf)
|
|
NGLs
(Per Bbl)
|
|
|||||||||
2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
DJ basin
|
31
|
|
|
212
|
|
|
21
|
|
|
88
|
|
|
49.73
|
|
|
2.55
|
|
|
27.46
|
|
|
10.23
|
|
Other United States
|
66
|
|
|
266
|
|
|
13
|
|
|
123
|
|
|
49.57
|
|
|
3.03
|
|
|
32.24
|
|
|
9.38
|
|
Total United States
|
97
|
|
|
478
|
|
|
34
|
|
|
211
|
|
|
49.62
|
|
|
2.82
|
|
|
29.24
|
|
|
9.73
|
|
International
|
32
|
|
|
—
|
|
|
2
|
|
|
34
|
|
|
53.77
|
|
|
—
|
|
|
35.64
|
|
|
7.01
|
|
Total
|
129
|
|
|
478
|
|
|
36
|
|
|
245
|
|
|
50.66
|
|
|
2.82
|
|
|
29.54
|
|
|
9.34
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
DJ basin
|
33
|
|
|
214
|
|
|
20
|
|
|
89
|
|
|
40.27
|
|
|
2.00
|
|
|
18.26
|
|
|
8.41
|
|
Other United States
|
52
|
|
|
552
|
|
|
24
|
|
|
168
|
|
|
38.29
|
|
|
2.06
|
|
|
20.21
|
|
|
6.80
|
|
Total United States
|
85
|
|
|
766
|
|
|
44
|
|
|
257
|
|
|
39.06
|
|
|
2.04
|
|
|
19.32
|
|
|
7.36
|
|
International
|
31
|
|
|
—
|
|
|
2
|
|
|
33
|
|
|
43.93
|
|
|
—
|
|
|
25.63
|
|
|
7.93
|
|
Total
|
116
|
|
|
766
|
|
|
46
|
|
|
290
|
|
|
40.34
|
|
|
2.04
|
|
|
19.64
|
|
|
7.42
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
DJ basin
|
35
|
|
|
176
|
|
|
16
|
|
|
81
|
|
|
44.88
|
|
|
2.31
|
|
|
15.65
|
|
|
8.21
|
|
Other United States
|
50
|
|
|
676
|
|
|
29
|
|
|
191
|
|
|
45.08
|
|
|
2.37
|
|
|
17.83
|
|
|
8.55
|
|
Total United States
|
85
|
|
|
852
|
|
|
45
|
|
|
272
|
|
|
45.00
|
|
|
2.36
|
|
|
17.03
|
|
|
8.45
|
|
International
|
31
|
|
|
—
|
|
|
2
|
|
|
33
|
|
|
51.68
|
|
|
—
|
|
|
29.85
|
|
|
7.22
|
|
Total
|
116
|
|
|
852
|
|
|
47
|
|
|
305
|
|
|
46.79
|
|
|
2.36
|
|
|
17.61
|
|
|
8.31
|
|
(1)
|
Excludes the impact of commodity derivatives.
|
(2)
|
Excludes ad valorem and severance taxes.
|
|
Developed
Lease
|
|
Undeveloped
Lease
|
|
Fee
Mineral
(1)
|
|
Total
|
||||||||||||||||
thousands of acres
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||||
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Onshore
|
2,417
|
|
|
1,486
|
|
|
1,797
|
|
|
681
|
|
|
9,891
|
|
|
8,192
|
|
|
14,105
|
|
|
10,359
|
|
Offshore
|
352
|
|
|
198
|
|
|
1,483
|
|
|
1,098
|
|
|
—
|
|
|
—
|
|
|
1,835
|
|
|
1,296
|
|
Total United States
|
2,769
|
|
|
1,684
|
|
|
3,280
|
|
|
1,779
|
|
|
9,891
|
|
|
8,192
|
|
|
15,940
|
|
|
11,655
|
|
International
|
636
|
|
|
138
|
|
|
39,440
|
|
|
31,690
|
|
|
—
|
|
|
—
|
|
|
40,076
|
|
|
31,828
|
|
Total
|
3,405
|
|
|
1,822
|
|
|
42,720
|
|
|
33,469
|
|
|
9,891
|
|
|
8,192
|
|
|
56,016
|
|
|
43,483
|
|
(1)
|
The Company’s fee mineral acreage is primarily undeveloped.
|
|
Net Exploratory
|
|
Net Development
|
|
Total
|
|||||||||||||||
|
Productive
|
|
Dry Holes
|
|
Total
|
|
Productive
|
|
Dry Holes
|
|
Total
|
|
||||||||
2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
United States
|
6.6
|
|
|
3.6
|
|
|
10.2
|
|
|
359.1
|
|
|
2.4
|
|
|
361.5
|
|
|
371.7
|
|
International
|
—
|
|
|
7.3
|
|
|
7.3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7.3
|
|
Total
|
6.6
|
|
|
10.9
|
|
|
17.5
|
|
|
359.1
|
|
|
2.4
|
|
|
361.5
|
|
|
379.0
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
United States
|
3.7
|
|
|
1.2
|
|
|
4.9
|
|
|
322.1
|
|
|
—
|
|
|
322.1
|
|
|
327.0
|
|
International
|
—
|
|
|
1.8
|
|
|
1.8
|
|
|
2.9
|
|
|
—
|
|
|
2.9
|
|
|
4.7
|
|
Total
|
3.7
|
|
|
3.0
|
|
|
6.7
|
|
|
325.0
|
|
|
—
|
|
|
325.0
|
|
|
331.7
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
United States
|
16.0
|
|
|
—
|
|
|
16.0
|
|
|
573.1
|
|
|
13.8
|
|
|
586.9
|
|
|
602.9
|
|
International
|
2.4
|
|
|
0.4
|
|
|
2.8
|
|
|
1.8
|
|
|
—
|
|
|
1.8
|
|
|
4.6
|
|
Total
|
18.4
|
|
|
0.4
|
|
|
18.8
|
|
|
574.9
|
|
|
13.8
|
|
|
588.7
|
|
|
607.5
|
|
|
Wells in the process of drilling
or in active completion
|
|
Wells suspended or
waiting on completion
(1)
|
||||||||
|
Exploration
|
|
Development
|
|
Exploration
|
|
Development
(2)
|
||||
United States
|
|
|
|
|
|
|
|
||||
Gross
|
—
|
|
|
23
|
|
|
14
|
|
|
543
|
|
Net
|
—
|
|
|
20.4
|
|
|
8.6
|
|
|
396.2
|
|
International
|
|
|
|
|
|
|
|
||||
Gross
|
—
|
|
|
—
|
|
|
28
|
|
|
15
|
|
Net
|
—
|
|
|
—
|
|
|
7.8
|
|
|
3.5
|
|
Total
|
|
|
|
|
|
|
|
||||
Gross
|
—
|
|
|
23
|
|
|
42
|
|
|
558
|
|
Net
|
—
|
|
|
20.4
|
|
|
16.4
|
|
|
399.7
|
|
(1)
|
Wells suspended or waiting on completion include exploration and development wells where drilling has occurred, but the wells are awaiting the completion of hydraulic fracturing or other completion activities or the resumption of drilling in the future.
|
(2)
|
There were 107 MMBOE of PUDs primarily assigned to U.S. onshore development wells suspended or waiting on completion at
December 31, 2017
. The Company expects to convert these reserves to developed status within five years of their initial disclosure.
|
|
Oil Wells
(1)
|
|
Gas Wells
(1)
|
||
United States
|
|
|
|
||
Gross
|
3,571
|
|
|
8,574
|
|
Net
|
2,309.2
|
|
|
7,182.0
|
|
International
|
|
|
|
||
Gross
|
208
|
|
|
9
|
|
Net
|
37.3
|
|
|
2.2
|
|
Total
|
|
|
|
||
Gross
|
3,779
|
|
|
8,583
|
|
Net
|
2,346.5
|
|
|
7,184.2
|
|
(1)
|
Includes wells containing multiple completions as follows:
|
Gross
|
411
|
|
|
2,997
|
|
Net
|
355.1
|
|
|
2,697.1
|
|
Area
|
|
Miles of
Pipelines
|
|
Total
Horsepower
|
|
2017 Average Net
Throughput (MMcf/d)
|
|
2017 Average Net
Throughput (MBbls/d)
|
||||
DJ basin
|
|
4,680
|
|
|
319,200
|
|
|
950
|
|
|
50
|
|
Delaware basin
|
|
1,300
|
|
|
316,100
|
|
|
810
|
|
|
30
|
|
Greater Natural Buttes
|
|
40
|
|
|
74,900
|
|
|
420
|
|
|
10
|
|
Wyoming
|
|
4,750
|
|
|
173,300
|
|
|
800
|
|
|
—
|
|
Eagleford
|
|
870
|
|
|
200,100
|
|
|
450
|
|
|
30
|
|
Other
|
|
870
|
|
|
34,600
|
|
|
80
|
|
|
80
|
|
Total
|
|
12,510
|
|
|
1,118,200
|
|
|
3,510
|
|
|
200
|
|
Area
|
|
Miles of
Pipelines |
|
Total
Horsepower |
|
2017 Average Net
Throughput (MMcf/d)
|
|
2017 Average Net
Throughput (MBbls/d)
|
||||
DJ basin
|
|
1,050
|
|
|
50,200
|
|
|
190
|
|
|
110
|
|
Delaware basin
|
|
540
|
|
|
44,500
|
|
|
130
|
|
|
80
|
|
Greater Natural Buttes
|
|
1,180
|
|
|
152,100
|
|
|
330
|
|
|
—
|
|
Other
|
|
300
|
|
|
7,000
|
|
|
—
|
|
|
10
|
|
Total
|
|
3,070
|
|
|
253,800
|
|
|
650
|
|
|
200
|
|
•
|
the U.S. Clean Air Act, which restricts the emission of air pollutants from many sources, imposes various pre-construction, monitoring, and reporting requirements, which the EPA has relied upon as authority for adopting climate change regulatory initiatives relating to greenhouse gas (GHG) emissions
|
•
|
the U.S. Federal Water Pollution Control Act, also known as the federal Clean Water Act, which regulates discharges of pollutants from facilities to state and federal waters and establishes the extent to which waterways are subject to federal jurisdiction and rulemaking as protected waters of the United States
|
•
|
the U.S. Oil Pollution Act of 1990, which subjects owners and operators of vessels, onshore facilities, and pipelines, as well as lessees or permittees of areas in which offshore facilities are located, to liability for removal costs and damages arising from an oil spill in waters of the United States
|
•
|
U.S. Department of the Interior regulations, which relate to offshore oil and natural-gas operations in U.S. waters and impose obligations for establishing financial assurances for decommissioning activities, liabilities for pollution cleanup costs resulting from operations, and potential liabilities for pollution damages
|
•
|
the Comprehensive Environmental Response, Compensation and Liability Act of 1980, which imposes liability on generators, transporters, and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur
|
•
|
the U.S. Resource Conservation and Recovery Act, which governs the generation, treatment, storage, transport, and disposal of solid wastes, including hazardous wastes
|
•
|
the U.S. Safe Drinking Water Act, which ensures the quality of the nation’s public drinking water through adoption of drinking water standards and control over the injection of waste fluids into below-ground formations that may adversely affect drinking water sources
|
•
|
the U.S. Emergency Planning and Community Right-to-Know Act, which requires facilities to implement a safety hazard communication program and disseminate information to employees, local emergency planning committees, and response departments on toxic chemical uses and inventories
|
•
|
the U.S. Occupational Safety and Health Act, which establishes workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures
|
•
|
the Endangered Species Act, which restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas
|
•
|
the National Environmental Policy Act, which requires federal agencies, including the Department of the Interior, to evaluate major agency actions having the potential to impact the environment and that may require the preparation of environmental assessments and more detailed environmental impact statements that may be made available for public review and comment
|
•
|
the U.S. Department of Transportation regulations, which relate to advancing the safe transportation of energy and hazardous materials and emergency response preparedness
|
Name
|
|
Age at
January 31, 2018
|
|
Position
|
R. A. Walker
|
|
60
|
|
Chairman, President and Chief Executive Officer
|
Robert G. Gwin
|
|
54
|
|
Executive Vice President, Finance and Chief Financial Officer
|
Daniel E. Brown
|
|
42
|
|
Executive Vice President, U.S. Onshore Operations
|
Mitchell W. Ingram
|
|
55
|
|
Executive Vice President, International & Deepwater Operations and Project Management
|
Ernest A. Leyendecker
|
|
57
|
|
Executive Vice President, Exploration
|
Robert K. Reeves
|
|
60
|
|
Executive Vice President, Law and Chief Administrative Officer
|
Christopher O. Champion
|
|
48
|
|
Senior Vice President, Chief Accounting Officer and Controller
|
•
|
the Company’s assumptions about energy markets
|
•
|
production and sales volume levels
|
•
|
levels of oil, natural-gas, and NGLs reserves
|
•
|
operating results
|
•
|
competitive conditions
|
•
|
technology
|
•
|
availability of capital resources, levels of capital expenditures, and other contractual obligations
|
•
|
supply and demand for, the price of, and the commercialization and transporting of oil, natural gas, NGLs, and other products or services
|
•
|
volatility in the commodity-futures market
|
•
|
weather
|
•
|
inflation
|
•
|
availability of goods and services, including unexpected changes in costs
|
•
|
drilling and other operational risks
|
•
|
processing volumes, pipeline throughput, and produced water disposal
|
•
|
general economic conditions, nationally, internationally, or in the jurisdictions in which the Company is, or in the future may be, doing business
|
•
|
the Company’s inability to timely obtain or maintain permits or other governmental approvals, including those necessary for drilling and/or development projects
|
•
|
legislative or regulatory changes, including changes relating to hydraulic fracturing; retroactive royalty or production tax regimes; deepwater drilling and permitting regulations; derivatives reform; changes in state, federal, and foreign income taxes; environmental regulation, including regulations related to climate change; environmental risks; and liability under international, provincial, federal, regional, state, tribal, local, and foreign environmental laws and regulations
|
•
|
civil or political unrest or acts of terrorism in a region or country
|
•
|
the creditworthiness and performance of the Company’s counterparties, including financial institutions, operating partners, and other parties
|
•
|
volatility in the securities, capital, or credit markets and related risks such as general credit, liquidity, and interest-rate risk
|
•
|
the Company’s ability to successfully monetize select assets, repay or refinance its debt, and the impact of changes in the Company’s credit ratings
|
•
|
the Company’s ability to successfully complete its share-repurchase program
|
•
|
uncertainties associated with acquired properties and businesses
|
•
|
disruptions in international oil and NGLs cargo shipping activities
|
•
|
physical, digital, cyber, internal, and external security breaches
|
•
|
supply and demand, technological, political, governmental, and commercial conditions associated with long-term development and production projects in domestic and international locations
|
•
|
the outcome of pending and future regulatory, legislative, or other proceedings or investigations, including the investigation by the NTSB related to the Company’s operations in Colorado, and continued or additional disruptions in operations that may occur as the Company complies with regulatory orders or other state or local changes in laws or regulations in Colorado
|
•
|
other factors discussed below and elsewhere in this Form 10-K, and in the Company’s other public filings, press releases, and discussions with Company management
|
•
|
the domestic and worldwide supply of, and demand for, oil, natural gas, and NGLs
|
•
|
volatility and trading patterns in the commodity-futures markets
|
•
|
the cost of exploring for, developing, producing, transporting, and marketing oil, natural gas, and NGLs
|
•
|
the level of global oil and natural-gas inventories
|
•
|
weather conditions
|
•
|
the level of U.S. exports of oil, LNG, or NGLs
|
•
|
the ability of the members of OPEC and other producing nations to agree to and maintain production levels
|
•
|
the worldwide military and political environment, civil and political unrest worldwide, including in Africa and the Middle East, uncertainty or instability resulting from the escalation or additional outbreak of armed hostilities, or acts of terrorism in the United States or elsewhere
|
•
|
the effect of worldwide energy conservation and environmental protection efforts
|
•
|
the price and availability of alternative and competing fuels
|
•
|
the level of foreign imports of oil, natural gas, and NGLs
|
•
|
domestic and foreign governmental laws, regulations, and taxes
|
•
|
shareholder activism or activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development, and production of oil and natural gas
|
•
|
the proximity to, and capacity of, natural-gas pipelines and other transportation facilities
|
•
|
general economic conditions worldwide
|
•
|
adversely affect our financial condition, liquidity, ability to finance planned capital expenditures, and results of operations
|
•
|
reduce the amount of oil, natural gas, and NGLs that we can produce economically
|
•
|
cause us to delay or postpone some of our capital projects
|
•
|
reduce our revenues, operating income, or cash flows
|
•
|
reduce the amounts of our estimated proved oil, natural-gas, and NGLs reserves
|
•
|
reduce the carrying value of our oil, natural-gas, and midstream properties due to recognizing additional impairments of proved properties, unproved properties, exploration assets, and midstream facilities
|
•
|
reduce the standardized measure of discounted future net cash flows relating to oil, natural-gas, and NGLs reserves
|
•
|
limit our access to, or increasing the cost of, sources of capital such as equity and long-term debt
|
•
|
adversely affect the ability of our partners to fund their working interest capital requirements
|
•
|
issuance of permits in connection with exploration, drilling, production, produced water disposal, and other midstream activities
|
•
|
drilling activities on certain lands lying within wilderness, wetlands, and other protected areas
|
•
|
types, quantities, and concentrations of emissions, discharges, and authorized releases
|
•
|
generation, management, and disposition of waste materials
|
•
|
offshore oil and natural-gas operations and decommissioning of abandoned facilities
|
•
|
reclamation and abandonment of wells and facility sites
|
•
|
remediation of contaminated sites
|
•
|
protection of endangered species
|
•
|
Ground-Level Ozone Standards.
In October 2015, the EPA issued a rule under the Clean Air Act, lowering the National Ambient Air Quality Standard for ground-level ozone from 75 parts per billion to 70 parts per billion under both the primary and secondary standards to provide requisite protection of public health and welfare, respectively. The EPA did not meet the October 1, 2017 deadline for designating non-attainment areas but, on November 6, 2017, issued final designations for areas in the United States that are in attainment with the 70 parts per billion standard, representing approximately 85% of the U.S. counties that became effective on January 18, 2018. For the remaining areas of the United States, the EPA has not yet prepared final designations, but is expected to do so in a separate future action in the first half of 2018. Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modified facilities in new designated non-attainment areas. Also, states that are designated as non-attainment are expected to implement more stringent regulations, which could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs.
|
•
|
Reduction of Methane Emissions by the Oil and Gas Industry.
In June 2016, the EPA published a final rule establishing new emissions standards for methane and additional standards for volatile organic compounds from certain new, modified, and reconstructed oil and natural-gas production and natural-gas processing and transmission facilities. The EPA’s rule is under the New Source Performance Standards, Subpart OOOOa, that requires certain new, modified, or reconstructed facilities in the oil and natural-gas sector to reduce these methane gas and volatile organic compound emissions. These Subpart OOOOa standards would expand previously issued New Source Performance Standards, Subpart OOOO, published by the EPA in 2012 by using certain equipment-specific emissions control practices with respect to, among other things, hydraulically fractured oil and natural-gas well completions, fugitive emissions from well sites and compressors, and pneumatic pumps. However, in June 2017, the EPA published a proposed rule to stay certain portions of the June 2016 standards for two years and re-evaluate the entirety of the 2016 standards but the EPA has not yet published a final rule and, as a result, the June 2016 standards remain in effect, but future implementation of the standards are uncertain at this time. Furthermore, in June 2017, the Bureau of Land Management (BLM) stayed a rule published in November 2016 imposing requirements to reduce methane emissions from venting, flaring, and leaking on public lands. On October 4, 2017, the U.S. District Court for the Northern District of California struck down the June 2017 stay. However, on December 8, 2017, the BLM published a final rule that will temporarily suspend certain requirements contained in the November 2016 final rule until January 17, 2019. The December 2017 compliance extension was challenged by non-governmental organizations and several states on December 19, 2017. Notwithstanding the current uncertainty, we have taken measures to enter into a voluntary regime, together with certain other oil and natural gas exploration and production operators, to reduce methane emissions. At the state level, some states are considering and others have issued requirements, including Colorado where we conduct operations, for the performance of leak-detection programs that identify and repair methane leaks at certain oil and natural-gas sources. Compliance with these rules or future methane regulations will, among other things, require installation of new emission controls on some of our equipment and increase our capital expenditures and operating costs.
|
•
|
Induced Seismic Activity Associated with Oilfield Disposal Wells.
We dispose of wastewater generated from oil and natural-gas production operations directly or through the use of third parties. The legal requirements related to the disposal of wastewater in underground injections wells are subject to change based on concerns of the public or governmental authorities regarding such disposal activities. One such concern relates to recent seismic events near injection wells used for the disposal of produced water resulting from oil and natural-gas activities. In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Colorado developed and follows guidance when issuing underground injection control permits to limit the maximum injection pressure, rate, and volume of water. Oklahoma has issued rules for wastewater disposal wells that imposed certain permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults and also, from time to time, is developing and implementing plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. The Texas Railroad Commission has also adopted similar permitting, operating, and reporting rules for disposal wells. In addition, ongoing class action lawsuits, to which we are not currently a party, allege that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells by us or by commercial disposal well vendors whom we may use from time to time to dispose of wastewater, which could have a material adverse effect on our capital expenditures and operating costs, financial condition, and results of operations.
|
•
|
Reduction of Greenhouse Gas Emissions.
The U.S. Congress and the EPA, in addition to some state and regional authorities, have in recent years considered legislation or regulations to reduce emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. In the absence of federal GHG-limiting legislation, the EPA has determined that GHG emissions present a danger to public health and the environment and has adopted regulations that, among other things, restrict emissions of GHGs under existing provisions of the Clean Air Act and may require the installation of “best available control technology” to limit emissions of GHGs from any new or significantly modified facilities that we may seek to construct in the future if they would otherwise emit large volumes of GHGs together with other criteria pollutants. Also, certain of our operations are subject to EPA rules requiring the monitoring and annual reporting of GHG emissions from specified onshore and offshore production sources. In December 2015, the United States joined the international community at the 21
st
Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that prepared an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. Although this international agreement does not create any binding obligations for nations to limit their GHG emissions, it does include pledges to voluntarily limit or reduce future emissions. In August 2017, the U.S. State Department informed the United Nations of the intent of the United States to withdraw from the Paris Climate Agreement, which would result in an effective exit date of November 2020. Notwithstanding any withdrawal from this agreement, the implementation of substantial limitations on GHG emissions in areas where we conduct operations could adversely affect demand for the oil and natural gas we produce and lower the value of our reserves.
|
•
|
increasing our vulnerability to general adverse economic and industry conditions
|
•
|
limiting our ability to fund future working capital and capital expenditures, to engage in future acquisitions or development activities, or to otherwise fully realize the value of our assets and opportunities because of the need to dedicate a substantial portion of our cash flows from operations to payments on our debt or to comply with any restrictive terms of our debt
|
•
|
limiting our flexibility in planning for, or reacting to, changes in the industry in which we operate
|
•
|
placing us at a competitive disadvantage compared to our competitors that have less debt and/or fewer financial commitments
|
•
|
estimated future production from an area is consistent with historical production from similar producing areas
|
•
|
assumed effects of regulation by governmental agencies and court rulings
|
•
|
assumptions concerning future oil, natural-gas, and NGLs prices, future operating costs, and capital expenditures
|
•
|
estimates of future severance and excise taxes, workover costs, and remedial costs
|
•
|
hurricanes and other adverse weather conditions
|
•
|
geological complexities and water depths associated with such operations
|
•
|
limited number of partners available to participate in projects
|
•
|
oilfield service costs and availability
|
•
|
compliance with environmental, safety, and other laws and regulations
|
•
|
terrorist attacks or piracy
|
•
|
remediation and other costs and regulatory changes resulting from oil spills or releases of hazardous materials
|
•
|
failure of equipment or facilities
|
•
|
response capabilities for personnel, equipment, or environmental incidents
|
•
|
loss of revenue, property, and equipment or delays in operations as a result of hazards such as expropriation, war, piracy, acts of terrorism, insurrection, civil unrest, and other political risks, including tension and confrontations among political parties
|
•
|
transparency issues in general and, more specifically, the U.S. Foreign Corrupt Practices Act, the U.K. Bribery Act, and other anti-corruption compliance laws and issues
|
•
|
increases in taxes and governmental royalties
|
•
|
unilateral renegotiation of contracts by governmental entities
|
•
|
redefinition of international boundaries or boundary disputes
|
•
|
difficulties enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations
|
•
|
changes in laws and policies governing operations of foreign-based companies
|
•
|
foreign-exchange restrictions
|
•
|
international monetary fluctuations and changes in the relative value of the U.S. dollar as compared to the currencies of other countries in which we conduct business
|
•
|
our production is less than the notional volumes
|
•
|
a widening of price basis differentials occurs between delivery points for our production and the delivery point assumed in the derivative arrangement
|
•
|
the counterparties to our hedging or other price-risk management contracts fail to perform under those arrangements
|
•
|
a sudden unexpected event materially impacts oil, natural-gas, or NGLs prices
|
•
|
project approvals and funding by joint-venture partners
|
•
|
timely issuance of permits and licenses by governmental agencies or legislative and other governmental approvals
|
•
|
weather conditions
|
•
|
availability of qualified personnel
|
•
|
civil and political environment of, and existing infrastructure in, the country or region in which the project is located
|
•
|
manufacturing and delivery schedules of critical equipment
|
•
|
commercial arrangements for pipelines, tankers, and related equipment to transport and market hydrocarbons
|
•
|
unexpected drilling conditions
|
•
|
pressure or irregularities in formations
|
•
|
equipment failures or accidents
|
•
|
fires, explosions, blowouts, and surface cratering
|
•
|
marine risks such as capsizing, collisions, and hurricanes
|
•
|
difficulty identifying and retaining qualified personnel
|
•
|
title problems
|
•
|
other adverse weather conditions
|
•
|
lack of availability or delays in the delivery of technology, equipment, or resources for operations
|
•
|
the validity of our assumptions about, among other things, reserves, estimated production, revenues, capital expenditures, operating expenses, and costs
|
•
|
the assumption of environmental, decommissioning, and other liabilities, and losses or costs for which we are not indemnified or for which our indemnity is inadequate
|
•
|
a failure to attain or maintain compliance with environmental, safety, and other governmental regulations
|
Item 5.
|
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
|
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
||||||||
2017
|
|
|
|
|
|
|
|
||||||||
Market Price
|
|
|
|
|
|
|
|
||||||||
High
|
$
|
72.32
|
|
|
$
|
64.15
|
|
|
$
|
50.16
|
|
|
$
|
54.45
|
|
Low
|
$
|
59.34
|
|
|
$
|
43.45
|
|
|
$
|
39.96
|
|
|
$
|
46.75
|
|
Dividends
|
$
|
0.05
|
|
|
$
|
0.05
|
|
|
$
|
0.05
|
|
|
$
|
0.05
|
|
2016
|
|
|
|
|
|
|
|
||||||||
Market Price
|
|
|
|
|
|
|
|
||||||||
High
|
$
|
50.39
|
|
|
$
|
57.00
|
|
|
$
|
63.84
|
|
|
$
|
73.33
|
|
Low
|
$
|
28.16
|
|
|
$
|
43.52
|
|
|
$
|
50.23
|
|
|
$
|
58.59
|
|
Dividends
|
$
|
0.05
|
|
|
$
|
0.05
|
|
|
$
|
0.05
|
|
|
$
|
0.05
|
|
Plan Category
|
|
(a)
Number of securities
to be issued upon
exercise of
outstanding options,
warrants, and rights
|
|
(b)
Weighted-average
exercise price of
outstanding
options, warrants,
and rights
|
|
(c)
Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in column(a))
|
||||
Equity compensation plans approved by security holders
|
|
6,567,944
|
|
|
$
|
71.44
|
|
|
27,094,327
|
|
Equity compensation plans not approved by security holders
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total
|
|
6,567,944
|
|
|
$
|
71.44
|
|
|
27,094,327
|
|
Period
|
|
Total
number of
shares
purchased
(1)
|
|
Average
price paid
per share
|
|
Total number of
shares purchased
as part of publicly
announced plans
or programs
(2)
|
|
Approximate dollar
value of shares that
may yet be
purchased under the
plans or programs
(2)
|
||||||
October 1-31, 2017
(3)
|
|
15,698,241
|
|
|
$
|
48.13
|
|
|
15,679,096
|
|
|
$
|
1,745,327,838
|
|
November 1-30, 2017
|
|
44,950
|
|
|
$
|
51.09
|
|
|
—
|
|
|
$
|
1,745,327,838
|
|
December 1-31, 2017
(3)
|
|
6,239,532
|
|
|
$
|
48.84
|
|
|
6,236,398
|
|
|
$
|
1,440,745,052
|
|
Total
|
|
21,982,723
|
|
|
$
|
48.34
|
|
|
21,915,494
|
|
|
|
|
(1)
|
During the fourth quarter of 2017, (i)
21.9 million
shares were purchased under the $3.0 Billion Share-Repurchase Program and (ii)
67 thousand
shares were purchased related to stock received by the Company for the payment of withholding taxes due on employee share issuances under share-based compensation plans. For additional information, see
Note 22—Share-Based Compensation
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
(2)
|
At December 31, 2017, the Company had repurchased, through open-market and private transactions, approximately $1.1 billion of common stock under its share-repurchase program in place at year end, which was expanded by $500 million in February 2018 under the $3.0 Billion Share-Repurchase Program. In February 2018, the Company completed the repurchase of an additional 8.5 million shares as part of an ASR Agreement. For additional information, see
Note 20—Stockholders’ Equity
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
(3)
|
In October 2017, the Company entered into an ASR Agreement to complete
$1.0 billion
of the $3.0 Billion Share-Repurchase Program and received an initial delivery of
15.7 million
shares. The transaction was completed in December 2017, at which time the Company received an additional
5.1 million
shares to settle the agreement. The settlement price was determined by the volume-weighted average price of the shares during the term less a negotiated settlement price adjustment. During the fourth quarter of 2017, the Company repurchased an additional
1.1 million
shares for
$59 million
through open-market purchases. For additional information, see
Note 20—Stockholders’ Equity
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
Fiscal Year Ended December 31
|
2012
|
|
2013
|
|
2014
|
|
2015
|
|
2016
|
|
2017
|
||||||||||||
Anadarko Petroleum Corporation
|
$
|
100.00
|
|
|
$
|
107.39
|
|
|
$
|
112.91
|
|
|
$
|
67.53
|
|
|
$
|
97.28
|
|
|
$
|
75.14
|
|
S&P 500
|
100.00
|
|
|
132.39
|
|
|
150.51
|
|
|
152.59
|
|
|
170.84
|
|
|
208.14
|
|
||||||
Peer Group
|
100.00
|
|
|
126.49
|
|
|
116.48
|
|
|
88.51
|
|
|
115.49
|
|
|
119.42
|
|
|
Summary Financial Information
(1)
|
||||||||||||||||||
millions except per-share amounts
|
2017
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
||||||||||
Sales Revenues
|
$
|
10,969
|
|
|
$
|
8,447
|
|
|
$
|
9,486
|
|
|
$
|
16,375
|
|
|
$
|
14,867
|
|
Gains (Losses) on Divestitures and Other, net
|
939
|
|
|
(578
|
)
|
|
(788
|
)
|
|
2,095
|
|
|
(286
|
)
|
|||||
Total Revenues and Other
|
11,908
|
|
|
7,869
|
|
|
8,698
|
|
|
18,470
|
|
|
14,581
|
|
|||||
Operating Income (Loss)
|
(672
|
)
|
|
(2,599
|
)
|
|
(8,809
|
)
|
|
5,403
|
|
|
3,333
|
|
|||||
Tronox-related Contingent Loss
|
—
|
|
|
—
|
|
|
5
|
|
|
4,360
|
|
|
850
|
|
|||||
Net Income (Loss)
(2)
|
(211
|
)
|
|
(2,808
|
)
|
|
(6,812
|
)
|
|
(1,563
|
)
|
|
941
|
|
|||||
Net Income (Loss) Attributable to Common Stockholders
|
(456
|
)
|
|
(3,071
|
)
|
|
(6,692
|
)
|
|
(1,750
|
)
|
|
801
|
|
|||||
Per Common Share (amounts attributable to common stockholders)
|
|
|
|
|
|
|
|
|
|
||||||||||
Net Income (Loss)—Basic
|
$
|
(0.85
|
)
|
|
$
|
(5.90
|
)
|
|
$
|
(13.18
|
)
|
|
$
|
(3.47
|
)
|
|
$
|
1.58
|
|
Net Income (Loss)—Diluted
|
$
|
(0.85
|
)
|
|
$
|
(5.90
|
)
|
|
$
|
(13.18
|
)
|
|
$
|
(3.47
|
)
|
|
$
|
1.58
|
|
Dividends
|
$
|
0.20
|
|
|
$
|
0.20
|
|
|
$
|
1.08
|
|
|
$
|
0.99
|
|
|
$
|
0.54
|
|
Average Number of Common Shares Outstanding—Basic
|
548
|
|
|
522
|
|
|
508
|
|
|
506
|
|
|
502
|
|
|||||
Average Number of Common Shares Outstanding—Diluted
|
548
|
|
|
522
|
|
|
508
|
|
|
506
|
|
|
505
|
|
|||||
Cash Provided by (Used in) Operating Activities
(3)
|
4,009
|
|
|
3,000
|
|
|
(1,877
|
)
|
|
8,466
|
|
|
8,888
|
|
|||||
Capital Expenditures
|
$
|
5,300
|
|
|
$
|
3,314
|
|
|
$
|
5,888
|
|
|
$
|
9,256
|
|
|
$
|
8,523
|
|
Short-term Debt - Anadarko
(4)
|
$
|
142
|
|
|
$
|
42
|
|
|
$
|
32
|
|
|
$
|
—
|
|
|
$
|
500
|
|
Long-term Debt - Anadarko
(4)
|
12,054
|
|
|
12,162
|
|
|
12,945
|
|
|
12,595
|
|
|
11,576
|
|
|||||
Long-term Debt - WES and WGP
|
3,493
|
|
|
3,119
|
|
|
2,691
|
|
|
2,409
|
|
|
1,408
|
|
|||||
Total Debt
|
$
|
15,689
|
|
|
$
|
15,323
|
|
|
$
|
15,668
|
|
|
$
|
15,004
|
|
|
$
|
13,484
|
|
Total Stockholders’ Equity
|
10,696
|
|
|
12,212
|
|
|
12,819
|
|
|
19,725
|
|
|
21,857
|
|
|||||
Total Assets
|
$
|
42,086
|
|
|
$
|
45,564
|
|
|
$
|
46,331
|
|
|
$
|
60,879
|
|
|
$
|
55,340
|
|
Annual Sales Volumes
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (MMBbls)
|
129
|
|
|
116
|
|
|
116
|
|
|
106
|
|
|
91
|
|
|||||
Natural Gas (Bcf)
|
478
|
|
|
766
|
|
|
852
|
|
|
945
|
|
|
968
|
|
|||||
Natural Gas Liquids (MMBbls)
|
36
|
|
|
46
|
|
|
47
|
|
|
44
|
|
|
33
|
|
|||||
Total (MMBOE)
(5)
|
245
|
|
|
290
|
|
|
305
|
|
|
308
|
|
|
285
|
|
|||||
Average Daily Sales Volumes
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (MBbls/d)
|
355
|
|
|
316
|
|
|
317
|
|
|
292
|
|
|
248
|
|
|||||
Natural Gas (MMcf/d)
|
1,309
|
|
|
2,093
|
|
|
2,334
|
|
|
2,589
|
|
|
2,652
|
|
|||||
Natural Gas Liquids (MBbls/d)
|
99
|
|
|
128
|
|
|
130
|
|
|
119
|
|
|
91
|
|
|||||
Total (MBOE/d)
|
672
|
|
|
793
|
|
|
836
|
|
|
843
|
|
|
781
|
|
|||||
Proved Reserves
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil Reserves (MMBbls)
|
658
|
|
|
702
|
|
|
713
|
|
|
929
|
|
|
851
|
|
|||||
Natural-gas Reserves (Tcf)
|
3.2
|
|
|
4.4
|
|
|
6.0
|
|
|
8.7
|
|
|
9.2
|
|
|||||
Natural-gas Liquids Reserves (MMBbls)
|
243
|
|
|
283
|
|
|
340
|
|
|
479
|
|
|
407
|
|
|||||
Total Proved Reserves (MMBOE)
|
1,439
|
|
|
1,722
|
|
|
2,057
|
|
|
2,858
|
|
|
2,792
|
|
|||||
Number of Employees
|
4,400
|
|
|
4,500
|
|
|
5,800
|
|
|
6,100
|
|
|
5,700
|
|
(1)
|
Consolidated for Anadarko and its subsidiaries. Certain amounts for prior years have been reclassified to conform to the current presentation.
|
(2)
|
Includes one-time deferred tax benefit of $1.2 billion in 2017 related to Tax Reform Legislation.
|
(3)
|
Includes Tronox settlement payment of $5.2 billion in 2015.
|
(4)
|
Excludes WES and WGP.
|
(5)
|
Natural gas is converted to equivalent barrels at the rate of 6,000 cubic feet of gas per barrel.
|
•
|
Delaware Basin
Anadarko plans to allocate approximately $1.0 billion toward upstream and an additional $500 million toward Anadarko midstream investments. This program supports the continuation of the Company's efforts to build out one of the most expansive and integrated infrastructure positions in the region. The Company also is advancing its efforts to capture operatorship on 70% of its acreage position, primarily in Reeves and Loving counties. Additionally, Anadarko continues to progress the construction of three ROTFs to support its more cost-effective and environmentally beneficial tankless battery design field-wide, while also securing necessary gathering, processing, and takeaway capacity. This comprehensive build-out plan and phased development approach in the basin is expected to deliver incremental oil sales volumes during the second half of 2018, with total-year Delaware basin oil sales volumes expected to increase more than 50% relative to 2017. During 2018, the Company plans to average seven operated rigs and six completion crews.
|
•
|
DJ Basin
Anadarko expects to invest approximately $950 million on upstream activities and an additional $50 million toward Anadarko midstream investments. The Company has implemented a new completion design in the field, which has
resulted in a 20% improvement in average well recovery
. Anadarko expects to increase year-over-year oil sales volumes from the DJ basin by more than 30% and plans to average five operated rigs and three completions crews in the basin during the year.
|
•
|
Deepwater Gulf of Mexico
Anadarko expects to allocate approximately $1.0 billion toward its deepwater Gulf of Mexico operations. The majority of these investments are expected to be directed toward high-return oil development opportunities near operated infrastructure at Lucius, Horn Mountain, Marlin, Holstein, and Marco Polo. The Company plans to operate two floating drillships and one platform rig and spud approximately nine development wells in the Gulf of Mexico during the year.
|
•
|
International
Anadarko plans to allocate approximately $150 million toward its international cash-generating operations in Algeria and Ghana. These investments will support further drilling in the TEN development area, which is expected to commence in early 2018, as well as additional drilling operations in the Jubilee field following the Ghanaian government's recent approval of the full-field plan of development.
|
•
|
Exploration
The Company's exploration investments in 2018 are expected to total approximately $200 million. Exploration spending will primarily be focused on the Gulf of Mexico, where the Company plans to drill identified prospects near existing operated infrastructure with one floating drillship. The Company plans to allocate additional exploration investment to the U.S. onshore as it continues to identify future areas that could make a material and scalable addition to its portfolio.
|
•
|
LNG
The Company expects to invest approximately $150 million to advance the Mozambique LNG project toward FID. This includes funding Anadarko's portion
of the costs associated with preparing the site of the future onshore LNG park.
|
•
|
The Company’s oil sales volumes averaged
355
MBbls/d, representing a
12%
increase from
2016
, primarily due to increased volumes from the Gulf of Mexico, partially offset by the divestiture of certain U.S. onshore assets in 2017 and 2016.
|
•
|
The Company’s overall sales-volume product mix increased to
53%
oil in
2017
, compared to
40%
in
2016
, which significantly improved margins and returns.
|
•
|
Total sales volumes in the Delaware basin averaged
63
MBOE/d, representing a
41%
increase from
2016
, and oil sales volumes in the Delaware basin increased
13
MBbls/d, representing a
52%
increase from
2016
, primarily due to continued drilling and completion activities.
|
•
|
WES acquired a third party’s 50% nonoperated interest in the DBJV System in exchange for WES’s 33.75% interest in nonoperated Marcellus midstream assets and $155 million in cash.
|
•
|
The Company received net proceeds of approximately $4.0 billion from divestitures of certain U.S. onshore assets during 2017.
|
•
|
Oil sales volumes averaged
121
MBbls/d, representing an
85%
increase from
2016
, primarily due to the GOM Acquisition and continued tie-back activity at several facilities, partially offset by deferred production as a result of Hurricanes Harvey, Irma, and Nate and nonoperated field downtime during the second half of 2017.
|
•
|
The International Tribunal for the Law of the Sea issued a ruling in September 2017 regarding the delimitation of the maritime boundary between Ghana and Côte d’Ivoire in the Atlantic Ocean. The new maritime boundary as determined by the tribunal does not affect the TEN fields, and the operator now plans to resume development drilling in early 2018.
|
•
|
Interim spread mooring of the FPSO at the Jubilee field in Ghana commenced in the fourth quarter of 2016 and was completed during the first quarter of 2017. In early 2018, the operator will start the first of three shutdown periods that are expected to occur in 2018 to effectively stabilize the turret and rotate the FPSO to its permanent heading. In October, the partnership received Ghanaian Government approval for the full-field plan of development, with drilling operations expected to commence in 2018.
|
•
|
During the third quarter of 2017, the foundational legal and contractual framework was completed for the Company’s onshore LNG project in Mozambique. Anadarko commenced resettlement and site preparation activities, which will position the onshore area for construction of the LNG facilities.
|
•
|
Anadarko and its co-venturers in Offshore Area 1 in Mozambique reached agreement on the project’s first long-term sale and purchase agreement for 2.6 MTPA with Thailand’s national oil and gas company, subject to the approval of the Government of Thailand.
|
•
|
The Company generated
$4.0 billion
of cash flow from operations and ended
2017
with
$4.6 billion
of cash.
|
•
|
Prior to the end of 2017, the Company completed $1.1 billion of the share repurchases. In February 2018, the Company completed an additional $500 million of share repurchases.
|
•
|
The Company recognized a one-time deferred tax benefit of $1.2 billion as a result of the Tax Reform Legislation.
|
millions except per-share amounts
|
2017
|
|
2016
|
|
2015
|
||||||
Oil, natural-gas, and NGLs sales
|
$
|
8,969
|
|
|
$
|
7,153
|
|
|
$
|
8,260
|
|
Gathering, processing, and marketing sales
|
2,000
|
|
|
1,294
|
|
|
1,226
|
|
|||
Gains (losses) on divestitures and other, net
|
939
|
|
|
(578
|
)
|
|
(788
|
)
|
|||
Revenues and other
|
$
|
11,908
|
|
|
$
|
7,869
|
|
|
$
|
8,698
|
|
Costs and expenses
|
12,580
|
|
|
10,468
|
|
|
17,507
|
|
|||
Other (income) expense
|
1,016
|
|
|
1,230
|
|
|
880
|
|
|||
Income tax expense (benefit)
|
(1,477
|
)
|
|
(1,021
|
)
|
|
(2,877
|
)
|
|||
Net income (loss) attributable to common stockholders
|
$
|
(456
|
)
|
|
$
|
(3,071
|
)
|
|
$
|
(6,692
|
)
|
Net income (loss) per common share attributable to common stockholders—diluted
|
$
|
(0.85
|
)
|
|
$
|
(5.90
|
)
|
|
$
|
(13.18
|
)
|
Average number of common shares outstanding—diluted
|
548
|
|
|
522
|
|
|
508
|
|
millions
|
Oil
|
|
Natural Gas
|
|
NGLs
|
|
Total
|
||||||||
2016 sales revenues
|
$
|
4,668
|
|
|
$
|
1,564
|
|
|
$
|
921
|
|
|
$
|
7,153
|
|
Changes associated with prices
|
1,334
|
|
|
373
|
|
|
358
|
|
|
2,065
|
|
||||
Changes associated with sales volumes
|
550
|
|
|
(589
|
)
|
|
(210
|
)
|
|
(249
|
)
|
||||
2017 sales revenues
|
$
|
6,552
|
|
|
$
|
1,348
|
|
|
$
|
1,069
|
|
|
$
|
8,969
|
|
Increase/(decrease) vs. 2016
|
40
|
%
|
|
(14
|
)%
|
|
16
|
%
|
|
25
|
%
|
||||
|
|
|
|
|
|
|
|
||||||||
2015 sales revenues
|
$
|
5,420
|
|
|
$
|
2,007
|
|
|
$
|
833
|
|
|
$
|
8,260
|
|
Changes associated with prices
|
(745
|
)
|
|
(241
|
)
|
|
95
|
|
|
(891
|
)
|
||||
Changes associated with sales volumes
|
(7
|
)
|
|
(202
|
)
|
|
(7
|
)
|
|
(216
|
)
|
||||
2016 sales revenues
|
$
|
4,668
|
|
|
$
|
1,564
|
|
|
$
|
921
|
|
|
$
|
7,153
|
|
Increase/(decrease) vs. 2015
|
(14
|
)%
|
|
(22
|
)%
|
|
11
|
%
|
|
(13
|
)%
|
|
|
2017
|
|
Inc (Dec)
vs. 2016 |
|
2016
|
|
Inc (Dec)
vs. 2015 |
|
2015
|
|||||
Barrels of Oil Equivalent
|
|
|
|
|
|
|
|
|
|
|
|||||
(MMBOE except percentages)
|
|
|
|
|
|
|
|
|
|
|
|||||
United States
|
|
211
|
|
|
(18
|
)%
|
|
257
|
|
|
(5
|
)%
|
|
272
|
|
International
|
|
34
|
|
|
3
|
|
|
33
|
|
|
(1
|
)
|
|
33
|
|
Total barrels of oil equivalent
|
|
245
|
|
|
(16
|
)
|
|
290
|
|
|
(5
|
)
|
|
305
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Barrels of Oil Equivalent per Day
|
|
|
|
|
|
|
|
|
|
|
|||||
(MBOE/d except percentages)
|
|
|
|
|
|
|
|
|
|
|
|||||
United States
|
|
579
|
|
|
(18
|
)%
|
|
704
|
|
|
(5
|
)%
|
|
745
|
|
International
|
|
93
|
|
|
4
|
|
|
89
|
|
|
(1
|
)
|
|
91
|
|
Total barrels of oil equivalent per day
|
|
672
|
|
|
(15
|
)
|
|
793
|
|
|
(5
|
)
|
|
836
|
|
|
2017
|
|
Inc (Dec)
vs. 2016 |
|
2016
|
|
Inc (Dec)
vs. 2015 |
|
2015
|
||||||||
Oil sales revenues (millions)
|
$
|
6,552
|
|
|
40
|
%
|
|
$
|
4,668
|
|
|
(14
|
)%
|
|
$
|
5,420
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
United States
|
|
|
|
|
|
|
|
|
|
||||||||
Sales volumes—MMBbls
|
97
|
|
|
14
|
%
|
|
85
|
|
|
1
|
%
|
|
85
|
|
|||
MBbls/d
|
266
|
|
|
14
|
|
|
233
|
|
|
1
|
|
|
232
|
|
|||
Price per barrel
|
$
|
49.62
|
|
|
27
|
|
|
$
|
39.06
|
|
|
(13
|
)
|
|
$
|
45.00
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
International
|
|
|
|
|
|
|
|
|
|
||||||||
Sales volumes—MMBbls
|
32
|
|
|
6
|
%
|
|
31
|
|
|
(2
|
)%
|
|
31
|
|
|||
MBbls/d
|
89
|
|
|
6
|
|
|
83
|
|
|
(2
|
)
|
|
85
|
|
|||
Price per barrel
|
$
|
53.77
|
|
|
22
|
|
|
$
|
43.93
|
|
|
(15
|
)
|
|
$
|
51.68
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Total
|
|
|
|
|
|
|
|
|
|
||||||||
Sales volumes—MMBbls
|
129
|
|
|
12
|
%
|
|
116
|
|
|
—
|
%
|
|
116
|
|
|||
MBbls/d
|
355
|
|
|
12
|
|
|
316
|
|
|
—
|
|
|
317
|
|
|||
Price per barrel
|
$
|
50.66
|
|
|
26
|
|
|
$
|
40.34
|
|
|
(14
|
)
|
|
$
|
46.79
|
|
millions
|
Change in Revenues
|
|
Due to Change
in Prices
|
|
Due to Change
in Volumes
|
||||||
2017 vs. 2016
|
$
|
1,884
|
|
|
$
|
1,334
|
|
|
$
|
550
|
|
2016 vs. 2015
|
(752
|
)
|
|
(745
|
)
|
|
(7
|
)
|
•
|
Sales volumes for the Delaware basin increased by
13
MBbls/d, primarily due to continued drilling and completion activities in 2017.
|
•
|
Divestitures resulted in a decrease in sales volumes of
29
MBbls/d, primarily related to the sale of the Eagleford assets in the first half of 2017.
|
•
|
Sales volumes increased by
56
MBbls/d, primarily due to the GOM Acquisition in December 2016 and continued tie-back activity at several facilities, partially offset by deferred production as a result of Hurricanes Harvey, Irma, and Nate and nonoperated field downtime during the second half of 2017.
|
•
|
Sales volumes for Ghana increased by
9
MBbls/d, primarily due to a full year of liftings from the TEN development project, which came online late in the third quarter of 2016, and downtime in 2016 to address new production and offtake procedures resulting from issues associated with the Jubilee field FPSO turret bearing. Shuttle tankers are conducting offtakes until the facility is permanently moored.
|
•
|
Sales volumes for the Delaware basin increased by 8 MBbls/d, primarily due to continued field development.
|
•
|
Sales volumes for the DJ basin decreased by 6 MBbls/d, primarily due to reduced capital activity.
|
•
|
Sales volumes decreased by 7 MBbls/d, primarily due to the sale of EOR assets in the first half of 2015 and the East Chalk and Wamsutter assets in the first half of 2016.
|
•
|
Sales volumes increased by 12 MBbls/d, primarily due to new wells coming online at K2 Complex and Caesar/Tonga in the first half of 2016, an increased flow rate at Lucius, and the achievement of first oil at Heidelberg in January 2016.
|
•
|
Sales volumes for Ghana decreased by 7 MBbls/d, primarily due to downtime during 2016 to address new production and offtake procedures resulting from issues associated with the Jubilee field FPSO turret bearing. Shuttle tankers are conducting offtakes until the facility is permanently moored. The decrease in volumes at Jubilee were partially offset by TEN coming online late in the third quarter of 2016.
|
|
2017
|
|
Inc (Dec)
vs. 2016 |
|
2016
|
|
Inc (Dec)
vs. 2015 |
|
2015
|
||||||||
Natural-gas sales revenues (millions)
|
$
|
1,348
|
|
|
(14
|
)%
|
|
$
|
1,564
|
|
|
(22
|
)%
|
|
$
|
2,007
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
United States
|
|
|
|
|
|
|
|
|
|
||||||||
Sales volumes—Bcf
|
478
|
|
|
(38
|
)%
|
|
766
|
|
|
(10
|
)%
|
|
852
|
|
|||
MMcf/d
|
1,309
|
|
|
(37
|
)
|
|
2,093
|
|
|
(10
|
)
|
|
2,334
|
|
|||
Price per Mcf
|
$
|
2.82
|
|
|
38
|
|
|
$
|
2.04
|
|
|
(14
|
)
|
|
$
|
2.36
|
|
millions
|
Change in Revenues
|
|
Due to Change
in Prices
|
|
Due to Change
in Volumes
|
||||||
2017 vs. 2016
|
$
|
(216
|
)
|
|
$
|
373
|
|
|
$
|
(589
|
)
|
2016 vs. 2015
|
(443
|
)
|
|
(241
|
)
|
|
(202
|
)
|
•
|
Sales volumes for the DJ basin increased by 98 MMcf/d, primarily due to improved performance.
|
•
|
Sales volumes for the Delaware basin increased by 18 MMcf/d, primarily due to continued field development.
|
•
|
Sales volumes decreased by 290 MMcf/d, primarily due to the sale of the Powder River Basin CBM assets and the Freestone assets in the second half of 2015, the Carthage assets in the second half of 2016, and the Wamsutter assets in the first half of 2016.
|
•
|
Sales volumes decreased by 61 MMcf/d, primarily as a result of the last producing well at Independence Hub going off line in December 2015.
|
|
2017
|
|
Inc (Dec)
vs. 2016 |
|
2016
|
|
Inc (Dec)
vs. 2015 |
|
2015
|
||||||||
Natural-gas liquids sales revenues (millions)
|
$
|
1,069
|
|
|
16
|
%
|
|
$
|
921
|
|
|
11
|
%
|
|
$
|
833
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Total
|
|
|
|
|
|
|
|
|
|
||||||||
Sales volumes—MMBbls
(1)
|
36
|
|
|
(23
|
)%
|
|
46
|
|
|
(1
|
)%
|
|
47
|
|
|||
MBbls/d
(2)
|
99
|
|
|
(23
|
)
|
|
128
|
|
|
(1
|
)
|
|
130
|
|
|||
Price per barrel
|
$
|
29.54
|
|
|
50
|
|
|
$
|
19.64
|
|
|
12
|
|
|
$
|
17.61
|
|
(1)
|
The percentage of NGLs sales volumes from the U.S. was 94% in 2017 and 96% in 2016 and 2015.
|
(2)
|
The percentage of daily NGLs sales volumes from the U.S. was 96% in 2017 and 95% in 2016 and 2015.
|
millions
|
Change in Revenues
|
|
Due to Change
in Prices
|
|
Due to Change
in Volumes
|
||||||
2017 vs. 2016
|
$
|
148
|
|
|
$
|
358
|
|
|
$
|
(210
|
)
|
2016 vs. 2015
|
88
|
|
|
95
|
|
|
(7
|
)
|
millions except percentages
|
|
2017
|
|
Inc (Dec)
vs. 2016 |
|
2016
|
|
Inc (Dec)
vs. 2015 |
|
2015
|
||||||||
Gathering, processing, and marketing sales
|
|
$
|
2,000
|
|
|
55
|
%
|
|
$
|
1,294
|
|
|
6
|
%
|
|
$
|
1,226
|
|
Gathering, processing, and marketing expense
|
|
1,560
|
|
|
44
|
|
|
1,087
|
|
|
3
|
|
|
1,054
|
|
|||
Total gathering, processing, and marketing, net
|
|
$
|
440
|
|
|
113
|
|
|
$
|
207
|
|
|
20
|
|
|
$
|
172
|
|
millions except percentages
|
2017
|
|
Inc (Dec)
vs. 2016 |
|
2016
|
|
Inc (Dec)
vs. 2015 |
|
2015
|
||||||||
Gains (losses) on divestitures, net
|
$
|
674
|
|
|
189
|
%
|
|
$
|
(757
|
)
|
|
26
|
%
|
|
$
|
(1,022
|
)
|
Other
|
265
|
|
|
48
|
|
|
179
|
|
|
(24
|
)
|
|
234
|
|
|||
Total gains (losses) on divestitures and other, net
|
$
|
939
|
|
|
NM
|
|
|
$
|
(578
|
)
|
|
27
|
|
|
$
|
(788
|
)
|
millions
|
2017
|
|
2016
|
|
2015
|
||||||
Oil and gas operating
|
$
|
1,000
|
|
|
$
|
811
|
|
|
$
|
1,014
|
|
Oil and gas transportation
|
914
|
|
|
1,002
|
|
|
1,117
|
|
|||
Exploration
|
2,541
|
|
|
946
|
|
|
2,644
|
|
|||
Gathering, processing, and marketing
|
1,560
|
|
|
1,087
|
|
|
1,054
|
|
|||
G&A
|
1,075
|
|
|
1,440
|
|
|
1,176
|
|
|||
DD&A
|
4,279
|
|
|
4,301
|
|
|
4,603
|
|
|||
Production, property, and other taxes
|
582
|
|
|
536
|
|
|
553
|
|
|||
Impairments
|
408
|
|
|
227
|
|
|
5,075
|
|
|||
Other operating expense
|
221
|
|
|
118
|
|
|
271
|
|
|||
Total
|
$
|
12,580
|
|
|
$
|
10,468
|
|
|
$
|
17,507
|
|
|
2017
|
|
Inc (Dec)
vs. 2016 |
|
2016
|
|
Inc (Dec)
vs. 2015 |
|
2015
|
||||||||
Oil and gas operating (millions)
|
$
|
1,000
|
|
|
23
|
%
|
|
$
|
811
|
|
|
(20
|
)%
|
|
$
|
1,014
|
|
Oil and gas operating—per BOE
|
4.08
|
|
|
46
|
|
|
2.79
|
|
|
(16
|
)
|
|
3.32
|
|
|||
Oil and gas transportation (millions)
|
914
|
|
|
(9
|
)
|
|
1,002
|
|
|
(10
|
)
|
|
1,117
|
|
|||
Oil and gas transportation—per BOE
|
3.73
|
|
|
8
|
|
|
3.46
|
|
|
(5
|
)
|
|
3.66
|
|
•
|
higher operating costs of
$212 million
primarily related to the GOM Acquisition
|
•
|
higher operating costs of
$88 million
related to increased activity in the DJ and Delaware basins and costs related to the Company’s response efforts in Colorado in 2017
|
•
|
lower nonoperating costs of
$12 million
in Ghana primarily related to FPSO maintenance costs in 2016, partially offset by higher costs in 2017 due to increased production from the TEN development, which came online late in the third quarter of 2016
|
•
|
lower expenses of
$89 million
as a result of U.S. onshore asset divestitures
|
•
|
lower workover costs of $28 million in the Gulf of Mexico and the U.S. onshore
|
•
|
lower surface maintenance costs of $16 million in the U.S. onshore and the Gulf of Mexico
|
•
|
lower expenses of $112 million as a result of divestitures
|
millions
|
2017
|
|
2016
|
|
2015
|
||||||
Dry hole expense
|
$
|
1,433
|
|
|
$
|
397
|
|
|
$
|
1,052
|
|
Impairments of unproved properties
|
788
|
|
|
216
|
|
|
1,215
|
|
|||
Geological and geophysical, exploration overhead, and other expense
|
320
|
|
|
333
|
|
|
377
|
|
|||
Total exploration expense
|
$
|
2,541
|
|
|
$
|
946
|
|
|
$
|
2,644
|
|
•
|
$437 million
related to the Shenandoah project,
$215 million
related to the Phobos project, and
$108 million
related to the Warrior project in the Gulf of Mexico due to insufficient quantities of oil pay to justify development
|
•
|
$329 million
related to all remaining wells in Côte d’Ivoire, where the Company relinquished its interest in its Cote d'Ivoire blocks
|
•
|
$243 million
related to certain wells in the Grand Fuerte area in Colombia due to insufficient progress on contractual and fiscal reforms needed for deepwater natural-gas development
|
•
|
$231 million related to certain wells in the Gulf of Mexico and $92 million related to certain wells in Mozambique
|
•
|
$39 million for a well in Côte d’Ivoire that finished drilling in the third quarter of 2016 and encountered noncommercial quantities of hydrocarbons
|
•
|
$746 million primarily related to Brazil where the Company did not expect to have substantive exploration and development activities for the foreseeable future given the current oil-price environment
|
•
|
$306 million due to unsuccessful drilling activities in 2015 primarily in Colombia and the Gulf of Mexico
|
•
|
The Company recognized a $610 million impairment of unproved Gulf of Mexico properties, of which $463 million related to the Shenandoah project. The unproved property balance related to the Shenandoah project originated from the purchase price allocated to the Gulf of Mexico exploration projects from the acquisition of Kerr McGee Corporation in 2006. For additional details on the Shenandoah project, see
Note 6—Suspended Exploratory Well Costs
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
•
|
The Company recognized $88 million of impairments of unproved international properties.
|
•
|
The Company recognized a $72 million impairment of unproved properties in the Gulf of Mexico and $92 million for unproved international properties, primarily in Brazil and Tunisia, due to the Company’s current intentions to not pursue future exploration activities.
|
•
|
The Company recognized a $935 million impairment of unproved Greater Natural Buttes properties and a $66 million impairment of an unproved Gulf of Mexico property as a result of lower commodity prices.
|
•
|
The Company recognized a $109 million impairment of unproved Utica properties resulting from an assignment of mineral interests in settlement of a legal matter.
|
millions except percentages
|
2017
|
|
Inc (Dec)
vs. 2016 |
|
2016
|
|
Inc (Dec)
vs. 2015 |
|
2015
|
||||||||
G&A
|
$
|
1,075
|
|
|
(25
|
)%
|
|
$
|
1,440
|
|
|
22
|
%
|
|
$
|
1,176
|
|
millions except percentages
|
2017
|
|
Inc (Dec)
vs. 2016 |
|
2016
|
|
Inc (Dec)
vs. 2015 |
|
2015
|
||||||||
DD&A
|
$
|
4,279
|
|
|
(1
|
)%
|
|
$
|
4,301
|
|
|
(7
|
)%
|
|
$
|
4,603
|
|
•
|
$717 million related to lower 2017 sales volumes and asset property balances associated with U.S. onshore properties as a result of divestitures in 2016 and 2017
|
•
|
$457 million related to higher sales volumes in the Gulf of Mexico primarily due to the GOM Acquisition
|
•
|
$240 million related to international production DD&A primarily due to higher sales volumes from the Ghana TEN project, which came online late in the third quarter of 2016
|
•
|
lower carrying value for U.S. onshore and midstream properties as a result of 2015 asset impairments and divestitures in 2015 and 2016
|
•
|
lower 2016 sales volumes associated with U.S. onshore properties
|
millions
|
2017
|
|
2016
|
|
2015
|
||||||
Exploration and Production
|
|
|
|
|
|
||||||
U.S. onshore properties
|
$
|
2
|
|
|
$
|
28
|
|
|
$
|
3,684
|
|
Gulf of Mexico properties
|
227
|
|
|
27
|
|
|
349
|
|
|||
Cost-method investment
|
—
|
|
|
59
|
|
|
3
|
|
|||
WES Midstream
|
176
|
|
|
16
|
|
|
515
|
|
|||
Other Midstream
|
2
|
|
|
57
|
|
|
524
|
|
|||
Other
|
1
|
|
|
40
|
|
|
—
|
|
|||
Total impairments
(1)
|
$
|
408
|
|
|
$
|
227
|
|
|
$
|
5,075
|
|
(1)
|
In 2015, $3.0 billion of Exploration and Production impairments and $482 million of Other Midstream impairments related to Greater Natural Buttes.
|
millions
|
2017
|
|
2016
|
|
2015
|
||||||
Interest expense
(1)
|
$
|
932
|
|
|
$
|
890
|
|
|
$
|
825
|
|
Loss on early extinguishment of debt
(2)
|
2
|
|
|
155
|
|
|
—
|
|
|||
(Gains) losses on derivatives, net
(3)
|
135
|
|
|
286
|
|
|
(99
|
)
|
|||
Other (income) expense, net
|
(53
|
)
|
|
(101
|
)
|
|
154
|
|
|||
Total
|
$
|
1,016
|
|
|
$
|
1,230
|
|
|
$
|
880
|
|
(1)
|
The increase in interest expense from 2016 to 2017 is primarily due to lower capitalized interest in 2017. See
Note 12—Debt and Interest Expense
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
(2)
|
See
Note 12—Debt and Interest Expense
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K for information on early extinguishment of debt.
|
(3)
|
See
Note 10—Derivative Instruments
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
millions except percentages
|
2017
|
|
2016
|
|
2015
|
||||||
Income tax expense (benefit)
|
$
|
(1,477
|
)
|
|
$
|
(1,021
|
)
|
|
$
|
(2,877
|
)
|
Income (loss) before income taxes
|
$
|
(1,688
|
)
|
|
$
|
(3,829
|
)
|
|
$
|
(9,689
|
)
|
Effective tax rate
|
88
|
%
|
|
27
|
%
|
|
30
|
%
|
millions
|
2017
|
|
2016
|
|
2015
|
||||||
Net cash provided by (used in) operating activities
|
$
|
4,009
|
|
|
$
|
3,000
|
|
|
$
|
(1,877
|
)
|
Net cash provided by (used in) investing activities
|
(1,028
|
)
|
|
(2,762
|
)
|
|
(4,771
|
)
|
|||
Net cash provided by (used in) financing activities
|
(1,613
|
)
|
|
2,008
|
|
|
220
|
|
millions
|
2017
|
|
2016
|
|
2015
|
||||||
Cash Flows from Investing Activities
|
|
|
|
|
|
||||||
Additions to properties and equipment
(1)
|
$
|
5,031
|
|
|
$
|
3,505
|
|
|
$
|
6,067
|
|
Adjustments for capital expenditures
|
|
|
|
|
|
||||||
Changes in capital accruals
|
275
|
|
|
(205
|
)
|
|
(226
|
)
|
|||
Other
|
(6
|
)
|
|
14
|
|
|
47
|
|
|||
Total capital expenditures
(2)
|
$
|
5,300
|
|
|
$
|
3,314
|
|
|
$
|
5,888
|
|
|
|
|
|
|
|
||||||
Exploration and Production and other capital expenditures
|
$
|
3,886
|
|
|
$
|
2,764
|
|
|
$
|
5,118
|
|
WES Midstream capital expenditures
|
956
|
|
|
491
|
|
|
525
|
|
|||
Other Midstream capital expenditures
|
458
|
|
|
59
|
|
|
245
|
|
(1)
|
Additions to properties and equipment as presented within Anadarko’s cash flows from investing activities include cash payments for cost of properties, equipment, and facilities. The cost of properties includes the initial capitalization of drilling costs associated with all exploratory wells, whether or not they were deemed to have a commercially sufficient quantity of proved reserves.
|
(2)
|
Capital expenditures exclude the FPSO capital lease asset; see Financing Activities
—Capital Lease Obligations
below.
|
millions except percentages
|
2017
|
|
2016
|
||||
Anadarko
|
$
|
12,196
|
|
|
$
|
12,204
|
|
WES
|
3,465
|
|
|
3,091
|
|
||
WGP
|
28
|
|
|
28
|
|
||
Total debt
|
$
|
15,689
|
|
|
$
|
15,323
|
|
Total equity
|
13,790
|
|
|
15,497
|
|
||
Debt to total capitalization ratio
|
53.2
|
%
|
|
49.7
|
%
|
millions
|
2017
|
|
2016
|
|
2015
|
|
Description
|
||||||
Issuances
|
$
|
—
|
|
|
$
|
800
|
|
|
$
|
—
|
|
|
4.850% Senior Notes due 2021
(1)
|
|
—
|
|
|
1,100
|
|
|
—
|
|
|
5.550% Senior Notes due 2026
(1)
|
|||
|
—
|
|
|
1,100
|
|
|
—
|
|
|
6.600% Senior Notes due 2046
(1)
|
|||
|
—
|
|
|
500
|
|
|
—
|
|
|
WES 4.650% Senior Notes due 2026
|
|||
|
—
|
|
|
—
|
|
|
500
|
|
|
WES 3.950% Senior Notes due 2025
|
|||
|
—
|
|
|
—
|
|
|
101
|
|
|
TEUs - senior amortizing notes
|
|||
|
—
|
|
|
200
|
|
|
—
|
|
|
WES 5.450% Senior Notes due 2044
|
|||
Borrowings
|
—
|
|
|
1,750
|
|
|
1,800
|
|
|
364-Day Facility
|
|||
|
—
|
|
|
—
|
|
|
1,500
|
|
|
$5.0 Billion Facility
|
|||
|
370
|
|
|
600
|
|
|
400
|
|
|
WES RCF
|
|||
|
—
|
|
|
28
|
|
|
—
|
|
|
WGP RCF
|
|||
|
—
|
|
|
—
|
|
|
250
|
|
|
Commercial paper notes, net
(2)
|
|||
Repayments
|
(6
|
)
|
|
—
|
|
|
—
|
|
|
7.000% Debentures due 2027
|
|||
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
6.625% Debentures due 2028
|
|||
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
7.950% Debentures due 2029
|
|||
|
—
|
|
|
(1,750
|
)
|
|
—
|
|
|
5.950% Senior Notes due 2016
|
|||
|
—
|
|
|
(2,000
|
)
|
|
—
|
|
|
6.375% Senior Notes due 2017
|
|||
|
—
|
|
|
(1,750
|
)
|
|
(1,800
|
)
|
|
364-Day Facility
|
|||
|
—
|
|
|
—
|
|
|
(1,500
|
)
|
|
$5.0 Billion Facility
|
|||
|
—
|
|
|
(900
|
)
|
|
(610
|
)
|
|
WES RCF
|
|||
|
—
|
|
|
(250
|
)
|
|
—
|
|
|
Commercial paper notes, net
|
|||
|
(34
|
)
|
|
(34
|
)
|
|
(16
|
)
|
|
TEUs - senior amortizing notes
|
(1)
|
Represent senior notes issued in March 2016.
|
(2)
|
Includes repayments of
$(106) million
related to commercial paper notes with maturities greater than 90 days.
|
millions
|
2017
|
|
2016
|
|
2015
|
||||||
WES distributions to unitholders (excluding Anadarko and WGP)
(1)
|
$
|
326
|
|
|
$
|
258
|
|
|
$
|
231
|
|
WES distributions to Series A Preferred unitholders
(2)
|
22
|
|
|
31
|
|
|
—
|
|
|||
WGP distributions to unitholders (excluding Anadarko)
(3)
|
81
|
|
|
59
|
|
|
37
|
|
(1)
|
WES has made quarterly distributions to its unitholders since its IPO in the second quarter of 2008 and has increased its distribution from $0.30 per common unit for the third quarter of 2008 to $0.92 per common unit for the fourth quarter of
2017
(paid in February
2018
).
|
(2)
|
WES made distributions of $0.68 per unit, prorated based on issuance date, to its Series A Preferred unitholders since the unit issuances in March and April 2016. As of June 30, 2017, all Series A Preferred units had converted into WES common units. See
Note 23—Noncontrolling Interests
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
(3)
|
WGP has made quarterly distributions to its unitholders since its IPO in December 2012 and has increased its distribution from $0.17875 per common unit for the first quarter of 2013 to $0.54875 per unit for the fourth quarter of
2017
(to be paid in February
2018
).
|
|
|
|
Obligations by Period
|
||||||||||||||||||
millions
|
Note Reference
(1)
|
|
2018
|
|
2019-2020
|
|
2021-2022
|
|
2023 and Beyond
|
|
Total
|
||||||||||
Total debt
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Principal—total borrowings
(2)
|
|
$
|
481
|
|
|
$
|
1,298
|
|
|
$
|
1,970
|
|
|
$
|
13,283
|
|
|
$
|
17,032
|
|
|
Interest on borrowings
|
|
|
826
|
|
|
1,597
|
|
|
1,431
|
|
|
8,631
|
|
|
12,485
|
|
|||||
Capital lease obligation and interest
|
|
|
53
|
|
|
85
|
|
|
84
|
|
|
365
|
|
|
587
|
|
|||||
Investee entities’ debt and interest
(3)
|
|
82
|
|
|
183
|
|
|
191
|
|
|
2,073
|
|
|
2,529
|
|
||||||
Operating leases
|
|
465
|
|
|
353
|
|
|
64
|
|
|
52
|
|
|
934
|
|
||||||
Oil and gas activities
(4)
|
|
408
|
|
|
280
|
|
|
101
|
|
|
127
|
|
|
916
|
|
||||||
Midstream and marketing activities
|
|
859
|
|
|
1,757
|
|
|
1,260
|
|
|
1,310
|
|
|
5,186
|
|
||||||
AROs
|
|
298
|
|
|
100
|
|
|
644
|
|
|
1,752
|
|
|
2,794
|
|
||||||
Derivative liabilities
(5)
|
|
344
|
|
|
486
|
|
|
397
|
|
|
183
|
|
|
1,410
|
|
||||||
Uncertain tax positions
(6)
|
|
21
|
|
|
53
|
|
|
72
|
|
|
1,171
|
|
|
1,317
|
|
||||||
Other
(7)
|
|
|
37
|
|
|
192
|
|
|
58
|
|
|
84
|
|
|
371
|
|
|||||
Total
(8)
|
|
|
$
|
3,874
|
|
|
$
|
6,384
|
|
|
$
|
6,272
|
|
|
$
|
29,031
|
|
|
$
|
45,561
|
|
(1)
|
For additional information, see the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
(2)
|
Includes the fully accreted principal amount of the Zero Coupons of approximately
$2.4 billion
as coming due after
2022
. While the Zero Coupons do not mature until
2036
, the outstanding Zero Coupons can be put to the Company each October, in whole or in part, for the then-accreted value. The Company could be required to repurchase the outstanding Zero Coupons at
$930 million
in October
2018
(the next potential put date).
|
(3)
|
The obligations and related investments are presented net on the Company’s Consolidated Balance Sheets in other assets or other long-term liabilities-other. Future interest payments are estimated using the relevant forward LIBOR rate curve. The preferred return that Anadarko receives on its investment in these entities is not included.
|
(4)
|
Includes long-term drilling and work-related commitments of
$916 million
, comprised of approximately
$815 million
related to the United States and
$101 million
related to international locations. Amounts are undiscounted and do not include purchase commitments for jointly owned fields and facilities where the Company is not the operator.
|
(5)
|
Represents Anadarko’s gross derivative liability after taking into account the impacts of netting margin and collateral balances deposited with counterparties.
|
(6)
|
Timing of conclusion of the uncertain tax positions cannot be determined with certainty.
|
(7)
|
Includes environmental liabilities; for additional information, see
Note 17—Contingencies
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
(8)
|
Excludes litigation-related contingent liabilities, the Company’s pension and postretirement benefit obligations, or payments related to the conveyance of future hard-minerals royalty revenues. See
Note 17—Contingencies
,
Note 19—Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans
, and
Note 15—Conveyance of Future Hard-Minerals Royalty Revenues
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
•
|
significant changes in the stock price of Anadarko, WES, and WGP
|
•
|
significant declines in commodity prices
|
•
|
significant increases in cost factors such as costs of drilling, production costs, and gathering, processing, and other transportation costs
|
•
|
impairments recognized by the Company
|
•
|
acquisitions and disposals of assets
|
•
|
changes to the Company’s reserves, including changes due to fluctuations in commodity prices and updates to the Company’s plans or forecasts
|
•
|
significant declines in trading multiples for midstream peers
|
|
Page
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ R. A. WALKER
|
R. A. Walker
Chairman, President and Chief Executive Officer
|
/s/ ROBERT G. GWIN
|
Robert G. Gwin
Executive Vice President, Finance and Chief Financial Officer
|
|
February 15, 2018
|
/s/ KPMG LLP
|
|
Houston, Texas
|
February 15, 2018
|
/s/ KPMG LLP
|
|
We have served as the Company’s auditor since 1981.
|
|
Houston, Texas
|
February 15, 2018
|
|
Years Ended December 31,
|
||||||||||
millions except per-share amounts
|
2017
|
|
2016
|
|
2015
|
||||||
Revenues and Other
|
|
|
|
|
|
||||||
Oil sales
|
$
|
6,552
|
|
|
$
|
4,668
|
|
|
$
|
5,420
|
|
Natural-gas sales
|
1,348
|
|
|
1,564
|
|
|
2,007
|
|
|||
Natural-gas liquids sales
|
1,069
|
|
|
921
|
|
|
833
|
|
|||
Gathering, processing, and marketing sales
|
2,000
|
|
|
1,294
|
|
|
1,226
|
|
|||
Gains (losses) on divestitures and other, net
|
939
|
|
|
(578
|
)
|
|
(788
|
)
|
|||
Total
|
11,908
|
|
|
7,869
|
|
|
8,698
|
|
|||
Costs and Expenses
|
|
|
|
|
|
||||||
Oil and gas operating
|
1,000
|
|
|
811
|
|
|
1,014
|
|
|||
Oil and gas transportation
|
914
|
|
|
1,002
|
|
|
1,117
|
|
|||
Exploration
|
2,541
|
|
|
946
|
|
|
2,644
|
|
|||
Gathering, processing, and marketing
|
1,560
|
|
|
1,087
|
|
|
1,054
|
|
|||
General and administrative
|
1,075
|
|
|
1,440
|
|
|
1,176
|
|
|||
Depreciation, depletion, and amortization
|
4,279
|
|
|
4,301
|
|
|
4,603
|
|
|||
Production, property, and other taxes
|
582
|
|
|
536
|
|
|
553
|
|
|||
Impairments
|
408
|
|
|
227
|
|
|
5,075
|
|
|||
Other operating expense
|
221
|
|
|
118
|
|
|
271
|
|
|||
Total
|
12,580
|
|
|
10,468
|
|
|
17,507
|
|
|||
Operating Income (Loss)
|
(672
|
)
|
|
(2,599
|
)
|
|
(8,809
|
)
|
|||
Other (Income) Expense
|
|
|
|
|
|
||||||
Interest expense
|
932
|
|
|
890
|
|
|
825
|
|
|||
Loss on early extinguishment of debt
|
2
|
|
|
155
|
|
|
—
|
|
|||
(Gains) losses on derivatives, net
|
135
|
|
|
286
|
|
|
(99
|
)
|
|||
Other (income) expense, net
|
(53
|
)
|
|
(101
|
)
|
|
154
|
|
|||
Total
|
1,016
|
|
|
1,230
|
|
|
880
|
|
|||
Income (Loss) Before Income Taxes
|
(1,688
|
)
|
|
(3,829
|
)
|
|
(9,689
|
)
|
|||
Income tax expense (benefit)
|
(1,477
|
)
|
|
(1,021
|
)
|
|
(2,877
|
)
|
|||
Net Income (Loss)
|
(211
|
)
|
|
(2,808
|
)
|
|
(6,812
|
)
|
|||
Net income (loss) attributable to noncontrolling interests
|
245
|
|
|
263
|
|
|
(120
|
)
|
|||
Net Income (Loss) Attributable to Common Stockholders
|
$
|
(456
|
)
|
|
$
|
(3,071
|
)
|
|
$
|
(6,692
|
)
|
|
|
|
|
|
|
||||||
Per Common Share
|
|
|
|
|
|
||||||
Net income (loss) attributable to common stockholders—basic
|
$
|
(0.85
|
)
|
|
$
|
(5.90
|
)
|
|
$
|
(13.18
|
)
|
Net income (loss) attributable to common stockholders—diluted
|
$
|
(0.85
|
)
|
|
$
|
(5.90
|
)
|
|
$
|
(13.18
|
)
|
Average Number of Common Shares Outstanding—Basic
|
548
|
|
|
522
|
|
|
508
|
|
|||
Average Number of Common Shares Outstanding—Diluted
|
548
|
|
|
522
|
|
|
508
|
|
|||
Dividends (per Common Share)
|
$
|
0.20
|
|
|
$
|
0.20
|
|
|
$
|
1.08
|
|
|
Years Ended December 31,
|
||||||||||
millions
|
2017
|
|
2016
|
|
2015
|
||||||
Net Income (Loss)
|
$
|
(211
|
)
|
|
$
|
(2,808
|
)
|
|
$
|
(6,812
|
)
|
Other Comprehensive Income (Loss)
|
|
|
|
|
|
||||||
Adjustments for derivative instruments
|
|
|
|
|
|
||||||
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net
|
3
|
|
|
8
|
|
|
10
|
|
|||
Income taxes on reclassification of previously deferred derivative losses to (gains) losses on derivatives, net
|
(1
|
)
|
|
(3
|
)
|
|
(4
|
)
|
|||
Total adjustments for derivative instruments, net of taxes
|
2
|
|
|
5
|
|
|
6
|
|
|||
Adjustments for pension and other postretirement plans
|
|
|
|
|
|
||||||
Net gain (loss) incurred during period
|
(14
|
)
|
|
(175
|
)
|
|
49
|
|
|||
Income taxes on net gain (loss) incurred during period
|
4
|
|
|
68
|
|
|
(18
|
)
|
|||
Prior service credit (cost) incurred during period
|
—
|
|
|
—
|
|
|
89
|
|
|||
Income taxes on prior service credit (cost) incurred during period
|
—
|
|
|
—
|
|
|
(33
|
)
|
|||
Amortization of net actuarial (gain) loss to general and administrative expense
|
116
|
|
|
188
|
|
|
63
|
|
|||
Income taxes on amortization of net actuarial (gain) loss to general and administrative expense
|
(40
|
)
|
|
(73
|
)
|
|
(20
|
)
|
|||
Amortization of net prior service (credit) cost to general and administrative expense
|
(25
|
)
|
|
(34
|
)
|
|
(4
|
)
|
|||
Income taxes on amortization of net prior service (credit) cost to general and administrative expense
|
10
|
|
|
13
|
|
|
2
|
|
|||
Total adjustments for pension and other postretirement plans, net of taxes
|
51
|
|
|
(13
|
)
|
|
128
|
|
|||
Total
|
53
|
|
|
(8
|
)
|
|
134
|
|
|||
Comprehensive Income (Loss)
|
(158
|
)
|
|
(2,816
|
)
|
|
(6,678
|
)
|
|||
Comprehensive income (loss) attributable to noncontrolling interests
|
245
|
|
|
263
|
|
|
(120
|
)
|
|||
Comprehensive Income (Loss) Attributable to Common Stockholders
|
$
|
(403
|
)
|
|
$
|
(3,079
|
)
|
|
$
|
(6,558
|
)
|
|
December 31,
|
||||||
millions
except per-share amounts
|
2017
|
|
2016
|
||||
ASSETS
|
|
|
|
||||
Current Assets
|
|
|
|
||||
Cash and cash equivalents ($80 and $359 related to VIEs)
|
$
|
4,553
|
|
|
$
|
3,184
|
|
Accounts receivable (net of allowance of $14 and $14)
|
|
|
|
||||
Customers ($106 and $70 related to VIEs)
|
1,222
|
|
|
1,007
|
|
||
Others ($19 and $80 related to VIEs)
|
607
|
|
|
721
|
|
||
Other current assets
|
380
|
|
|
354
|
|
||
Total
|
6,762
|
|
|
5,266
|
|
||
Properties and Equipment
|
|
|
|
||||
Cost
|
65,050
|
|
|
69,013
|
|
||
Less accumulated depreciation, depletion, and amortization
|
37,599
|
|
|
36,845
|
|
||
Net properties and equipment ($5,731 and $5,050 related to VIEs)
|
27,451
|
|
|
32,168
|
|
||
Other Assets
($579 and $609 related to VIEs)
|
2,211
|
|
|
2,226
|
|
||
Goodwill and Other Intangible Assets
($1,191 and $1,221 related to VIEs)
|
5,662
|
|
|
5,904
|
|
||
Total Assets
|
$
|
42,086
|
|
|
$
|
45,564
|
|
|
|
|
|
||||
LIABILITIES AND EQUITY
|
|
|
|
||||
Current Liabilities
|
|
|
|
||||
Accounts payable
|
|
|
|
||||
Trade ($305 and $234 related to VIEs)
|
$
|
1,894
|
|
|
$
|
1,617
|
|
Other
|
266
|
|
|
303
|
|
||
Short-term debt - Anadarko
(1)
|
142
|
|
|
42
|
|
||
Current asset retirement obligations
|
294
|
|
|
129
|
|
||
Other current liabilities
|
1,310
|
|
|
1,237
|
|
||
Total
|
3,906
|
|
|
3,328
|
|
||
Long-term Debt
|
|
|
|
||||
Long-term debt - Anadarko
(1)
|
12,054
|
|
|
12,162
|
|
||
Long-term debt - WES and WGP
|
3,493
|
|
|
3,119
|
|
||
Total
|
15,547
|
|
|
15,281
|
|
||
Other Long-term Liabilities
|
|
|
|
||||
Deferred income taxes
|
2,234
|
|
|
4,324
|
|
||
Asset retirement obligations ($143 and $140 related to VIEs)
|
2,500
|
|
|
2,802
|
|
||
Other
|
4,109
|
|
|
4,332
|
|
||
Total
|
8,843
|
|
|
11,458
|
|
||
|
|
|
|
||||
Equity
|
|
|
|
||||
Stockholders’ equity
|
|
|
|
||||
Common stock, par value $0.10 per share
(1.0 billion shares authorized, 574.2 million and 572.0 million shares issued) |
57
|
|
|
57
|
|
||
Paid-in capital
|
12,000
|
|
|
11,875
|
|
||
Retained earnings
|
1,109
|
|
|
1,704
|
|
||
Treasury stock (43.4 million and 20.8 million shares)
|
(2,132
|
)
|
|
(1,033
|
)
|
||
Accumulated other comprehensive income (loss)
|
(338
|
)
|
|
(391
|
)
|
||
Total Stockholders’ Equity
|
10,696
|
|
|
12,212
|
|
||
Noncontrolling interests
|
3,094
|
|
|
3,285
|
|
||
Total Equity
|
13,790
|
|
|
15,497
|
|
||
Total Liabilities and Equity
|
$
|
42,086
|
|
|
$
|
45,564
|
|
(1)
|
Excludes WES and WGP.
|
|
Total Stockholders’ Equity
|
|
|
|
|
||||||||||||||||||||||
millions
|
Common
Stock
|
|
Paid-in
Capital
|
|
Retained
Earnings
|
|
Treasury
Stock
|
|
Accumulated Other
Comprehensive
Income (Loss)
|
|
Non-
controlling
Interests
|
|
Total
Equity
|
||||||||||||||
Balance at December 31, 2014
|
$
|
52
|
|
|
$
|
9,005
|
|
|
$
|
12,125
|
|
|
$
|
(940
|
)
|
|
$
|
(517
|
)
|
|
$
|
2,593
|
|
|
$
|
22,318
|
|
Net income (loss)
|
—
|
|
|
—
|
|
|
(6,692
|
)
|
|
—
|
|
|
—
|
|
|
(120
|
)
|
|
(6,812
|
)
|
|||||||
Common stock issued
|
—
|
|
|
31
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
31
|
|
|||||||
Share-based compensation expense
|
—
|
|
|
178
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
178
|
|
|||||||
Dividends—common stock
|
—
|
|
|
—
|
|
|
(553
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(553
|
)
|
|||||||
Repurchase of common stock
|
—
|
|
|
—
|
|
|
—
|
|
|
(55
|
)
|
|
—
|
|
|
—
|
|
|
(55
|
)
|
|||||||
Subsidiary equity transactions
|
—
|
|
|
51
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
99
|
|
|
150
|
|
|||||||
Issuance of tangible equity units
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
348
|
|
|
348
|
|
|||||||
Distributions to noncontrolling interest owners
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(282
|
)
|
|
(282
|
)
|
|||||||
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6
|
|
|
—
|
|
|
6
|
|
|||||||
Adjustments for pension and other postretirement plans
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
128
|
|
|
—
|
|
|
128
|
|
|||||||
Balance at December 31, 2015
|
52
|
|
|
9,265
|
|
|
4,880
|
|
|
(995
|
)
|
|
(383
|
)
|
|
2,638
|
|
|
15,457
|
|
|||||||
Net income (loss)
|
—
|
|
|
—
|
|
|
(3,071
|
)
|
|
—
|
|
|
—
|
|
|
263
|
|
|
(2,808
|
)
|
|||||||
Common stock issued
|
5
|
|
|
2,150
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,155
|
|
|||||||
Share-based compensation expense
|
—
|
|
|
197
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
197
|
|
|||||||
Dividends—common stock
|
—
|
|
|
—
|
|
|
(105
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(105
|
)
|
|||||||
Repurchase of common stock
|
—
|
|
|
—
|
|
|
—
|
|
|
(38
|
)
|
|
—
|
|
|
—
|
|
|
(38
|
)
|
|||||||
Subsidiary equity transactions
|
—
|
|
|
263
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
746
|
|
|
1,009
|
|
|||||||
Distributions to noncontrolling interest owners
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(362
|
)
|
|
(362
|
)
|
|||||||
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|
—
|
|
|
5
|
|
|||||||
Adjustments for pension and other postretirement plans
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(13
|
)
|
|
—
|
|
|
(13
|
)
|
|||||||
Balance at December 31, 2016
|
57
|
|
|
11,875
|
|
|
1,704
|
|
|
(1,033
|
)
|
|
(391
|
)
|
|
3,285
|
|
|
15,497
|
|
|||||||
Net income (loss)
|
—
|
|
|
—
|
|
|
(456
|
)
|
|
—
|
|
|
—
|
|
|
245
|
|
|
(211
|
)
|
|||||||
Share-based compensation expense
|
—
|
|
|
163
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
163
|
|
|||||||
Dividends—common stock
|
—
|
|
|
—
|
|
|
(111
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(111
|
)
|
|||||||
Repurchase of common stock
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,099
|
)
|
|
—
|
|
|
—
|
|
|
(1,099
|
)
|
|||||||
Subsidiary equity transactions
|
—
|
|
|
(35
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9
|
|
|
(26
|
)
|
|||||||
Distributions to noncontrolling interest owners
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(445
|
)
|
|
(445
|
)
|
|||||||
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
2
|
|
|||||||
Adjustments for pension and other postretirement plans
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
51
|
|
|
—
|
|
|
51
|
|
|||||||
Cumulative effect of accounting change
|
—
|
|
|
(3
|
)
|
|
(28
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(31
|
)
|
|||||||
Balance at December 31, 2017
|
$
|
57
|
|
|
$
|
12,000
|
|
|
$
|
1,109
|
|
|
$
|
(2,132
|
)
|
|
$
|
(338
|
)
|
|
$
|
3,094
|
|
|
$
|
13,790
|
|
|
Years Ended December 31,
|
||||||||||
millions
|
2017
|
|
2016
|
|
2015
|
||||||
Cash Flows from Operating Activities
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
(211
|
)
|
|
$
|
(2,808
|
)
|
|
$
|
(6,812
|
)
|
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
|
|
|
|
|
|
||||||
Depreciation, depletion, and amortization
|
4,279
|
|
|
4,301
|
|
|
4,603
|
|
|||
Deferred income taxes
|
(2,169
|
)
|
|
(1,238
|
)
|
|
(3,152
|
)
|
|||
Dry hole expense and impairments of unproved properties
|
2,221
|
|
|
613
|
|
|
2,267
|
|
|||
Impairments
|
408
|
|
|
227
|
|
|
5,075
|
|
|||
(Gains) losses on divestitures, net
|
(674
|
)
|
|
757
|
|
|
1,022
|
|
|||
Loss on early extinguishment of debt
|
2
|
|
|
155
|
|
|
—
|
|
|||
Total (gains) losses on derivatives, net
|
131
|
|
|
292
|
|
|
(100
|
)
|
|||
Operating portion of net cash received (paid) in settlement of derivative instruments
|
25
|
|
|
267
|
|
|
335
|
|
|||
Other
|
303
|
|
|
342
|
|
|
320
|
|
|||
Changes in assets and liabilities
|
|
|
|
|
|
||||||
Tronox-related contingent liability
|
—
|
|
|
—
|
|
|
(5,210
|
)
|
|||
(Increase) decrease in accounts receivable
|
(147
|
)
|
|
677
|
|
|
(2
|
)
|
|||
Increase (decrease) in accounts payable and other current liabilities
|
(32
|
)
|
|
(443
|
)
|
|
(697
|
)
|
|||
Other items, net
|
(127
|
)
|
|
(142
|
)
|
|
474
|
|
|||
Net cash provided by (used in) operating activities
|
4,009
|
|
|
3,000
|
|
|
(1,877
|
)
|
|||
Cash Flows from Investing Activities
|
|
|
|
|
|
||||||
Additions to properties and equipment
|
(5,031
|
)
|
|
(3,505
|
)
|
|
(6,067
|
)
|
|||
Acquisition of businesses
|
25
|
|
|
(1,740
|
)
|
|
(3
|
)
|
|||
Divestitures of properties and equipment and other assets
|
4,008
|
|
|
2,356
|
|
|
1,415
|
|
|||
Other, net
|
(30
|
)
|
|
127
|
|
|
(116
|
)
|
|||
Net cash provided by (used in) investing activities
|
(1,028
|
)
|
|
(2,762
|
)
|
|
(4,771
|
)
|
|||
Cash Flows from Financing Activities
|
|
|
|
|
|
||||||
Borrowings, net of issuance costs
|
369
|
|
|
6,042
|
|
|
4,632
|
|
|||
Repayments of debt
|
(58
|
)
|
|
(6,832
|
)
|
|
(4,033
|
)
|
|||
Financing portion of net cash received (paid) for derivative instruments
|
(165
|
)
|
|
(333
|
)
|
|
(35
|
)
|
|||
Increase (decrease) in outstanding checks
|
(43
|
)
|
|
(103
|
)
|
|
(23
|
)
|
|||
Dividends paid
|
(111
|
)
|
|
(105
|
)
|
|
(553
|
)
|
|||
Repurchase of common stock
|
(1,092
|
)
|
|
(38
|
)
|
|
(55
|
)
|
|||
Issuance of common stock
|
—
|
|
|
2,188
|
|
|
34
|
|
|||
Sale of subsidiary units
|
—
|
|
|
1,163
|
|
|
187
|
|
|||
Issuance of tangible equity units — equity component
|
—
|
|
|
—
|
|
|
348
|
|
|||
Distributions to noncontrolling interest owners
|
(445
|
)
|
|
(362
|
)
|
|
(282
|
)
|
|||
Proceeds from conveyance of future hard-minerals royalty revenues,
net of transaction costs
|
—
|
|
|
413
|
|
|
—
|
|
|||
Payments of future hard-minerals royalty revenues conveyed
|
(50
|
)
|
|
(25
|
)
|
|
—
|
|
|||
Other financing activities
|
(18
|
)
|
|
—
|
|
|
—
|
|
|||
Net cash provided by (used in) financing activities
|
(1,613
|
)
|
|
2,008
|
|
|
220
|
|
|||
Effect of Exchange Rate Changes on Cash
|
1
|
|
|
(1
|
)
|
|
(2
|
)
|
|||
Net Increase (Decrease) in Cash and Cash Equivalents
|
1,369
|
|
|
2,245
|
|
|
(6,430
|
)
|
|||
Cash and Cash Equivalents at Beginning of Period
|
3,184
|
|
|
939
|
|
|
7,369
|
|
|||
Cash and Cash Equivalents at End of Period
|
$
|
4,553
|
|
|
$
|
3,184
|
|
|
$
|
939
|
|
•
|
Exploration and Production
—No significant impact is expected for the recognition, measurement, or presentation of oil, natural-gas, or NGLs sales revenues.
|
•
|
WES Midstream and Other Midstream
—Gathering and processing revenues will decrease for contracts where the Company is acting as an agent for its processing customer in the sale of processed volumes and increase for contracts with noncash consideration that will generally be valued at current market prices of the commodity received, with an offset in gathering and processing expense. The magnitude of these changes is dependent on future customer volumes subject to the impacted contracts and commodity prices for those volumes. While reported gathering and processing revenues and expenses will be materially reduced, these presentation changes will not impact net earnings.
|
millions
|
2017
|
|
2016
|
||||
Oil
|
$
|
165
|
|
|
$
|
169
|
|
Natural gas
|
29
|
|
|
38
|
|
||
NGLs
|
122
|
|
|
106
|
|
||
Total inventories
|
$
|
316
|
|
|
$
|
313
|
|
millions
|
|
|
||
Current assets
|
|
$
|
8
|
|
Properties and equipment
|
|
2,492
|
|
|
Other assets
|
|
145
|
|
|
AROs
|
|
(816
|
)
|
|
Net assets acquired
|
|
$
|
1,829
|
|
Accounts payable
|
|
(5
|
)
|
|
Other long-term liabilities
|
|
(109
|
)
|
|
Cash paid
|
|
$
|
1,715
|
|
millions
|
2016
|
|
2015
|
||||
Revenues
|
$
|
8,849
|
|
|
$
|
9,786
|
|
Net income (loss)
|
(2,623
|
)
|
|
(6,560
|
)
|
millions
|
2017
|
|
2016
|
|
2015
|
||||||
Proceeds received, net of closing adjustments
|
$
|
4,008
|
|
|
$
|
2,356
|
|
|
$
|
1,415
|
|
Gains (losses) on divestitures, net
(1) (2)
|
674
|
|
|
(757
|
)
|
|
(1,022
|
)
|
(1)
|
Includes goodwill allocated to divestitures of
$209 million
in
2017
,
$397 million
in
2016
, and
$184 million
in
2015
.
|
(2)
|
Includes the
$126 million
gain related to the property exchange discussed above.
|
•
|
Eagleford assets in South Texas, included in the Exploration and Production reporting segment, for net proceeds of
$2.1 billion
and a net gain of
$729 million
|
•
|
Eaglebine assets in Southeast Texas, included in the Exploration and Production reporting segment, for net proceeds of
$533 million
and a net gain of
$282 million
|
•
|
CBM assets in Utah, included in the Exploration and Production and WES Midstream reporting segments, for net proceeds of
$69 million
and a net loss of
$52 million
|
•
|
Marcellus assets in Pennsylvania, included in the Exploration and Production and Other Midstream reporting segments, for net proceeds of
$951 million
and net losses of
$55 million
in
2017
and
$129 million
in
2016
|
•
|
Moxa assets in Wyoming, included in the Exploration and Production reporting segment, for net proceeds of
$313 million
and a net loss of
$204 million
|
•
|
Hugoton assets in Kansas, included in the Exploration and Production and WES Midstream reporting segments, for net proceeds of
$159 million
and a loss of
$4 million
|
•
|
Ozona and Steward assets in West Texas, included in the Exploration and Production and Other Midstream reporting segments, for net proceeds of
$221 million
and a loss of
$52 million
|
•
|
Wamsutter assets in Wyoming, included in the Exploration and Production reporting segment, for net proceeds of
$588 million
and a loss of
$58 million
|
•
|
Elm Grove assets in East Texas, included in the Exploration and Production reporting segment, for net proceeds of
$89 million
and a loss of
$64 million
|
•
|
East Chalk and Carthage assets in East Texas/Louisiana, included in the Exploration and Production and Other Midstream reporting segments, for net proceeds of
$1.0 billion
and a net loss of
$439 million
|
•
|
Freestone and Dew Pinnacle assets in East Texas, included in the Exploration and Production and WES Midstream reporting segments, for net proceeds of
$425 million
and a loss of
$110 million
|
•
|
EOR assets in Wyoming, included in the Exploration and Production reporting segment, for net proceeds of
$675 million
and a loss of
$350 million
|
•
|
Powder River Basin CBM assets in Wyoming, included in the Exploration and Production and Other Midstream reporting segments, for net proceeds of
$154 million
and a loss of
$538 million
|
millions
|
2017
|
|
2016
|
||||
Exploration and Production
(1)
|
$
|
52,364
|
|
|
$
|
57,581
|
|
WES Midstream
|
7,871
|
|
|
6,862
|
|
||
Other Midstream
|
2,012
|
|
|
1,785
|
|
||
Other
|
2,803
|
|
|
2,785
|
|
||
Gross properties and equipment
|
$
|
65,050
|
|
|
$
|
69,013
|
|
Less accumulated DD&A
|
37,599
|
|
|
36,845
|
|
||
Net properties and equipment
|
$
|
27,451
|
|
|
$
|
32,168
|
|
(1)
|
Includes costs associated with unproved properties of
$2.4 billion
at
December 31, 2017
, and
$4.1 billion
at
December 31, 2016
.
|
|
2017
|
|
2016
|
|
2015
|
||||||||||||||||||
millions
|
Impairment
|
|
Fair Value
(1)
|
|
Impairment
|
|
Fair Value
(1)
|
|
Impairment
|
|
Fair Value
(1)
|
||||||||||||
Exploration and Production
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
U.S. onshore properties
|
$
|
2
|
|
|
$
|
3
|
|
|
$
|
28
|
|
|
$
|
617
|
|
|
$
|
3,684
|
|
|
$
|
1,253
|
|
Gulf of Mexico properties
|
227
|
|
|
216
|
|
|
27
|
|
|
61
|
|
|
349
|
|
|
65
|
|
||||||
Cost-method investment
(2)
|
—
|
|
|
—
|
|
|
59
|
|
|
—
|
|
|
3
|
|
|
59
|
|
||||||
WES Midstream
|
176
|
|
|
58
|
|
|
16
|
|
|
3
|
|
|
515
|
|
|
36
|
|
||||||
Other Midstream
|
2
|
|
|
—
|
|
|
57
|
|
|
29
|
|
|
524
|
|
|
176
|
|
||||||
Other
|
1
|
|
|
—
|
|
|
40
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total impairments
|
$
|
408
|
|
|
$
|
277
|
|
|
$
|
227
|
|
|
$
|
710
|
|
|
$
|
5,075
|
|
|
$
|
1,589
|
|
(1)
|
Measured as of the impairment date using the income approach and Level 3 inputs. The primary assumptions used to estimate undiscounted future net cash flows include anticipated future production, commodity prices, and capital and operating costs.
|
(2)
|
The after-tax net investment fair value was
$32 million
at December 31, 2015.
|
millions
|
2017
|
|
2016
|
|
2015
|
||||||
Balance at January 1
|
$
|
1,230
|
|
|
$
|
1,124
|
|
|
$
|
1,522
|
|
Additions pending the determination of proved reserves
|
349
|
|
|
490
|
|
|
461
|
|
|||
Divestitures and other
|
(36
|
)
|
|
(11
|
)
|
|
(33
|
)
|
|||
Reclassifications to proved properties
|
(41
|
)
|
|
(50
|
)
|
|
(104
|
)
|
|||
Charges to exploration expense
|
(977
|
)
|
|
(323
|
)
|
|
(722
|
)
|
|||
Balance at December 31
|
$
|
525
|
|
|
$
|
1,230
|
|
|
$
|
1,124
|
|
•
|
Shenandoah
The Company expensed
$437 million
of exploratory well costs, including
$326 million
of costs that were suspended as of
December 31, 2016
. The Shenandoah-6 appraisal well and subsequent sidetrack, which completed appraisal activities in April 2017 and did not encounter oil in the eastern portion of the field. Given the results of this well and the commodity-price environment, the Company suspended further appraisal activities.
|
•
|
Phobos
The Company expensed
$215 million
of exploratory well costs, including
$99 million
of costs that were suspended as of
December 31, 2016,
in the third quarter of 2017 related to wells at the Phobos project. These wells found insufficient quantities of oil pay to justify development in the current price environment.
|
•
|
Warrior
The Company expensed
$108 million
of exploratory well costs in the third quarter of 2017 related to the northern appraisal well and sidetrack at the Warrior project. These wells found insufficient quantities of oil pay to justify development of the northern portion of the field in the current price environment. Evaluation of tie-back opportunities in the southern portion of the field is ongoing.
|
•
|
The Company expensed
$243 million
of exploratory well costs, including
$102 million
of costs that were suspended as of
December 31, 2016,
related to wells in the Grand Fuerte area in Colombia due to insufficient progress on contractual and fiscal reforms needed for deepwater gas development. All remaining leases are contractually in good standing.
|
•
|
The Company expensed
$329 million
of exploratory well costs, including
$237 million
of costs that were suspended as of
December 31, 2016,
in Côte d’Ivoire. During 2017, the Company had unsuccessful drilling activities in the south channel of the Paon prospect and in Block CI-527 and after further evaluation of the well results, Anadarko withdrew from all Côte d’Ivoire blocks.
|
•
|
The Company expensed
$231 million
of suspended exploratory well costs in the Gulf of Mexico primarily related to the Yeti project, as the Company did not expect to have exploration activities on this prospect in the foreseeable future, and a Shenandoah well that was expensed, as it was no longer reasonably possible that the wellbore could be used in the development of the project.
|
•
|
The Company expensed
$92 million
of suspended exploratory well costs in Mozambique. The Tubarão-Tigre discovery wells were expensed based on the outlook for development viability, the commodity market conditions, and the complexity introduced by the depth and characteristics of the reservoir. The Orca-4 well was expensed after additional reservoir analysis and the determination that the well was not associated with the first three Orca wells.
|
millions except projects
|
Number of Projects
|
|
Total
|
|
2016
|
|
2015
|
|
2014 and
prior |
||||||||
U.S. Onshore
|
9
|
|
$
|
44
|
|
|
$
|
10
|
|
|
$
|
4
|
|
|
$
|
30
|
|
U.S. Offshore
|
1
|
|
74
|
|
|
74
|
|
|
—
|
|
|
—
|
|
||||
International
|
3
|
|
206
|
|
|
14
|
|
|
87
|
|
|
105
|
|
||||
|
13
|
|
$
|
324
|
|
|
$
|
98
|
|
|
$
|
91
|
|
|
$
|
135
|
|
millions
|
2017
|
|
2016
|
||||
Gross carrying amount
|
$
|
1,013
|
|
|
$
|
1,013
|
|
Accumulated amortization
|
(140
|
)
|
|
(109
|
)
|
||
Net carrying amount
|
$
|
873
|
|
|
$
|
904
|
|
Amortization expense
|
$
|
31
|
|
|
$
|
32
|
|
millions
|
December 31, 2017
|
|
December 31, 2016
|
||||
Accrued income taxes
|
$
|
71
|
|
|
$
|
6
|
|
Interest payable
|
246
|
|
|
244
|
|
||
Production, property, and other taxes payable
|
216
|
|
|
239
|
|
||
Accrued employee benefits
|
210
|
|
|
355
|
|
||
Derivatives
|
384
|
|
|
175
|
|
||
Other
|
183
|
|
|
218
|
|
||
Total other current liabilities
|
$
|
1,310
|
|
|
$
|
1,237
|
|
|
|
2018 Settlement
|
||
Oil
|
|
|
||
Two-Way Collars (MBbls/d)
|
|
108
|
|
|
Average price per barrel
|
|
|
||
Ceiling sold price (call)
|
|
$
|
60.48
|
|
Floor purchased price (put)
|
|
$
|
50.00
|
|
Fixed-Price Contracts (MBbls/d)
|
|
84
|
|
|
Average price per barrel
|
|
$
|
61.45
|
|
Natural Gas
|
|
|
||
Three-Way Collars (thousand MMBtu/d)
|
|
250
|
|
|
Average price per MMBtu
|
|
|
||
Ceiling sold price (call)
|
|
$
|
3.54
|
|
Floor purchased price (put)
|
|
$
|
2.75
|
|
Floor sold price (put)
|
|
$
|
2.00
|
|
millions except percentages
|
|
|
|
Mandatory
|
|
Weighted-Average
|
|||
Notional Principal Amount
|
|
Reference Period
|
|
Termination Date
|
|
Interest Rate
|
|||
$
|
550
|
|
|
|
September 2016 - 2046
|
|
September 2020
|
|
6.418%
|
$
|
250
|
|
|
|
September 2016 - 2046
|
|
September 2022
|
|
6.809%
|
$
|
200
|
|
|
|
September 2017 - 2047
|
|
September 2018
|
|
6.049%
|
$
|
100
|
|
|
|
September 2017 - 2047
|
|
September 2020
|
|
6.891%
|
$
|
250
|
|
|
|
September 2017 - 2047
|
|
September 2021
|
|
6.570%
|
$
|
250
|
|
|
|
September 2017 - 2047
|
|
September 2023
|
|
6.761%
|
millions
|
|
Gross
Derivative Assets
|
|
Gross
Derivative Liabilities
|
||||||||||||
Balance Sheet Classification
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
||||||||
Commodity derivatives
|
|
|
|
|
|
|
|
|
||||||||
Other current assets
|
|
$
|
7
|
|
|
$
|
10
|
|
|
$
|
(1
|
)
|
|
$
|
(3
|
)
|
Other assets
|
|
2
|
|
|
9
|
|
|
—
|
|
|
—
|
|
||||
Other current liabilities
|
|
45
|
|
|
66
|
|
|
(206
|
)
|
|
(201
|
)
|
||||
Other liabilities
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
(12
|
)
|
||||
|
|
54
|
|
|
85
|
|
|
(209
|
)
|
|
(216
|
)
|
||||
Interest-rate derivatives
|
|
|
|
|
|
|
|
|
||||||||
Other current assets
|
|
14
|
|
|
8
|
|
|
—
|
|
|
—
|
|
||||
Other assets
|
|
40
|
|
|
23
|
|
|
—
|
|
|
—
|
|
||||
Other current liabilities
|
|
—
|
|
|
—
|
|
|
(236
|
)
|
|
(48
|
)
|
||||
Other liabilities
|
|
—
|
|
|
—
|
|
|
(1,183
|
)
|
|
(1,328
|
)
|
||||
|
|
54
|
|
|
31
|
|
|
(1,419
|
)
|
|
(1,376
|
)
|
||||
Total derivatives
|
|
$
|
108
|
|
|
$
|
116
|
|
|
$
|
(1,628
|
)
|
|
$
|
(1,592
|
)
|
millions
|
|
|
|
|
|
|
||||||
Classification of (Gain) Loss Recognized
|
|
2017
|
|
2016
|
|
2015
|
||||||
Commodity derivatives
|
|
|
|
|
|
|
||||||
Gathering, processing, and marketing sales
(1)
|
|
$
|
(4
|
)
|
|
$
|
6
|
|
|
$
|
(1
|
)
|
(Gains) losses on derivatives, net
|
|
3
|
|
|
147
|
|
|
(367
|
)
|
|||
Interest-rate derivatives
|
|
|
|
|
|
|
||||||
(Gains) losses on derivatives, net
|
|
132
|
|
|
139
|
|
|
268
|
|
|||
Total (gains) losses on derivatives, net
|
|
$
|
131
|
|
|
$
|
292
|
|
|
$
|
(100
|
)
|
(1)
|
Represents the effect of Marketing and Trading Derivative Activities.
|
millions
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Netting
(1)
|
|
Collateral
|
|
Total
|
||||||||||||
December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Assets
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity derivatives
|
$
|
1
|
|
|
$
|
53
|
|
|
$
|
—
|
|
|
$
|
(46
|
)
|
|
$
|
(1
|
)
|
|
$
|
7
|
|
Interest-rate derivatives
|
—
|
|
|
54
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
54
|
|
||||||
Total derivative assets
|
$
|
1
|
|
|
$
|
107
|
|
|
$
|
—
|
|
|
$
|
(46
|
)
|
|
$
|
(1
|
)
|
|
$
|
61
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity derivatives
|
$
|
(1
|
)
|
|
$
|
(208
|
)
|
|
$
|
—
|
|
|
$
|
46
|
|
|
$
|
3
|
|
|
$
|
(160
|
)
|
Interest-rate derivatives
|
—
|
|
|
(1,419
|
)
|
|
—
|
|
|
—
|
|
|
170
|
|
|
(1,249
|
)
|
||||||
Total derivative liabilities
|
$
|
(1
|
)
|
|
$
|
(1,627
|
)
|
|
$
|
—
|
|
|
$
|
46
|
|
|
$
|
173
|
|
|
$
|
(1,409
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Assets
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity derivatives
|
$
|
2
|
|
|
$
|
83
|
|
|
$
|
—
|
|
|
$
|
(69
|
)
|
|
$
|
—
|
|
|
$
|
16
|
|
Interest-rate derivatives
|
—
|
|
|
31
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
31
|
|
||||||
Total derivative assets
|
$
|
2
|
|
|
$
|
114
|
|
|
$
|
—
|
|
|
$
|
(69
|
)
|
|
$
|
—
|
|
|
$
|
47
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity derivatives
|
$
|
(3
|
)
|
|
$
|
(213
|
)
|
|
$
|
—
|
|
|
$
|
69
|
|
|
$
|
6
|
|
|
$
|
(141
|
)
|
Interest-rate derivatives
|
—
|
|
|
(1,376
|
)
|
|
—
|
|
|
—
|
|
|
117
|
|
|
(1,259
|
)
|
||||||
Total derivative liabilities
|
$
|
(3
|
)
|
|
$
|
(1,589
|
)
|
|
$
|
—
|
|
|
$
|
69
|
|
|
$
|
123
|
|
|
$
|
(1,400
|
)
|
(1)
|
Represents the impact of netting commodity derivative assets and liabilities with counterparties where the Company has the contractual right and intends to net settle.
|
millions, except price per TEU
|
Equity Component
|
|
Debt Component
|
|
Total
|
||||||
Price per TEU
|
$
|
39.05
|
|
|
$
|
10.95
|
|
|
$
|
50.00
|
|
Gross proceeds
|
359
|
|
|
101
|
|
|
460
|
|
|||
Less issuance costs
|
11
|
|
|
4
|
|
|
15
|
|
|||
Net proceeds
|
$
|
348
|
|
|
$
|
97
|
|
|
$
|
445
|
|
|
|
Settlement Rate per Purchase Contract
(1)
|
||
Applicable Market Value of WGP Common Units
(1)
|
|
WGP Common Units
|
|
APC Shares (if elected)
|
Exceeds $68.0643 (Threshold Appreciation Price)
|
|
0.7346 units (Minimum Settlement Rate)
|
|
a number of shares equal to (a) the Minimum Settlement Rate, multiplied by the applicable market value of WGP common units, divided by (b) 98% of the applicable market value of APC Shares
|
Less than or equal to the Threshold Appreciation Price, but greater than or equal to $56.7083 (Reference Price)
|
|
a number of units equal to $50.00, divided by the applicable market value of WGP common units
|
|
a number of shares equal to $50.00, divided by 98% of the applicable market value of APC Shares
|
Less than the Reference Price
|
|
0.8817 units (Maximum Settlement Rate)
|
|
a number of shares equal to (a) the Maximum Settlement Rate, multiplied by the applicable market value of WGP common units, divided by (b) 98% of the applicable market value of APC Shares
|
(1)
|
The applicable market value is the average of the daily volume-weighted average prices of WGP common units (or APC Shares) for the 20 consecutive trading days beginning on, and including, the 23
rd
scheduled trading day immediately preceding June 7, 2018.
|
|
Carrying Value
|
|
|
||||||||||||||
millions
|
WES
|
|
WGP
(1)
|
|
Anadarko
(2)
|
|
Consolidated
|
|
Description
|
||||||||
Balance at December 31, 2015
|
$
|
2,691
|
|
|
$
|
—
|
|
|
$
|
12,957
|
|
|
$
|
15,648
|
|
|
|
Issuances
|
—
|
|
|
—
|
|
|
794
|
|
|
794
|
|
|
4.850% Senior Notes due 2021
(3)
|
||||
|
—
|
|
|
—
|
|
|
1,088
|
|
|
1,088
|
|
|
5.550% Senior Notes due 2026
(3)
|
||||
|
—
|
|
|
—
|
|
|
1,088
|
|
|
1,088
|
|
|
6.600% Senior Notes due 2046
(3)
|
||||
|
495
|
|
|
—
|
|
|
—
|
|
|
495
|
|
|
WES 4.650% Senior Notes due 2026
|
||||
|
203
|
|
|
—
|
|
|
—
|
|
|
203
|
|
|
WES 5.450% Senior Notes due 2044
|
||||
Borrowings
|
—
|
|
|
—
|
|
|
1,750
|
|
|
1,750
|
|
|
364-Day Facility
|
||||
|
600
|
|
|
—
|
|
|
—
|
|
|
600
|
|
|
WES RCF
|
||||
|
—
|
|
|
28
|
|
|
—
|
|
|
28
|
|
|
WGP RCF
|
||||
Repayments
|
—
|
|
|
—
|
|
|
(1,749
|
)
|
|
(1,749
|
)
|
|
5.950% Senior Notes due 2016
|
||||
|
—
|
|
|
—
|
|
|
(1,994
|
)
|
|
(1,994
|
)
|
|
6.375% Senior Notes due 2017
|
||||
|
—
|
|
|
—
|
|
|
(1,750
|
)
|
|
(1,750
|
)
|
|
364-Day Facility
|
||||
|
(900
|
)
|
|
—
|
|
|
—
|
|
|
(900
|
)
|
|
WES RCF
|
||||
|
—
|
|
|
—
|
|
|
(250
|
)
|
|
(250
|
)
|
|
Commercial paper notes, net
|
||||
|
—
|
|
|
—
|
|
|
(34
|
)
|
|
(34
|
)
|
|
TEUs - senior amortizing notes
|
||||
Other, net
|
2
|
|
|
—
|
|
|
59
|
|
|
61
|
|
|
Amortization of discounts, premiums, and debt issuance costs
|
||||
Balance at December 31, 2016
|
$
|
3,091
|
|
|
$
|
28
|
|
|
$
|
11,959
|
|
|
$
|
15,078
|
|
|
|
Borrowings
|
370
|
|
|
—
|
|
|
—
|
|
|
370
|
|
|
WES RCF
|
||||
Repayments
|
—
|
|
|
—
|
|
|
(6
|
)
|
|
(6
|
)
|
|
7.000% Debentures due 2027
|
||||
|
—
|
|
|
—
|
|
|
(3
|
)
|
|
(3
|
)
|
|
6.625% Debentures due 2028
|
||||
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
(1
|
)
|
|
7.950% Debentures due 2029
|
||||
|
—
|
|
|
—
|
|
|
(34
|
)
|
|
(34
|
)
|
|
TEUs - senior amortizing notes
|
||||
Other, net
|
4
|
|
|
—
|
|
|
50
|
|
|
54
|
|
|
Amortization of discounts, premiums, and debt issuance costs
|
||||
Balance at December 31, 2017
|
$
|
3,465
|
|
|
$
|
28
|
|
|
$
|
11,965
|
|
|
$
|
15,458
|
|
|
|
(1)
|
Excludes WES.
|
(2)
|
Excludes WES and WGP
|
(3)
|
Represent senior notes issued in March 2016.
|
|
December 31, 2017
|
||||||||||||||
millions
|
WES
|
|
WGP
(1)
|
|
Anadarko
(2)
|
|
Consolidated
|
||||||||
7.050% Debentures due 2018
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
114
|
|
|
$
|
114
|
|
TEUs - senior amortizing notes due 2018
|
—
|
|
|
—
|
|
|
17
|
|
|
17
|
|
||||
WES 2.600% Senior Notes due 2018
|
350
|
|
|
—
|
|
|
—
|
|
|
350
|
|
||||
6.950% Senior Notes due 2019
|
—
|
|
|
—
|
|
|
300
|
|
|
300
|
|
||||
8.700% Senior Notes due 2019
|
—
|
|
|
—
|
|
|
600
|
|
|
600
|
|
||||
4.850% Senior Notes due 2021
|
—
|
|
|
—
|
|
|
800
|
|
|
800
|
|
||||
WES 5.375% Senior Notes due 2021
|
500
|
|
|
—
|
|
|
—
|
|
|
500
|
|
||||
WES 4.000% Senior Notes due 2022
|
670
|
|
|
—
|
|
|
—
|
|
|
670
|
|
||||
3.450% Senior Notes due 2024
|
—
|
|
|
—
|
|
|
625
|
|
|
625
|
|
||||
6.950% Senior Notes due 2024
|
—
|
|
|
—
|
|
|
650
|
|
|
650
|
|
||||
WES 3.950% Senior Notes due 2025
|
500
|
|
|
—
|
|
|
—
|
|
|
500
|
|
||||
WES 4.650% Senior Notes due 2026
|
500
|
|
|
—
|
|
|
—
|
|
|
500
|
|
||||
5.550% Senior Notes due 2026
|
—
|
|
|
—
|
|
|
1,100
|
|
|
1,100
|
|
||||
7.500% Debentures due 2026
|
—
|
|
|
—
|
|
|
112
|
|
|
112
|
|
||||
7.000% Debentures due 2027
|
—
|
|
|
—
|
|
|
48
|
|
|
48
|
|
||||
7.125% Debentures due 2027
|
—
|
|
|
—
|
|
|
150
|
|
|
150
|
|
||||
6.625% Debentures due 2028
|
—
|
|
|
—
|
|
|
14
|
|
|
14
|
|
||||
7.150% Debentures due 2028
|
—
|
|
|
—
|
|
|
235
|
|
|
235
|
|
||||
7.200% Debentures due 2029
|
—
|
|
|
—
|
|
|
135
|
|
|
135
|
|
||||
7.950% Debentures due 2029
|
—
|
|
|
—
|
|
|
116
|
|
|
116
|
|
||||
7.500% Senior Notes due 2031
|
—
|
|
|
—
|
|
|
900
|
|
|
900
|
|
||||
7.875% Senior Notes due 2031
|
—
|
|
|
—
|
|
|
500
|
|
|
500
|
|
||||
Zero Coupon Senior Notes due 2036
|
—
|
|
|
—
|
|
|
2,360
|
|
|
2,360
|
|
||||
6.450% Senior Notes due 2036
|
—
|
|
|
—
|
|
|
1,750
|
|
|
1,750
|
|
||||
7.950% Senior Notes due 2039
|
—
|
|
|
—
|
|
|
325
|
|
|
325
|
|
||||
6.200% Senior Notes due 2040
|
—
|
|
|
—
|
|
|
750
|
|
|
750
|
|
||||
4.500% Senior Notes due 2044
|
—
|
|
|
—
|
|
|
625
|
|
|
625
|
|
||||
WES 5.450% Senior Notes due 2044
|
600
|
|
|
—
|
|
|
—
|
|
|
600
|
|
||||
6.600% Senior Notes due 2046
|
—
|
|
|
—
|
|
|
1,100
|
|
|
1,100
|
|
||||
7.730% Debentures due 2096
|
—
|
|
|
—
|
|
|
61
|
|
|
61
|
|
||||
7.500% Debentures due 2096
|
—
|
|
|
—
|
|
|
78
|
|
|
78
|
|
||||
7.250% Debentures due 2096
|
—
|
|
|
—
|
|
|
49
|
|
|
49
|
|
||||
WES RCF
|
370
|
|
|
—
|
|
|
—
|
|
|
370
|
|
||||
WGP RCF
|
—
|
|
|
28
|
|
|
—
|
|
|
28
|
|
||||
Total borrowings at face value
|
$
|
3,490
|
|
|
$
|
28
|
|
|
$
|
13,514
|
|
|
$
|
17,032
|
|
Net unamortized discounts, premiums, and debt issuance costs
(3)
|
(25
|
)
|
|
—
|
|
|
(1,549
|
)
|
|
(1,574
|
)
|
||||
Total borrowings
(4)
|
3,465
|
|
|
28
|
|
|
11,965
|
|
|
15,458
|
|
||||
Capital lease obligations
|
—
|
|
|
—
|
|
|
231
|
|
|
231
|
|
||||
Less short-term debt
|
—
|
|
|
—
|
|
|
142
|
|
|
142
|
|
||||
Total long-term debt
|
$
|
3,465
|
|
|
$
|
28
|
|
|
$
|
12,054
|
|
|
$
|
15,547
|
|
|
December 31, 2016
|
||||||||||||||
millions
|
WES
|
|
WGP
(1)
|
|
Anadarko
(2)
|
|
Consolidated
|
||||||||
7.050% Debentures due 2018
|
—
|
|
|
—
|
|
|
114
|
|
|
114
|
|
||||
TEUs - senior amortizing notes due 2018
|
—
|
|
|
—
|
|
|
51
|
|
|
51
|
|
||||
WES 2.600% Senior Notes due 2018
|
350
|
|
|
—
|
|
|
—
|
|
|
350
|
|
||||
6.950% Senior Notes due 2019
|
—
|
|
|
—
|
|
|
300
|
|
|
300
|
|
||||
8.700% Senior Notes due 2019
|
—
|
|
|
—
|
|
|
600
|
|
|
600
|
|
||||
4.850% Senior Notes due 2021
|
—
|
|
|
—
|
|
|
800
|
|
|
800
|
|
||||
WES 5.375% Senior Notes due 2021
|
500
|
|
|
—
|
|
|
—
|
|
|
500
|
|
||||
WES 4.000% Senior Notes due 2022
|
670
|
|
|
—
|
|
|
—
|
|
|
670
|
|
||||
3.450% Senior Notes due 2024
|
—
|
|
|
—
|
|
|
625
|
|
|
625
|
|
||||
6.950% Senior Notes due 2024
|
—
|
|
|
—
|
|
|
650
|
|
|
650
|
|
||||
WES 3.950% Senior Notes due 2025
|
500
|
|
|
—
|
|
|
—
|
|
|
500
|
|
||||
WES 4.650% Senior Notes due 2026
|
500
|
|
|
—
|
|
|
—
|
|
|
500
|
|
||||
5.550% Senior Notes due 2026
|
—
|
|
|
—
|
|
|
1,100
|
|
|
1,100
|
|
||||
7.500% Debentures due 2026
|
—
|
|
|
—
|
|
|
112
|
|
|
112
|
|
||||
7.000% Debentures due 2027
|
—
|
|
|
—
|
|
|
54
|
|
|
54
|
|
||||
7.125% Debentures due 2027
|
—
|
|
|
—
|
|
|
150
|
|
|
150
|
|
||||
6.625% Debentures due 2028
|
—
|
|
|
—
|
|
|
17
|
|
|
17
|
|
||||
7.150% Debentures due 2028
|
—
|
|
|
—
|
|
|
235
|
|
|
235
|
|
||||
7.200% Debentures due 2029
|
—
|
|
|
—
|
|
|
135
|
|
|
135
|
|
||||
7.950% Debentures due 2029
|
—
|
|
|
—
|
|
|
117
|
|
|
117
|
|
||||
7.500% Senior Notes due 2031
|
—
|
|
|
—
|
|
|
900
|
|
|
900
|
|
||||
7.875% Senior Notes due 2031
|
—
|
|
|
—
|
|
|
500
|
|
|
500
|
|
||||
Zero Coupon Senior Notes due 2036
|
—
|
|
|
—
|
|
|
2,360
|
|
|
2,360
|
|
||||
6.450% Senior Notes due 2036
|
—
|
|
|
—
|
|
|
1,750
|
|
|
1,750
|
|
||||
7.950% Senior Notes due 2039
|
—
|
|
|
—
|
|
|
325
|
|
|
325
|
|
||||
6.200% Senior Notes due 2040
|
—
|
|
|
—
|
|
|
750
|
|
|
750
|
|
||||
4.500% Senior Notes due 2044
|
—
|
|
|
—
|
|
|
625
|
|
|
625
|
|
||||
WES 5.450% Senior Notes due 2044
|
600
|
|
|
—
|
|
|
—
|
|
|
600
|
|
||||
6.600% Senior Notes due 2046
|
—
|
|
|
—
|
|
|
1,100
|
|
|
1,100
|
|
||||
7.730% Debentures due 2096
|
—
|
|
|
—
|
|
|
61
|
|
|
61
|
|
||||
7.500% Debentures due 2096
|
—
|
|
|
—
|
|
|
78
|
|
|
78
|
|
||||
7.250% Debentures due 2096
|
—
|
|
|
—
|
|
|
49
|
|
|
49
|
|
||||
WGP RCF
|
—
|
|
|
28
|
|
|
—
|
|
|
28
|
|
||||
Total borrowings at face value
|
$
|
3,120
|
|
|
$
|
28
|
|
|
$
|
13,558
|
|
|
$
|
16,706
|
|
Net unamortized discounts, premiums, and debt issuance costs
(3)
|
(29
|
)
|
|
—
|
|
|
(1,599
|
)
|
|
(1,628
|
)
|
||||
Total borrowings
(4)
|
3,091
|
|
|
28
|
|
|
11,959
|
|
|
15,078
|
|
||||
Capital lease obligations
|
—
|
|
|
—
|
|
|
245
|
|
|
245
|
|
||||
Less short-term debt
|
—
|
|
|
—
|
|
|
42
|
|
|
42
|
|
||||
Total long-term debt
|
$
|
3,091
|
|
|
$
|
28
|
|
|
$
|
12,162
|
|
|
$
|
15,281
|
|
(1)
|
Excludes WES.
|
(2)
|
Excludes WES and WGP.
|
(3)
|
Unamortized discounts, premiums, and debt issuance costs are amortized over the term of the related debt. Debt issuance costs related to RCFs are included in other current assets and other assets on the Company’s Consolidated Balance Sheets.
|
(4)
|
The Company’s outstanding borrowings, except for borrowings under the WGP RCF, are senior unsecured.
|
|
Principal Amount of Debt Maturities
|
||||||||||||||
millions
|
WES
|
|
WGP
(1)
|
|
Anadarko
(2)
|
|
Consolidated
|
||||||||
2018
|
$
|
350
|
|
|
$
|
—
|
|
|
$
|
131
|
|
|
$
|
481
|
|
2019
|
—
|
|
|
28
|
|
|
900
|
|
|
928
|
|
||||
2020
|
370
|
|
|
—
|
|
|
—
|
|
|
370
|
|
||||
2021
|
500
|
|
|
—
|
|
|
800
|
|
|
1,300
|
|
||||
2022
|
670
|
|
|
—
|
|
|
—
|
|
|
670
|
|
(1)
|
Excludes WES.
|
(2)
|
Excludes WES and WGP.
|
millions
|
|
||
2018
|
$
|
53
|
|
2019
|
42
|
|
|
2020
|
43
|
|
|
2021
|
42
|
|
|
2022
|
42
|
|
|
Remaining years
|
365
|
|
|
Total future minimum lease payments
|
$
|
587
|
|
Less portion representing imputed interest
|
356
|
|
|
Capital lease obligations
|
$
|
231
|
|
millions
|
2017
|
|
2016
|
|
2015
|
||||||
Debt and other
|
$
|
1,003
|
|
|
$
|
1,022
|
|
|
$
|
989
|
|
Capitalized interest
|
(71
|
)
|
|
(132
|
)
|
|
(164
|
)
|
|||
Total interest expense
|
$
|
932
|
|
|
$
|
890
|
|
|
$
|
825
|
|
millions
|
2017
|
|
2016
|
|
2015
|
||||||
Current
|
|
|
|
|
|
||||||
Federal
|
$
|
236
|
|
|
$
|
(140
|
)
|
|
$
|
(177
|
)
|
State
|
48
|
|
|
(1
|
)
|
|
(18
|
)
|
|||
Foreign
|
414
|
|
|
378
|
|
|
495
|
|
|||
|
698
|
|
|
237
|
|
|
300
|
|
|||
Deferred
|
|
|
|
|
|
||||||
Federal
|
(2,082
|
)
|
|
(1,020
|
)
|
|
(2,929
|
)
|
|||
State
|
(17
|
)
|
|
(148
|
)
|
|
(145
|
)
|
|||
Foreign
|
(76
|
)
|
|
(90
|
)
|
|
(103
|
)
|
|||
|
(2,175
|
)
|
|
(1,258
|
)
|
|
(3,177
|
)
|
|||
Total income tax expense (benefit)
|
$
|
(1,477
|
)
|
|
$
|
(1,021
|
)
|
|
$
|
(2,877
|
)
|
millions except percentages
|
2017
|
|
2016
|
|
2015
|
||||||
Income (loss) before income taxes
|
|
|
|
|
|
||||||
Domestic
|
$
|
(1,322
|
)
|
|
$
|
(3,728
|
)
|
|
$
|
(9,155
|
)
|
Foreign
|
(366
|
)
|
|
(101
|
)
|
|
(534
|
)
|
|||
Total
|
$
|
(1,688
|
)
|
|
$
|
(3,829
|
)
|
|
$
|
(9,689
|
)
|
U.S. federal statutory tax rate
|
35
|
%
|
|
35
|
%
|
|
35
|
%
|
|||
Tax computed at the U.S. federal statutory rate
|
$
|
(591
|
)
|
|
$
|
(1,340
|
)
|
|
$
|
(3,391
|
)
|
(Income) loss attributable to noncontrolling interests
|
(85
|
)
|
|
(92
|
)
|
|
42
|
|
|||
Adjustments resulting from
|
|
|
|
|
|
||||||
State income taxes (net of federal income tax benefit)
|
25
|
|
|
(108
|
)
|
|
(81
|
)
|
|||
U.S. federal tax reform
|
(1,168
|
)
|
|
—
|
|
|
—
|
|
|||
Tax impact from foreign operations
|
166
|
|
|
80
|
|
|
299
|
|
|||
Non-deductible Algerian exceptional profits tax
|
110
|
|
|
106
|
|
|
102
|
|
|||
Net changes in uncertain tax positions
|
90
|
|
|
90
|
|
|
54
|
|
|||
Dispositions of non-deductible goodwill
|
6
|
|
|
205
|
|
|
62
|
|
|||
Other, net
|
(30
|
)
|
|
38
|
|
|
36
|
|
|||
Total income tax expense (benefit)
|
$
|
(1,477
|
)
|
|
$
|
(1,021
|
)
|
|
$
|
(2,877
|
)
|
Effective tax rate
|
88
|
%
|
|
27
|
%
|
|
30
|
%
|
millions
|
2017
|
|
2016
|
||||
Federal
|
$
|
(1,758
|
)
|
|
$
|
(3,805
|
)
|
State, net of federal
|
(200
|
)
|
|
(173
|
)
|
||
Foreign
|
(255
|
)
|
|
(332
|
)
|
||
Total deferred taxes
|
$
|
(2,213
|
)
|
|
$
|
(4,310
|
)
|
millions
|
2017
|
|
2016
|
||||
Deferred tax liabilities
|
|
|
|
||||
Oil and gas exploration and development operations
|
$
|
(2,599
|
)
|
|
$
|
(5,025
|
)
|
Midstream and other depreciable properties
|
(543
|
)
|
|
(870
|
)
|
||
Mineral operations
|
(312
|
)
|
|
(550
|
)
|
||
Other
|
(54
|
)
|
|
(147
|
)
|
||
Gross long-term deferred tax liabilities
|
(3,508
|
)
|
|
(6,592
|
)
|
||
Deferred tax assets
|
|
|
|
||||
Oil and gas exploration and development costs
|
309
|
|
|
250
|
|
||
Foreign and state net operating loss carryforwards
|
562
|
|
|
648
|
|
||
U.S. foreign tax credit carryforwards
|
2,685
|
|
|
1,834
|
|
||
Compensation and benefit plans
|
365
|
|
|
672
|
|
||
Mark to market on derivatives
|
232
|
|
|
324
|
|
||
Other
|
166
|
|
|
309
|
|
||
Gross long-term deferred tax assets
|
4,319
|
|
|
4,037
|
|
||
Valuation allowances on deferred tax assets not expected to be realized
|
(3,024
|
)
|
|
(1,755
|
)
|
||
Net long-term deferred tax assets
|
1,295
|
|
|
2,282
|
|
||
Total deferred taxes
|
$
|
(2,213
|
)
|
|
$
|
(4,310
|
)
|
millions
|
2017
|
|
2016
|
|
2015
|
||||||
Balance at January 1
|
$
|
(1,755
|
)
|
|
$
|
(1,403
|
)
|
|
$
|
(864
|
)
|
Changes due to U.S. foreign tax credits
|
(1,287
|
)
|
|
(477
|
)
|
|
(384
|
)
|
|||
Changes due to foreign and state net operating loss carryforwards
|
75
|
|
|
13
|
|
|
10
|
|
|||
Changes due to foreign capitalized costs
|
(57
|
)
|
|
112
|
|
|
(165
|
)
|
|||
Balance at December 31
|
$
|
(3,024
|
)
|
|
$
|
(1,755
|
)
|
|
$
|
(1,403
|
)
|
millions
|
Domestic
|
|
Foreign
|
|
Expiration
|
||||
Net operating loss—foreign
|
$
|
—
|
|
|
$
|
1,184
|
|
|
2018 - Indefinite
|
Net operating loss—state
|
$
|
4,452
|
|
|
$
|
—
|
|
|
2018-2037
|
Foreign tax credits
|
$
|
2,685
|
|
|
$
|
—
|
|
|
2023-2028
|
Texas margins tax credit
|
$
|
30
|
|
|
$
|
—
|
|
|
2026
|
millions
|
|
|
|
|
||||
Balance Sheet Classification
|
|
2017
|
|
2016
|
||||
Income taxes receivable
|
|
|
|
|
||||
Accounts receivable—other
|
|
$
|
53
|
|
|
$
|
180
|
|
Other assets
|
|
101
|
|
|
67
|
|
||
|
|
154
|
|
|
247
|
|
||
Income taxes (payable)
|
|
|
|
|
||||
Other current liabilities
|
|
(71
|
)
|
|
(6
|
)
|
||
Total net income taxes receivable (payable)
|
|
$
|
83
|
|
|
$
|
241
|
|
|
Assets (Liabilities)
|
||||||||||
millions
|
2017
|
|
2016
|
|
2015
|
||||||
Balance at January 1
|
$
|
(1,456
|
)
|
|
$
|
(1,780
|
)
|
|
$
|
(1,687
|
)
|
Increases related to prior-year tax positions
|
(15
|
)
|
|
(86
|
)
|
|
(99
|
)
|
|||
Decreases related to prior-year tax positions
|
214
|
|
|
436
|
|
|
89
|
|
|||
Increases related to current-year tax positions
|
(72
|
)
|
|
(26
|
)
|
|
(263
|
)
|
|||
Settlements
|
12
|
|
|
—
|
|
|
180
|
|
|||
Balance at December 31
|
$
|
(1,317
|
)
|
|
$
|
(1,456
|
)
|
|
$
|
(1,780
|
)
|
|
Tax Years
|
United States
|
2012-2017
|
Algeria
|
2014-2017
|
Ghana
|
2014-2017
|
millions
|
2017
|
|
2016
|
||||
Carrying amount at January 1
|
$
|
2,931
|
|
|
$
|
2,059
|
|
Liabilities acquired
(1)
|
4
|
|
|
813
|
|
||
Liabilities incurred
|
191
|
|
|
93
|
|
||
Property dispositions
|
(154
|
)
|
|
(88
|
)
|
||
Liabilities settled
|
(135
|
)
|
|
(225
|
)
|
||
Accretion expense
|
144
|
|
|
100
|
|
||
Revisions in estimated liabilities
|
(187
|
)
|
|
179
|
|
||
Carrying amount at December 31
|
$
|
2,794
|
|
|
$
|
2,931
|
|
(1)
|
In December 2016, the Company closed the GOM Acquisition. See
Note 3—Acquisitions, Divestitures, and Assets Held for Sale
for additional information.
|
millions
|
|
||
2018
|
$
|
50
|
|
2019
|
52
|
|
|
2020
|
56
|
|
|
2021
|
57
|
|
|
2022
|
58
|
|
|
Later years
|
204
|
|
|
Total
|
$
|
477
|
|
millions
|
|
||
2018
|
$
|
465
|
|
2019
|
259
|
|
|
2020
|
94
|
|
|
2021
|
38
|
|
|
2022
|
26
|
|
|
Later years
|
52
|
|
|
Total future minimum lease payments
|
$
|
934
|
|
millions
|
|
||
2018
|
$
|
1,267
|
|
2019
|
1,069
|
|
|
2020
|
968
|
|
|
2021
|
756
|
|
|
2022
|
605
|
|
|
Later years
|
1,437
|
|
|
Total
(1)
|
$
|
6,102
|
|
(1)
|
Excludes purchase commitments for jointly owned fields and facilities for which the Company is not the operator.
|
|
Pension Benefits
|
|
Other Benefits
|
||||||||||||
millions
|
2017
|
|
2016
|
|
2017
|
|
2016
|
||||||||
Change in benefit obligation
|
|
|
|
|
|
|
|
||||||||
Benefit obligation at beginning of year
|
$
|
2,301
|
|
|
$
|
2,431
|
|
|
$
|
296
|
|
|
$
|
266
|
|
Service cost
|
87
|
|
|
99
|
|
|
2
|
|
|
3
|
|
||||
Interest cost
|
84
|
|
|
95
|
|
|
12
|
|
|
12
|
|
||||
Actuarial (gain) loss
(1)
|
130
|
|
|
211
|
|
|
14
|
|
|
34
|
|
||||
Participant contributions
|
—
|
|
|
—
|
|
|
5
|
|
|
4
|
|
||||
Benefit payments
|
(396
|
)
|
|
(513
|
)
|
|
(27
|
)
|
|
(23
|
)
|
||||
Foreign-currency exchange-rate changes
|
12
|
|
|
(22
|
)
|
|
—
|
|
|
—
|
|
||||
Benefit obligation at end of year
(2)
|
$
|
2,218
|
|
|
$
|
2,301
|
|
|
$
|
302
|
|
|
$
|
296
|
|
Change in plan assets
|
|
|
|
|
|
|
|
||||||||
Fair value of plan assets at beginning of year
|
$
|
1,340
|
|
|
$
|
1,674
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Actual return on plan assets
|
209
|
|
|
107
|
|
|
—
|
|
|
—
|
|
||||
Employer contributions
|
254
|
|
|
101
|
|
|
22
|
|
|
19
|
|
||||
Participant contributions
|
—
|
|
|
—
|
|
|
5
|
|
|
4
|
|
||||
Benefit payments
|
(396
|
)
|
|
(513
|
)
|
|
(27
|
)
|
|
(23
|
)
|
||||
Foreign-currency exchange-rate changes
|
17
|
|
|
(29
|
)
|
|
—
|
|
|
—
|
|
||||
Fair value of plan assets at end of year
|
$
|
1,424
|
|
|
$
|
1,340
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
||||||||
Funded status of the plans at end of year
|
$
|
(794
|
)
|
|
$
|
(961
|
)
|
|
$
|
(302
|
)
|
|
$
|
(296
|
)
|
|
|
|
|
|
|
|
|
||||||||
Amounts recognized on the balance sheet
|
|
|
|
|
|
|
|
||||||||
Other assets
|
$
|
58
|
|
|
$
|
44
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Other current liabilities
|
(16
|
)
|
|
(66
|
)
|
|
(21
|
)
|
|
(23
|
)
|
||||
Other long-term liabilities—other
|
(836
|
)
|
|
(939
|
)
|
|
(281
|
)
|
|
(273
|
)
|
||||
Total
|
$
|
(794
|
)
|
|
$
|
(961
|
)
|
|
$
|
(302
|
)
|
|
$
|
(296
|
)
|
|
|
|
|
|
|
|
|
||||||||
Amounts recognized in accumulated other comprehensive income
|
|
|
|
|
|
|
|
||||||||
Prior service (credit) cost
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(26
|
)
|
|
$
|
(50
|
)
|
Net actuarial (gain) loss
|
501
|
|
|
616
|
|
|
14
|
|
|
—
|
|
||||
Total
|
$
|
501
|
|
|
$
|
616
|
|
|
$
|
(12
|
)
|
|
$
|
(50
|
)
|
(1)
|
Includes
$19 million
of settlement losses for pension benefits at
December 31, 2017
, and
$44 million
of termination benefits at
December 31, 2016
, associated with the Company’s workforce reduction program initiated in the first quarter of 2016. See
Note 18—Restructuring Charges
.
|
(2)
|
The accumulated benefit obligation for all defined-benefit pension plans was
$1.9 billion
at
December 31, 2017
and
$2.0 billion
at
December 31, 2016
.
|
millions
|
2017
|
|
2016
|
||||
Projected benefit obligation
|
$
|
2,079
|
|
|
$
|
2,175
|
|
Accumulated benefit obligation
|
1,749
|
|
|
1,866
|
|
||
Fair value of plan assets
|
1,227
|
|
|
1,171
|
|
|
Pension Benefits
|
|
Other Benefits
|
||||||||||||||||||||
millions
|
2017
|
|
2016
|
|
2015
|
|
2017
|
|
2016
|
|
2015
|
||||||||||||
Components of net periodic benefit cost
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Service cost
|
$
|
87
|
|
|
$
|
99
|
|
|
$
|
118
|
|
|
$
|
2
|
|
|
$
|
3
|
|
|
$
|
9
|
|
Interest cost
|
84
|
|
|
95
|
|
|
101
|
|
|
12
|
|
|
12
|
|
|
15
|
|
||||||
Expected (return) loss on plan assets
|
(84
|
)
|
|
(97
|
)
|
|
(109
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Amortization of net actuarial (gain) loss
|
25
|
|
|
42
|
|
|
52
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Amortization of net prior service (credit) cost
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
(24
|
)
|
|
(25
|
)
|
|
(4
|
)
|
||||||
Settlement expense
(1)
|
91
|
|
|
146
|
|
|
11
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Termination benefits expense
(1)
|
4
|
|
|
44
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Curtailment expense
(1)
|
—
|
|
|
8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Net periodic benefit cost
|
$
|
206
|
|
|
$
|
337
|
|
|
$
|
173
|
|
|
$
|
(10
|
)
|
|
$
|
(10
|
)
|
|
$
|
20
|
|
(1)
|
Settlement expense, termination benefits expense, and curtailment expense for 2016 relate to the workforce reduction program initiated in the first quarter of 2016. See
Note 18—Restructuring Charges
.
|
|
Pension Benefits
|
|
Other Benefits
|
||||||||||||||||||||
millions
|
2017
|
|
2016
|
|
2015
|
|
2017
|
|
2016
|
|
2015
|
||||||||||||
Amounts recognized in other comprehensive income (expense)
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net actuarial gain (loss)
|
$
|
—
|
|
|
$
|
(150
|
)
|
|
$
|
22
|
|
|
$
|
(14
|
)
|
|
$
|
(25
|
)
|
|
$
|
27
|
|
Amortization of net actuarial (gain) loss
|
116
|
|
|
188
|
|
|
63
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Net prior service credit (cost)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
89
|
|
||||||
Amortization of net prior service (credit) cost
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
(24
|
)
|
|
(34
|
)
|
|
(4
|
)
|
||||||
Total amounts recognized in other comprehensive income (expense)
|
$
|
115
|
|
|
$
|
38
|
|
|
$
|
85
|
|
|
$
|
(38
|
)
|
|
$
|
(59
|
)
|
|
$
|
112
|
|
|
Pension Benefits
|
|
Other Benefits
|
||||||||||||||
|
2017
|
|
2016
|
|
2015
|
|
2017
|
|
2016
|
|
2015
|
||||||
Benefit obligation assumptions
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Discount rate
|
3.62
|
%
|
|
4.06
|
%
|
|
4.50
|
%
|
|
3.75
|
%
|
|
4.26
|
%
|
|
5.00
|
%
|
Rates of increase in compensation levels
|
5.36
|
%
|
|
5.40
|
%
|
|
5.25
|
%
|
|
5.46
|
%
|
|
5.48
|
%
|
|
5.50
|
%
|
Net periodic benefit cost assumptions
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Discount rate
|
4.06
|
%
|
|
4.62
|
%
|
|
4.00
|
%
|
|
4.26
|
%
|
|
5.00
|
%
|
|
4.25
|
%
|
Long-term rate of return on plan assets
|
6.12
|
%
|
|
6.77
|
%
|
|
6.75
|
%
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
Rates of increase in compensation levels
|
5.40
|
%
|
|
5.34
|
%
|
|
5.25
|
%
|
|
5.48
|
%
|
|
5.41
|
%
|
|
5.25
|
%
|
millions
|
|
|
|
|
|
|
|
||||||||
December 31, 2017
|
Level 1
|
|
Level 2
|
|
Level 3
(3)
|
|
Total
|
||||||||
Investments
|
|
|
|
|
|
|
|
||||||||
Cash and cash equivalents
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1
|
|
Fixed income
|
55
|
|
|
31
|
|
|
—
|
|
|
86
|
|
||||
Equity securities
|
185
|
|
|
—
|
|
|
—
|
|
|
185
|
|
||||
Other
|
|
|
|
|
|
|
|
||||||||
Real estate
|
—
|
|
|
—
|
|
|
13
|
|
|
13
|
|
||||
Other
|
—
|
|
|
53
|
|
|
—
|
|
|
53
|
|
||||
Investments measured at net asset value
(1)
|
—
|
|
|
—
|
|
|
—
|
|
|
1,086
|
|
||||
Total investments
(2)
|
$
|
241
|
|
|
$
|
84
|
|
|
$
|
13
|
|
|
$
|
1,424
|
|
|
|
|
|
|
|
|
|
||||||||
December 31, 2016
|
|
|
|
|
|
|
|
||||||||
Investments
|
|
|
|
|
|
|
|
||||||||
Cash and cash equivalents
|
$
|
2
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2
|
|
Fixed income
|
59
|
|
|
33
|
|
|
—
|
|
|
92
|
|
||||
Equity securities
|
347
|
|
|
—
|
|
|
—
|
|
|
347
|
|
||||
Other
|
|
|
|
|
|
|
|
||||||||
Real estate
|
—
|
|
|
—
|
|
|
10
|
|
|
10
|
|
||||
Other
|
—
|
|
|
28
|
|
|
—
|
|
|
28
|
|
||||
Investments measured at net asset value
(1)
|
—
|
|
|
—
|
|
|
—
|
|
|
861
|
|
||||
Total investments
(2)
|
$
|
408
|
|
|
$
|
61
|
|
|
$
|
10
|
|
|
$
|
1,340
|
|
(1)
|
Certain investments measured at fair value using the net asset value per share (or its equivalent) have not been categorized in the fair value hierarchy. Amounts presented in this table are intended to reconcile the fair value hierarchy to the pension plan assets.
|
(2)
|
Amount excludes receivables and payables, primarily related to Level 1 investments.
|
(3)
|
The changes in level 3 investments of
$3 million
for the year ended
December 31, 2017
, and
$(3) million
for the year ended
December 31, 2016
, were attributable to the actual return on plan assets still held at the reporting date.
|
millions
|
Expected 2018
|
|
2017
|
||||
Funded pension plans
|
$
|
114
|
|
|
$
|
167
|
|
Unfunded pension plans
|
16
|
|
|
87
|
|
||
Unfunded other postretirement plans
|
22
|
|
|
22
|
|
||
Total
|
$
|
152
|
|
|
$
|
276
|
|
millions
|
Pension Benefit
Payments
|
|
Other Benefit
Payments
|
||||
2018
|
$
|
138
|
|
|
$
|
22
|
|
2019
|
155
|
|
|
21
|
|
||
2020
|
154
|
|
|
21
|
|
||
2021
|
166
|
|
|
20
|
|
||
2022
|
195
|
|
|
20
|
|
||
2023-2027
|
938
|
|
|
90
|
|
millions
|
2017
|
|
2016
|
|
2015
|
|||
Shares of common stock issued
|
|
|
|
|
|
|||
Shares at January 1
|
572
|
|
|
528
|
|
|
526
|
|
Exercise of stock options
|
—
|
|
|
1
|
|
|
1
|
|
Issuance of common stock
|
—
|
|
|
41
|
|
|
—
|
|
Issuance of restricted stock
|
2
|
|
|
2
|
|
|
1
|
|
Shares at December 31
|
574
|
|
|
572
|
|
|
528
|
|
Shares of common stock held in treasury
|
|
|
|
|
|
|||
Shares at January 1
|
21
|
|
|
20
|
|
|
19
|
|
Purchase of treasury stock
|
22
|
|
|
—
|
|
|
—
|
|
Shares received for restricted stock vested and stock options exercised
|
—
|
|
|
1
|
|
|
1
|
|
Shares at December 31
|
43
|
|
|
21
|
|
|
20
|
|
Shares of common stock outstanding at December 31
|
531
|
|
|
551
|
|
|
508
|
|
millions except per-share amounts
|
2017
|
|
2016
|
|
2015
|
||||||
Net income (loss)
|
|
|
|
|
|
||||||
Net income (loss) attributable to common stockholders
|
$
|
(456
|
)
|
|
$
|
(3,071
|
)
|
|
$
|
(6,692
|
)
|
Income (loss) effect of TEUs
|
(7
|
)
|
|
(6
|
)
|
|
—
|
|
|||
Less distributions on participating securities
|
1
|
|
|
1
|
|
|
3
|
|
|||
Basic
|
$
|
(464
|
)
|
|
$
|
(3,078
|
)
|
|
$
|
(6,695
|
)
|
Income (loss) effect of TEUs
|
(2
|
)
|
|
(1
|
)
|
|
—
|
|
|||
Diluted
|
$
|
(466
|
)
|
|
$
|
(3,079
|
)
|
|
$
|
(6,695
|
)
|
Shares
|
|
|
|
|
|
||||||
Average number of common shares outstanding—basic
|
548
|
|
|
522
|
|
|
508
|
|
|||
Average number of common shares outstanding—diluted
|
548
|
|
|
522
|
|
|
508
|
|
|||
Excluded due to anti-dilutive effect
|
11
|
|
|
11
|
|
|
11
|
|
|||
Net income (loss) per common share
|
|
|
|
|
|
||||||
Basic
|
$
|
(0.85
|
)
|
|
$
|
(5.90
|
)
|
|
$
|
(13.18
|
)
|
Diluted
|
$
|
(0.85
|
)
|
|
$
|
(5.90
|
)
|
|
$
|
(13.18
|
)
|
millions
|
Interest-rate
Derivatives
Previously
Subject to Hedge
Accounting
|
|
Pension and Other Postretirement
Plans
|
|
Total
|
||||||
Balance at December 31, 2014
|
$
|
(48
|
)
|
|
$
|
(469
|
)
|
|
$
|
(517
|
)
|
Other comprehensive income (loss), before reclassifications
|
—
|
|
|
87
|
|
|
87
|
|
|||
Reclassifications to Consolidated Statement of Income
|
6
|
|
|
41
|
|
|
47
|
|
|||
Net other comprehensive income (loss)
|
6
|
|
|
128
|
|
|
134
|
|
|||
Balance at December 31, 2015
|
$
|
(42
|
)
|
|
$
|
(341
|
)
|
|
$
|
(383
|
)
|
Other comprehensive income (loss), before reclassifications
|
—
|
|
|
(107
|
)
|
|
(107
|
)
|
|||
Reclassifications to Consolidated Statement of Income
|
5
|
|
|
94
|
|
|
99
|
|
|||
Net other comprehensive income (loss)
|
5
|
|
|
(13
|
)
|
|
(8
|
)
|
|||
Balance at December 31, 2016
|
$
|
(37
|
)
|
|
$
|
(354
|
)
|
|
$
|
(391
|
)
|
Other comprehensive income (loss), before reclassifications
|
—
|
|
|
(10
|
)
|
|
(10
|
)
|
|||
Reclassifications to Consolidated Statement of Income
|
2
|
|
|
61
|
|
|
63
|
|
|||
Net other comprehensive income (loss)
|
2
|
|
|
51
|
|
|
53
|
|
|||
Balance at December 31, 2017
|
$
|
(35
|
)
|
|
$
|
(303
|
)
|
|
$
|
(338
|
)
|
millions
|
2017
|
|
2016
|
|
2015
|
||||||
Restricted stock
(1)
|
$
|
145
|
|
|
$
|
175
|
|
|
$
|
157
|
|
Stock options
(1)
|
17
|
|
|
20
|
|
|
19
|
|
|||
Other equity-classified awards
|
1
|
|
|
2
|
|
|
1
|
|
|||
Value creation plan
|
—
|
|
|
—
|
|
|
(4
|
)
|
|||
Performance-based unit awards
(1)
|
(13
|
)
|
|
38
|
|
|
(1
|
)
|
|||
Pretax share-based compensation expense
|
$
|
150
|
|
|
$
|
235
|
|
|
$
|
172
|
|
Income tax benefit
|
$
|
35
|
|
|
$
|
86
|
|
|
$
|
64
|
|
(1)
|
Includes restructuring charges of
$(7) million
for performance-based unit awards in 2017 and
$31 million
for restricted stock,
$1 million
for stock options, and
$7 million
for performance-based unit awards in 2016. See
Note 18—Restructuring Charges
for further discussion.
|
|
Shares
(millions)
|
|
Weighted-Average
Grant-Date
Fair Value
(per share)
|
|||
Non-vested at January 1, 2017
|
4.54
|
|
|
$
|
62.74
|
|
Granted
|
2.60
|
|
|
$
|
59.92
|
|
Vested
|
(2.21
|
)
|
|
$
|
67.02
|
|
Forfeited
|
(0.24
|
)
|
|
$
|
60.95
|
|
Non-vested at December 31, 2017
|
4.69
|
|
|
$
|
59.24
|
|
•
|
Expected life
—Based on historical exercise behavior.
|
•
|
Volatility
—Based on an average of historical volatility over the expected life of an option and the 12-month average implied volatility.
|
•
|
Risk-free interest rates
—Based on the U.S. Treasury rate over the expected life of an option.
|
•
|
Dividend yield
—Based on a 12-month average dividend yield, taking into account the Company’s expected dividend policy over the expected life of an option.
|
|
2017
|
|
2016
|
|
2015
|
|||||||||
Weighted-average grant-date fair value
|
$
|
14.77
|
|
|
$
|
15.92
|
|
|
$
|
18.18
|
|
|||
Assumptions
|
|
|
|
|
|
|
|
|
||||||
Expected option life—years
|
4.8
|
|
|
4.1
|
|
|
4.9
|
|
||||||
Volatility
|
33.6
|
%
|
|
38.2
|
%
|
|
32.4
|
%
|
||||||
Risk-free interest rate
|
2.0
|
%
|
|
1.3
|
%
|
|
1.4
|
%
|
||||||
Dividend yield
|
0.4
|
%
|
|
0.6
|
%
|
|
1.4
|
%
|
|
Shares
(millions)
|
|
Weighted-
Average
Exercise
Price
(per share)
|
|
Weighted-
Average
Remaining
Contractual
Term
(years)
|
|
Aggregate
Intrinsic
Value
(millions)
|
|||||
Outstanding at January 1, 2017
|
6.62
|
|
|
$
|
76.10
|
|
|
|
|
|
||
Granted
|
1.48
|
|
|
$
|
49.82
|
|
|
|
|
|
||
Exercised
(1)
|
—
|
|
|
$
|
47.20
|
|
|
|
|
|
||
Forfeited or expired
|
(1.53
|
)
|
|
$
|
70.71
|
|
|
|
|
|
||
Outstanding at December 31, 2017
|
6.57
|
|
|
$
|
71.44
|
|
|
3.64
|
|
$
|
7.4
|
|
Vested or expected to vest at December 31, 2017
|
6.57
|
|
|
$
|
71.44
|
|
|
3.64
|
|
$
|
7.4
|
|
Exercisable at December 31, 2017
|
4.41
|
|
|
$
|
79.86
|
|
|
2.29
|
|
$
|
0.1
|
|
(1)
|
The total intrinsic value of stock options exercised was
zero
during
2017
,
$7 million
during
2016
, and
$23 million
during
2015
, based on the difference between the market price at the exercise date and the exercise price.
|
millions
|
2017
|
|
2016
|
|
2015
|
||||||
Statement of Operations Data
|
|
|
|
|
|
||||||
Total revenues and other
|
$
|
2,248
|
|
|
$
|
1,804
|
|
|
$
|
1,752
|
|
Operating income (loss)
|
704
|
|
|
705
|
|
|
154
|
|
|||
Net income (loss)
|
573
|
|
|
597
|
|
|
11
|
|
|||
Statement of Cash Flows Data
|
|
|
|
|
|
||||||
Net cash provided by (used in) operating activities
|
$
|
897
|
|
|
$
|
913
|
|
|
$
|
783
|
|
Net cash provided by (used in) investing activities
|
(764
|
)
|
|
(1,106
|
)
|
|
(500
|
)
|
|||
Net cash provided by (used in) financing activities
|
(413
|
)
|
|
452
|
|
|
(250
|
)
|
millions
|
2017
|
|
2016
|
||||
Balance Sheet Data
|
|
|
|
||||
Net property, plant, and equipment
|
$
|
5,731
|
|
|
$
|
5,050
|
|
Total assets
|
8,016
|
|
|
7,736
|
|
||
Long-term debt
|
3,493
|
|
|
3,119
|
|
||
Total liabilities
|
4,071
|
|
|
3,625
|
|
||
Total equity and partners’ capital
|
3,945
|
|
|
4,111
|
|
millions
|
2017
|
|
2016
|
|
2015
|
||||||
Cash paid (received)
|
|
|
|
|
|
||||||
Interest, net of amounts capitalized
(1)
|
$
|
906
|
|
|
$
|
856
|
|
|
$
|
2,019
|
|
Income taxes, net of refunds
(2)
|
64
|
|
|
(882
|
)
|
|
26
|
|
|||
Non-cash investing activities
|
|
|
|
|
|
||||||
Fair value of properties and equipment acquired
|
$
|
640
|
|
|
$
|
3
|
|
|
$
|
178
|
|
Asset retirement cost additions
|
66
|
|
|
298
|
|
|
273
|
|
|||
Accruals of property, plant, and equipment
|
824
|
|
|
549
|
|
|
754
|
|
|||
Net liabilities assumed (divested) in acquisitions and divestitures
|
(158
|
)
|
|
723
|
|
|
(114
|
)
|
|||
Property insurance receivable
|
—
|
|
|
—
|
|
|
49
|
|
|||
Acquisition receivable
|
—
|
|
|
(32
|
)
|
|
—
|
|
|||
Non-cash investing and financing activities
|
|
|
|
|
|
||||||
Acquisition contingent consideration
|
$
|
—
|
|
|
$
|
103
|
|
|
$
|
—
|
|
Capital lease obligation
(3)
|
(2
|
)
|
|
10
|
|
|
—
|
|
|||
FPSO construction period obligation
(3)
|
—
|
|
|
11
|
|
|
59
|
|
|||
Deferred drilling lease liability
|
14
|
|
|
30
|
|
|
—
|
|
(1)
|
Includes
$1.2 billion
of interest related to the Tronox settlement payment in 2015.
|
(2)
|
Includes
$881 million
from a tax refund in 2016 related to the income tax benefit associated with the Company’s 2015 tax net operating loss carryback.
|
(3)
|
Upon completion of the FPSO in the third quarter of 2016, the Company reported the construction period obligation as a capital lease obligation based on the fair value of the FPSO. See
Note 12—Debt and Interest Expense
.
|
millions
|
2017
|
|
2016
|
|
2015
|
||||||
Income (loss) before income taxes
|
$
|
(1,688
|
)
|
|
$
|
(3,829
|
)
|
|
$
|
(9,689
|
)
|
(Gains) losses on divestitures, net
|
(674
|
)
|
|
757
|
|
|
1,022
|
|
|||
Exploration expense
|
2,541
|
|
|
946
|
|
|
2,644
|
|
|||
DD&A
|
4,279
|
|
|
4,301
|
|
|
4,603
|
|
|||
Impairments
|
408
|
|
|
227
|
|
|
5,075
|
|
|||
Interest expense
|
932
|
|
|
890
|
|
|
825
|
|
|||
Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives
|
156
|
|
|
559
|
|
|
235
|
|
|||
Restructuring charges
|
21
|
|
|
389
|
|
|
—
|
|
|||
Other operating expense
|
—
|
|
|
1
|
|
|
74
|
|
|||
Loss on early extinguishment of debt
|
2
|
|
|
155
|
|
|
—
|
|
|||
Certain other nonoperating items
|
—
|
|
|
(58
|
)
|
|
27
|
|
|||
Less net income (loss) attributable to noncontrolling interests
|
245
|
|
|
263
|
|
|
(120
|
)
|
|||
Consolidated Adjusted EBITDAX
|
$
|
5,732
|
|
|
$
|
4,075
|
|
|
$
|
4,936
|
|
millions
|
Exploration
& Production
|
|
WES Midstream
|
|
Other Midstream
|
|
Other and
Intersegment
Eliminations
|
|
Total
|
||||||||||
2017
|
|
|
|
|
|
|
|
|
|
||||||||||
Sales revenues
|
$
|
8,946
|
|
|
$
|
1,715
|
|
|
$
|
187
|
|
|
$
|
121
|
|
|
$
|
10,969
|
|
Intersegment revenues
|
23
|
|
|
523
|
|
|
172
|
|
|
(718
|
)
|
|
—
|
|
|||||
Other
(1)
|
15
|
|
|
153
|
|
|
30
|
|
|
67
|
|
|
265
|
|
|||||
Total revenues and other
(2)
|
8,984
|
|
|
2,391
|
|
|
389
|
|
|
(530
|
)
|
|
11,234
|
|
|||||
Operating costs and expenses
(3)
|
3,555
|
|
|
1,330
|
|
|
234
|
|
|
212
|
|
|
5,331
|
|
|||||
Net cash from settlement of commodity derivatives
|
—
|
|
|
—
|
|
|
—
|
|
|
(27
|
)
|
|
(27
|
)
|
|||||
Other (income) expense, net
|
—
|
|
|
—
|
|
|
—
|
|
|
(53
|
)
|
|
(53
|
)
|
|||||
Net income (loss) attributable to noncontrolling interests
(1)
|
—
|
|
|
—
|
|
|
—
|
|
|
245
|
|
|
245
|
|
|||||
Total expenses and other
|
3,555
|
|
|
1,330
|
|
|
234
|
|
|
377
|
|
|
5,496
|
|
|||||
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement
|
—
|
|
|
—
|
|
|
—
|
|
|
(6
|
)
|
|
(6
|
)
|
|||||
Adjusted EBITDAX
|
$
|
5,429
|
|
|
$
|
1,061
|
|
|
$
|
155
|
|
|
$
|
(913
|
)
|
|
$
|
5,732
|
|
Net properties and equipment
|
$
|
18,598
|
|
|
$
|
5,731
|
|
|
$
|
1,140
|
|
|
$
|
1,982
|
|
|
$
|
27,451
|
|
Capital expenditures
|
$
|
3,779
|
|
|
$
|
956
|
|
|
$
|
458
|
|
|
$
|
107
|
|
|
$
|
5,300
|
|
Goodwill
|
$
|
4,343
|
|
|
$
|
416
|
|
|
$
|
30
|
|
|
$
|
—
|
|
|
$
|
4,789
|
|
(1)
|
Presentation has been adjusted to align with the current analysis of segment performance. Net income (loss) attributable to noncontrolling interests, previously reported within the Midstream segment, is now presented within Other and Intersegment Eliminations. Other revenues, previously reported within Other and Intersegment Eliminations, is now presented within the applicable segments.
|
(2)
|
Total revenues and other excludes gains (losses) on divestitures, net since these gains and losses are excluded from Adjusted EBITDAX.
|
(3)
|
Operating costs and expenses excludes exploration expense, DD&A, impairments, restructuring charges, and certain other operating expenses since these expenses are excluded from Adjusted EBITDAX.
|
millions
|
Exploration
& Production
|
|
WES Midstream
|
|
Other Midstream
|
|
Other and
Intersegment
Eliminations
|
|
Total
|
||||||||||
2016
|
|
|
|
|
|
|
|
|
|
||||||||||
Sales revenues
|
$
|
7,146
|
|
|
$
|
1,055
|
|
|
$
|
146
|
|
|
$
|
100
|
|
|
$
|
8,447
|
|
Intersegment revenues
|
7
|
|
|
712
|
|
|
185
|
|
|
(904
|
)
|
|
—
|
|
|||||
Other
(1)
|
(5
|
)
|
|
114
|
|
|
19
|
|
|
51
|
|
|
179
|
|
|||||
Total revenues and other
(2)
|
7,148
|
|
|
1,881
|
|
|
350
|
|
|
(753
|
)
|
|
8,626
|
|
|||||
Operating costs and expenses
(3)
|
3,518
|
|
|
853
|
|
|
228
|
|
|
5
|
|
|
4,604
|
|
|||||
Net cash from settlement of commodity derivatives
|
—
|
|
|
—
|
|
|
—
|
|
|
(265
|
)
|
|
(265
|
)
|
|||||
Other (income) expense, net
(4)
|
—
|
|
|
—
|
|
|
—
|
|
|
(43
|
)
|
|
(43
|
)
|
|||||
Net income (loss) attributable to noncontrolling interests
(1)
|
—
|
|
|
—
|
|
|
—
|
|
|
263
|
|
|
263
|
|
|||||
Total expenses and other
|
3,518
|
|
|
853
|
|
|
228
|
|
|
(40
|
)
|
|
4,559
|
|
|||||
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement
|
—
|
|
|
—
|
|
|
—
|
|
|
8
|
|
|
8
|
|
|||||
Adjusted EBITDAX
|
$
|
3,630
|
|
|
$
|
1,028
|
|
|
$
|
122
|
|
|
$
|
(705
|
)
|
|
$
|
4,075
|
|
Net properties and equipment
|
$
|
24,251
|
|
|
$
|
5,050
|
|
|
$
|
885
|
|
|
$
|
1,982
|
|
|
$
|
32,168
|
|
Capital expenditures
|
$
|
2,685
|
|
|
$
|
491
|
|
|
$
|
59
|
|
|
$
|
79
|
|
|
$
|
3,314
|
|
Goodwill
|
$
|
4,550
|
|
|
$
|
418
|
|
|
$
|
32
|
|
|
$
|
—
|
|
|
$
|
5,000
|
|
2015
|
|
|
|
|
|
|
|
|
|
||||||||||
Sales revenues
|
$
|
8,250
|
|
|
$
|
958
|
|
|
$
|
195
|
|
|
$
|
83
|
|
|
$
|
9,486
|
|
Intersegment revenues
|
10
|
|
|
659
|
|
|
172
|
|
|
(841
|
)
|
|
—
|
|
|||||
Other
(1)
|
40
|
|
|
109
|
|
|
16
|
|
|
69
|
|
|
234
|
|
|||||
Total revenues and other
(2)
|
8,300
|
|
|
1,726
|
|
|
383
|
|
|
(689
|
)
|
|
9,720
|
|
|||||
Operating costs and expenses
(3)
|
3,778
|
|
|
818
|
|
|
282
|
|
|
233
|
|
|
5,111
|
|
|||||
Net cash from settlement of commodity derivatives
|
—
|
|
|
—
|
|
|
—
|
|
|
(335
|
)
|
|
(335
|
)
|
|||||
Other (income) expense, net
(4)
|
—
|
|
|
—
|
|
|
—
|
|
|
127
|
|
|
127
|
|
|||||
Net income (loss) attributable to noncontrolling interests
(1)
|
—
|
|
|
—
|
|
|
—
|
|
|
(120
|
)
|
|
(120
|
)
|
|||||
Total expenses and other
|
3,778
|
|
|
818
|
|
|
282
|
|
|
(95
|
)
|
|
4,783
|
|
|||||
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement
|
—
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
(1
|
)
|
|||||
Adjusted EBITDAX
|
$
|
4,522
|
|
|
$
|
908
|
|
|
$
|
101
|
|
|
$
|
(595
|
)
|
|
$
|
4,936
|
|
Net properties and equipment
|
$
|
25,742
|
|
|
$
|
4,859
|
|
|
$
|
1,038
|
|
|
$
|
2,112
|
|
|
$
|
33,751
|
|
Capital expenditures
|
$
|
5,029
|
|
|
$
|
525
|
|
|
$
|
245
|
|
|
$
|
89
|
|
|
$
|
5,888
|
|
Goodwill
|
$
|
4,945
|
|
|
$
|
388
|
|
|
$
|
62
|
|
|
$
|
—
|
|
|
$
|
5,395
|
|
(1)
|
Presentation has been adjusted to align with the current analysis of segment performance. Net income (loss) attributable to noncontrolling interests, previously reported within the Midstream segment, is now presented within Other and Intersegment Eliminations. Other revenues, previously reported within Other and Intersegment Eliminations, is now presented within the applicable segments.
|
(2)
|
Total revenues and other excludes gains (losses) on divestitures, net since these gains and losses are excluded from Adjusted EBITDAX.
|
(3)
|
Operating costs and expenses excludes exploration expense, DD&A, impairments, restructuring charges, and certain other operating expenses since these expenses are excluded from Adjusted EBITDAX.
|
(4)
|
Other (income) expense, net excludes certain other nonoperating items since these items are excluded from Adjusted EBITDAX.
|
|
Years Ended December 31,
|
||||||||||
millions
|
2017
|
|
2016
|
|
2015
|
||||||
Sales Revenues
|
|
|
|
|
|
||||||
United States
|
$
|
9,176
|
|
|
$
|
7,049
|
|
|
$
|
7,819
|
|
Algeria
|
1,249
|
|
|
1,103
|
|
|
1,189
|
|
|||
Other International
|
544
|
|
|
295
|
|
|
478
|
|
|||
Total sales revenues
|
$
|
10,969
|
|
|
$
|
8,447
|
|
|
$
|
9,486
|
|
|
December 31,
|
||||||
millions
|
2017
|
|
2016
|
||||
Net Properties and Equipment
|
|
|
|
||||
United States
|
$
|
24,382
|
|
|
$
|
28,024
|
|
Algeria
|
965
|
|
|
1,117
|
|
||
Other International
(1)
|
2,104
|
|
|
3,027
|
|
||
Total net properties and equipment
|
$
|
27,451
|
|
|
$
|
32,168
|
|
(1)
|
Includes
$413 million
of capitalized costs related to the Mozambique LNG project at
December 31, 2017
.
|
millions except per-share amounts
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
||||||||
2017
|
|
|
|
|
|
|
|
||||||||
Sales revenues
|
$
|
2,898
|
|
|
$
|
2,419
|
|
|
$
|
2,610
|
|
|
$
|
3,042
|
|
Gains (losses) on divestitures and other, net
|
869
|
|
|
297
|
|
|
(114
|
)
|
|
(113
|
)
|
||||
Impairments
|
373
|
|
|
10
|
|
|
—
|
|
|
25
|
|
||||
Operating income (loss)
|
(110
|
)
|
|
(125
|
)
|
|
(775
|
)
|
|
338
|
|
||||
Net income (loss)
(1)
|
(275
|
)
|
|
(334
|
)
|
|
(641
|
)
|
|
1,039
|
|
||||
Net income (loss) attributable to noncontrolling interests
|
43
|
|
|
81
|
|
|
58
|
|
|
63
|
|
||||
Net income (loss) attributable to common stockholders
|
(318
|
)
|
|
(415
|
)
|
|
(699
|
)
|
|
976
|
|
||||
Earnings per share
|
|
|
|
|
|
|
|
||||||||
Net income (loss) attributable to common stockholders—basic
|
$
|
(0.58
|
)
|
|
$
|
(0.76
|
)
|
|
$
|
(1.27
|
)
|
|
$
|
1.80
|
|
Net income (loss) attributable to common stockholders—diluted
|
$
|
(0.58
|
)
|
|
$
|
(0.76
|
)
|
|
$
|
(1.27
|
)
|
|
$
|
1.80
|
|
Average number common shares outstanding—basic
|
551
|
|
|
552
|
|
|
553
|
|
|
537
|
|
||||
Average number common shares outstanding—diluted
|
551
|
|
|
552
|
|
|
553
|
|
|
537
|
|
||||
|
|
|
|
|
|
|
|
||||||||
2016
|
|
|
|
|
|
|
|
||||||||
Sales revenues
|
$
|
1,634
|
|
|
$
|
1,985
|
|
|
$
|
2,251
|
|
|
$
|
2,577
|
|
Gains (losses) on divestitures and other, net
|
40
|
|
|
(70
|
)
|
|
(358
|
)
|
|
(190
|
)
|
||||
Impairments
|
16
|
|
|
18
|
|
|
27
|
|
|
166
|
|
||||
Operating income (loss)
|
(864
|
)
|
|
(332
|
)
|
|
(793
|
)
|
|
(610
|
)
|
||||
Net income (loss)
|
(998
|
)
|
|
(611
|
)
|
|
(747
|
)
|
|
(452
|
)
|
||||
Net income (loss) attributable to noncontrolling interests
|
36
|
|
|
81
|
|
|
83
|
|
|
63
|
|
||||
Net income (loss) attributable to common stockholders
|
(1,034
|
)
|
|
(692
|
)
|
|
(830
|
)
|
|
(515
|
)
|
||||
Earnings per share
|
|
|
|
|
|
|
|
||||||||
Net income (loss) attributable to common stockholders—basic
|
$
|
(2.03
|
)
|
|
$
|
(1.36
|
)
|
|
$
|
(1.61
|
)
|
|
$
|
(0.94
|
)
|
Net income (loss) attributable to common stockholders—diluted
|
$
|
(2.03
|
)
|
|
$
|
(1.36
|
)
|
|
$
|
(1.61
|
)
|
|
$
|
(0.94
|
)
|
Average number common shares outstanding—basic
|
509
|
|
|
510
|
|
|
517
|
|
|
551
|
|
||||
Average number common shares outstanding—diluted
|
509
|
|
|
510
|
|
|
517
|
|
|
551
|
|
(1)
|
Includes a one-time deferred tax benefit of $1.2 billion in the fourth quarter of 2017 related to the Tax Reform Legislation.
|
|
|
Oil
per Bbl
|
|
Natural Gas
per MMBtu
|
|
NGLs
per Bbl
|
||||||
December 31, 2017
|
|
$
|
51.34
|
|
|
$
|
2.98
|
|
|
$
|
31.83
|
|
December 31, 2016
|
|
$
|
42.75
|
|
|
$
|
2.48
|
|
|
$
|
19.74
|
|
December 31, 2015
|
|
$
|
50.28
|
|
|
$
|
2.59
|
|
|
$
|
19.47
|
|
|
Oil
(MMBbls)
|
|
Natural Gas
(Bcf)
|
||||||||||||||
|
United States
|
|
International
|
|
Total
|
|
United States
|
|
International
|
|
Total
|
||||||
Proved Reserves
|
|
|
|
|
|
|
|
|
|
|
|
||||||
December 31, 2014
|
704
|
|
|
225
|
|
|
929
|
|
|
8,668
|
|
|
31
|
|
|
8,699
|
|
Revisions of prior estimates
|
2
|
|
|
(6
|
)
|
|
(4
|
)
|
|
(888
|
)
|
|
4
|
|
|
(884
|
)
|
Extensions, discoveries, and other additions
|
15
|
|
|
—
|
|
|
15
|
|
|
60
|
|
|
—
|
|
|
60
|
|
Purchases in place
|
—
|
|
|
—
|
|
|
—
|
|
|
8
|
|
|
—
|
|
|
8
|
|
Sales in place
|
(111
|
)
|
|
—
|
|
|
(111
|
)
|
|
(1,003
|
)
|
|
—
|
|
|
(1,003
|
)
|
Production
|
(85
|
)
|
|
(31
|
)
|
|
(116
|
)
|
|
(854
|
)
|
|
(5
|
)
|
|
(859
|
)
|
December 31, 2015
|
525
|
|
|
188
|
|
|
713
|
|
|
5,991
|
|
|
30
|
|
|
6,021
|
|
Revisions of prior estimates
|
11
|
|
|
3
|
|
|
14
|
|
|
310
|
|
|
—
|
|
|
310
|
|
Extensions, discoveries, and other additions
|
24
|
|
|
—
|
|
|
24
|
|
|
59
|
|
|
—
|
|
|
59
|
|
Purchases in place
|
81
|
|
|
—
|
|
|
81
|
|
|
68
|
|
|
—
|
|
|
68
|
|
Sales in place
|
(14
|
)
|
|
—
|
|
|
(14
|
)
|
|
(1,263
|
)
|
|
—
|
|
|
(1,263
|
)
|
Production
|
(86
|
)
|
|
(30
|
)
|
|
(116
|
)
|
|
(766
|
)
|
|
(5
|
)
|
|
(771
|
)
|
December 31, 2016
|
541
|
|
|
161
|
|
|
702
|
|
|
4,399
|
|
|
25
|
|
|
4,424
|
|
Revisions of prior estimates
|
47
|
|
|
23
|
|
|
70
|
|
|
644
|
|
|
12
|
|
|
656
|
|
Extensions, discoveries, and other additions
|
72
|
|
|
5
|
|
|
77
|
|
|
119
|
|
|
6
|
|
|
125
|
|
Purchases in place
|
1
|
|
|
—
|
|
|
1
|
|
|
6
|
|
|
—
|
|
|
6
|
|
Sales in place
|
(63
|
)
|
|
—
|
|
|
(63
|
)
|
|
(1,514
|
)
|
|
—
|
|
|
(1,514
|
)
|
Production
|
(97
|
)
|
|
(32
|
)
|
|
(129
|
)
|
|
(461
|
)
|
|
(6
|
)
|
|
(467
|
)
|
December 31, 2017
|
501
|
|
|
157
|
|
|
658
|
|
|
3,193
|
|
|
37
|
|
|
3,230
|
|
Proved Developed Reserves
|
|
|
|
|
|
|
|
|
|
|
|
||||||
December 31, 2014
|
352
|
|
|
190
|
|
|
542
|
|
|
6,635
|
|
|
27
|
|
|
6,662
|
|
December 31, 2015
|
332
|
|
|
159
|
|
|
491
|
|
|
5,184
|
|
|
30
|
|
|
5,214
|
|
December 31, 2016
|
360
|
|
|
147
|
|
|
507
|
|
|
3,637
|
|
|
25
|
|
|
3,662
|
|
December 31, 2017
|
361
|
|
|
136
|
|
|
497
|
|
|
2,640
|
|
|
24
|
|
|
2,664
|
|
Proved Undeveloped Reserves
|
|
|
|
|
|
|
|
|
|
|
|
||||||
December 31, 2014
|
352
|
|
|
35
|
|
|
387
|
|
|
2,033
|
|
|
4
|
|
|
2,037
|
|
December 31, 2015
|
193
|
|
|
29
|
|
|
222
|
|
|
807
|
|
|
—
|
|
|
807
|
|
December 31, 2016
|
181
|
|
|
14
|
|
|
195
|
|
|
762
|
|
|
—
|
|
|
762
|
|
December 31, 2017
|
140
|
|
|
21
|
|
|
161
|
|
|
553
|
|
|
13
|
|
|
566
|
|
|
NGLs
(MMBbls)
|
|
Total
(MMBOE)
|
||||||||||||||
|
United States
|
|
International
|
|
Total
|
|
United States
|
|
International
|
|
Total
|
||||||
Proved Reserves
|
|
|
|
|
|
|
|
|
|
|
|
||||||
December 31, 2014
|
466
|
|
|
13
|
|
|
479
|
|
|
2,615
|
|
|
243
|
|
|
2,858
|
|
Revisions of prior estimates
(1)
|
(99
|
)
|
|
4
|
|
|
(95
|
)
|
|
(245
|
)
|
|
(1
|
)
|
|
(246
|
)
|
Extensions, discoveries, and other additions
|
4
|
|
|
—
|
|
|
4
|
|
|
29
|
|
|
—
|
|
|
29
|
|
Purchases in place
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
Sales in place
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
|
(279
|
)
|
|
—
|
|
|
(279
|
)
|
Production
|
(45
|
)
|
|
(2
|
)
|
|
(47
|
)
|
|
(272
|
)
|
|
(34
|
)
|
|
(306
|
)
|
December 31, 2015
|
325
|
|
|
15
|
|
|
340
|
|
|
1,849
|
|
|
208
|
|
|
2,057
|
|
Revisions of prior estimates
(1)
|
45
|
|
|
2
|
|
|
47
|
|
|
108
|
|
|
5
|
|
|
113
|
|
Extensions, discoveries, and other additions
|
6
|
|
|
—
|
|
|
6
|
|
|
40
|
|
|
—
|
|
|
40
|
|
Purchases in place
|
5
|
|
|
—
|
|
|
5
|
|
|
97
|
|
|
—
|
|
|
97
|
|
Sales in place
|
(69
|
)
|
|
—
|
|
|
(69
|
)
|
|
(294
|
)
|
|
—
|
|
|
(294
|
)
|
Production
|
(44
|
)
|
|
(2
|
)
|
|
(46
|
)
|
|
(258
|
)
|
|
(33
|
)
|
|
(291
|
)
|
December 31, 2016
|
268
|
|
|
15
|
|
|
283
|
|
|
1,542
|
|
|
180
|
|
|
1,722
|
|
Revisions of prior estimates
(1)
|
45
|
|
|
(2
|
)
|
|
43
|
|
|
199
|
|
|
23
|
|
|
222
|
|
Extensions, discoveries, and other additions
|
16
|
|
|
—
|
|
|
16
|
|
|
108
|
|
|
6
|
|
|
114
|
|
Purchases in place
|
1
|
|
|
—
|
|
|
1
|
|
|
3
|
|
|
—
|
|
|
3
|
|
Sales in place
|
(64
|
)
|
|
—
|
|
|
(64
|
)
|
|
(379
|
)
|
|
—
|
|
|
(379
|
)
|
Production
|
(34
|
)
|
|
(2
|
)
|
|
(36
|
)
|
|
(208
|
)
|
|
(35
|
)
|
|
(243
|
)
|
December 31, 2017
|
232
|
|
|
11
|
|
|
243
|
|
|
1,265
|
|
|
174
|
|
|
1,439
|
|
Proved Developed Reserves
|
|
|
|
|
|
|
|
|
|
|
|
||||||
December 31, 2014
|
304
|
|
|
13
|
|
|
317
|
|
|
1,762
|
|
|
207
|
|
|
1,969
|
|
December 31, 2015
|
257
|
|
|
15
|
|
|
272
|
|
|
1,453
|
|
|
179
|
|
|
1,632
|
|
December 31, 2016
|
193
|
|
|
15
|
|
|
208
|
|
|
1,159
|
|
|
166
|
|
|
1,325
|
|
December 31, 2017
|
176
|
|
|
10
|
|
|
186
|
|
|
977
|
|
|
150
|
|
|
1,127
|
|
Proved Undeveloped Reserves
|
|
|
|
|
|
|
|
|
|
|
|
||||||
December 31, 2014
|
162
|
|
|
—
|
|
|
162
|
|
|
853
|
|
|
36
|
|
|
889
|
|
December 31, 2015
|
68
|
|
|
—
|
|
|
68
|
|
|
396
|
|
|
29
|
|
|
425
|
|
December 31, 2016
|
75
|
|
|
—
|
|
|
75
|
|
|
383
|
|
|
14
|
|
|
397
|
|
December 31, 2017
|
56
|
|
|
1
|
|
|
57
|
|
|
288
|
|
|
24
|
|
|
312
|
|
(1)
|
Revisions of prior estimates include the effects of new infill drilling, changes in commodity prices, and other updates, including changes in economic conditions, changes in reservoir performance, and changes to development plans. Additions generated by Anadarko’s infill drilling programs were
71
MMBOE for
2017
,
69
MMBOE for
2016
, and
89
MMBOE for
2015
.
|
MMBOE
|
December 31, 2017
|
|
Revisions due to changes in year-end prices (price impact to opening balance)
|
92
|
|
Other revisions of prior estimates
|
|
|
Revisions due to performance
|
60
|
|
Revisions due to cost updates
|
(4
|
)
|
Revisions due to successful infill drilling
|
71
|
|
Revisions due to development plan updates
|
5
|
|
Other revisions
|
(2
|
)
|
Total other revisions of prior estimates
|
130
|
|
Revisions of prior estimates
|
222
|
|
•
|
Performance
The Company experienced an overall increase of
60
MMBOE in proved reserves due to performance improvements. Numerous areas of the Company contributed to a total upward revision of 91 MMBOE with the largest increases occurring in the DJ and Delaware basin areas. Downward revisions of 31 MMBOE were primarily due to performance reductions in the Lucius area in the Gulf of Mexico and in the Greater Natural Buttes area of the Rockies.
|
•
|
Cost updates
Annual updates reflected cost increases in certain U.S. onshore areas resulting in a minor reduction in proved reserves.
|
•
|
Infill-drilling activities
The Company added
71
MMBOE of proved reserves associated with infill drilling activities, of which 53 MMBOE was in the DJ basin, 13 MMBOE in the Lucius and Holstein areas in the Gulf of Mexico, and the remaining in the Ghana Jubilee field.
|
•
|
Development plan updates
The majority of revisions associated with updates to development plans occurred in the DJ basin due to ongoing optimization of development activity.
|
MMBOE
|
December 31, 2016
|
|
Revisions due to changes in year-end prices (price impact to opening balance)
|
(147
|
)
|
Other revisions of prior estimates
|
|
|
Revisions due to performance
|
74
|
|
Revisions due to cost reductions
|
100
|
|
Revisions due to successful infill drilling
|
69
|
|
Revisions due to development plan updates
|
(3
|
)
|
Other revisions
|
20
|
|
Total other revisions of prior estimates
|
260
|
|
Revisions of prior estimates
|
113
|
|
•
|
Performance
The Company experienced an overall increase of 74 MMBOE in proved reserves. Upward revisions of 102 MMBOE were primarily due to improved well performance in the DJ basin, certain U.S. shale plays, and select wells in the Gulf of Mexico. Downward revisions of 28 MMBOE were primarily due to performance updates associated with select wells in the Gulf of Mexico.
|
•
|
Cost reductions
Ongoing cost-optimization efforts and a reduced cost structure associated with the lower commodity-price environment resulted in an increase in proved reserves. The Eagleford and the DJ basin areas experienced an increase of 94 MMBOE of proved reserves associated with certain wells, included in the negative price-related revisions, which experienced restored economic producibility upon reduction of the cost structure. The remaining increase in proved reserves due to the improved cost structure is attributable to numerous areas across the Company.
|
•
|
Infill-drilling activities
The Company added 69 MMBOE of proved reserves associated with infill drilling activities, the majority of which were in the DJ basin and the K2 and Caesar/Tonga areas of the Gulf of Mexico.
|
•
|
Other revisions
Other revisions resulted from the Company’s multi-step reserves reconciliation process and the elimination of duplicative adjustments to the opening reserves balance.
|
MMBOE
|
December 31, 2015
|
|
Revisions due to changes in year-end prices (price impact to opening balance)
|
(624
|
)
|
Other revisions of prior estimates
|
|
|
Revisions due to performance
|
222
|
|
Revisions due to cost reductions
|
139
|
|
Revisions due to successful infill drilling
|
89
|
|
Revisions due to development plan updates
|
(126
|
)
|
Other revisions
|
54
|
|
Total other revisions of prior estimates
|
378
|
|
Revisions of prior estimates
|
(246
|
)
|
•
|
Performance
The Company experienced an increase of 169 MMBOE in proved reserves primarily due to increases to planned lateral lengths in the Eagleford area of South Texas combined with improved well performance in the Eagleford area, the DJ basin, and the Marcellus area of the Appalachian basin. All other performance increases were a result of minor improvements from numerous areas throughout the Company.
|
•
|
Cost reductions
Capital spent in 2015 associated with ongoing drilling and completion activities, ongoing cost-optimization efforts, and a reduced cost structure associated with the lower commodity-price environment resulted in an increase in proved reserves. The DJ basin and Greater Natural Buttes areas and the Eagleford area experienced an increase of 81 MMBOE of proved reserves due to drilling activity associated with certain wells, included in the negative price-related revisions, which experienced restored economic producibility upon reduction of the capital cost structure. An increase of 14 MMBOE in proved reserves was associated with the Marcellus area where certain wells, included in the negative price-related revisions, experienced extended economic limits as a result of reductions to operating expenses during 2015. The remaining increase in proved reserves due to the improved cost structure was attributable to numerous areas across the Company.
|
•
|
Infill-drilling activities
The Company added 89 MMBOE of proved reserves associated with infill drilling activities during 2015, the majority of which were in the DJ basin.
|
•
|
Development plan updates
The majority of revisions associated with updates to development plans occurred in the DJ basin due to a significantly reduced development pace related to the decrease in commodity prices.
|
•
|
Other revisions
Other revisions resulted from the Company’s multi-step reserves reconciliation process and the elimination of duplicative adjustments to the opening reserves balance.
|
millions
|
United States
|
|
International
|
|
Total
|
||||||
December 31, 2017
|
|
|
|
|
|
||||||
Capitalized
|
|
|
|
|
|
||||||
Unproved properties
|
$
|
2,099
|
|
|
$
|
284
|
|
|
$
|
2,383
|
|
Proved properties
|
43,945
|
|
|
5,773
|
|
|
49,718
|
|
|||
|
46,044
|
|
|
6,057
|
|
|
52,101
|
|
|||
Less accumulated DD&A
|
30,487
|
|
|
3,279
|
|
|
33,766
|
|
|||
Net capitalized costs
|
$
|
15,557
|
|
|
$
|
2,778
|
|
|
$
|
18,335
|
|
|
|
|
|
|
|
||||||
December 31, 2016
|
|
|
|
|
|
||||||
Capitalized
|
|
|
|
|
|
||||||
Unproved properties
|
$
|
3,332
|
|
|
$
|
804
|
|
|
$
|
4,136
|
|
Proved properties
|
47,476
|
|
|
5,752
|
|
|
53,228
|
|
|||
|
50,808
|
|
|
6,556
|
|
|
57,364
|
|
|||
Less accumulated DD&A
|
30,675
|
|
|
2,655
|
|
|
33,330
|
|
|||
Net capitalized costs
|
$
|
20,133
|
|
|
$
|
3,901
|
|
|
$
|
24,034
|
|
millions
|
United States
|
|
International
|
|
Total
|
||||||
Year Ended December 31, 2017
|
|
|
|
|
|
||||||
Property acquisitions
|
|
|
|
|
|
||||||
Unproved
|
$
|
490
|
|
|
$
|
9
|
|
|
$
|
499
|
|
Proved
|
(17
|
)
|
|
—
|
|
|
(17
|
)
|
|||
Exploration
|
654
|
|
|
318
|
|
|
972
|
|
|||
Development
|
2,610
|
|
|
29
|
|
|
2,639
|
|
|||
Total costs incurred
|
$
|
3,737
|
|
|
$
|
356
|
|
|
$
|
4,093
|
|
Year Ended December 31, 2016
|
|
|
|
|
|
||||||
Property acquisitions
|
|
|
|
|
|
||||||
Unproved
|
$
|
178
|
|
|
$
|
9
|
|
|
$
|
187
|
|
Proved
|
2,498
|
|
|
—
|
|
|
2,498
|
|
|||
Exploration
|
398
|
|
|
433
|
|
|
831
|
|
|||
Development
|
1,780
|
|
|
337
|
|
|
2,117
|
|
|||
Total costs incurred
|
$
|
4,854
|
|
|
$
|
779
|
|
|
$
|
5,633
|
|
Year Ended December 31, 2015
|
|
|
|
|
|
||||||
Property acquisitions
|
|
|
|
|
|
||||||
Unproved
|
$
|
293
|
|
|
$
|
1
|
|
|
$
|
294
|
|
Proved
|
81
|
|
|
—
|
|
|
81
|
|
|||
Exploration
|
503
|
|
|
609
|
|
|
1,112
|
|
|||
Development
|
3,660
|
|
|
606
|
|
|
4,266
|
|
|||
Total costs incurred
|
$
|
4,537
|
|
|
$
|
1,216
|
|
|
$
|
5,753
|
|
millions
|
United States
|
|
International
|
|
Total
|
||||||
Year Ended December 31, 2017
|
|
|
|
|
|
||||||
Net revenues from production
|
|
|
|
|
|
||||||
Third-party sales
|
$
|
5,429
|
|
|
$
|
710
|
|
|
$
|
6,139
|
|
Sales to consolidated affiliates
|
1,746
|
|
|
1,084
|
|
|
2,830
|
|
|||
Gains (losses) on property dispositions
|
520
|
|
|
13
|
|
|
533
|
|
|||
|
7,695
|
|
|
1,807
|
|
|
9,502
|
|
|||
Production costs
|
|
|
|
|
|
||||||
Oil and gas operating
|
803
|
|
|
197
|
|
|
1,000
|
|
|||
Oil and gas transportation
|
881
|
|
|
33
|
|
|
914
|
|
|||
Production-related G&A
|
341
|
|
|
15
|
|
|
356
|
|
|||
Production, property, and other taxes
|
226
|
|
|
290
|
|
|
516
|
|
|||
|
2,251
|
|
|
535
|
|
|
2,786
|
|
|||
Exploration expenses
|
1,699
|
|
|
842
|
|
|
2,541
|
|
|||
DD&A
|
3,260
|
|
|
634
|
|
|
3,894
|
|
|||
Impairments related to oil and gas properties
|
229
|
|
|
—
|
|
|
229
|
|
|||
Other operating expense
|
106
|
|
|
108
|
|
|
214
|
|
|||
|
150
|
|
|
(312
|
)
|
|
(162
|
)
|
|||
Income tax expense (benefit)
|
55
|
|
|
191
|
|
|
246
|
|
|||
Results of operations
|
$
|
95
|
|
|
$
|
(503
|
)
|
|
$
|
(408
|
)
|
millions
|
United States
|
|
International
|
|
Total
|
||||||
Year Ended December 31, 2016
|
|
|
|
|
|
||||||
Net revenues from production
|
|
|
|
|
|
||||||
Third-party sales
|
$
|
3,884
|
|
|
$
|
619
|
|
|
$
|
4,503
|
|
Sales to consolidated affiliates
|
1,871
|
|
|
779
|
|
|
2,650
|
|
|||
Gains (losses) on property dispositions
|
(855
|
)
|
|
(6
|
)
|
|
(861
|
)
|
|||
|
4,900
|
|
|
1,392
|
|
|
6,292
|
|
|||
Production costs
|
|
|
|
|
|
||||||
Oil and gas operating
|
607
|
|
|
204
|
|
|
811
|
|
|||
Oil and gas transportation
|
964
|
|
|
38
|
|
|
1,002
|
|
|||
Production-related G&A
|
317
|
|
|
20
|
|
|
337
|
|
|||
Production, property, and other taxes
|
189
|
|
|
282
|
|
|
471
|
|
|||
|
2,077
|
|
|
544
|
|
|
2,621
|
|
|||
Exploration expenses
|
541
|
|
|
405
|
|
|
946
|
|
|||
DD&A
|
3,512
|
|
|
395
|
|
|
3,907
|
|
|||
Impairments related to oil and gas properties
|
55
|
|
|
—
|
|
|
55
|
|
|||
Other operating expense
|
62
|
|
|
49
|
|
|
111
|
|
|||
|
(1,347
|
)
|
|
(1
|
)
|
|
(1,348
|
)
|
|||
Income tax expense (benefit)
|
(494
|
)
|
|
155
|
|
|
(339
|
)
|
|||
Results of operations
|
$
|
(853
|
)
|
|
$
|
(156
|
)
|
|
$
|
(1,009
|
)
|
Year Ended December 31, 2015
|
|
|
|
|
|
||||||
Net revenues from production
|
|
|
|
|
|
||||||
Third-party sales
|
$
|
4,409
|
|
|
$
|
673
|
|
|
$
|
5,082
|
|
Sales to consolidated affiliates
|
2,184
|
|
|
994
|
|
|
3,178
|
|
|||
Gains (losses) on property dispositions
|
(976
|
)
|
|
(14
|
)
|
|
(990
|
)
|
|||
|
5,617
|
|
|
1,653
|
|
|
7,270
|
|
|||
Production costs
|
|
|
|
|
|
||||||
Oil and gas operating
|
815
|
|
|
199
|
|
|
1,014
|
|
|||
Oil and gas transportation
|
1,083
|
|
|
34
|
|
|
1,117
|
|
|||
Production-related G&A
|
398
|
|
|
11
|
|
|
409
|
|
|||
Production, property, and other taxes
|
218
|
|
|
270
|
|
|
488
|
|
|||
|
2,514
|
|
|
514
|
|
|
3,028
|
|
|||
Exploration expenses
|
1,447
|
|
|
1,197
|
|
|
2,644
|
|
|||
DD&A
|
3,785
|
|
|
399
|
|
|
4,184
|
|
|||
Impairments related to oil and gas properties
|
4,033
|
|
|
—
|
|
|
4,033
|
|
|||
Other operating expense
|
150
|
|
|
—
|
|
|
150
|
|
|||
|
(6,312
|
)
|
|
(457
|
)
|
|
(6,769
|
)
|
|||
Income tax expense (benefit)
|
(2,332
|
)
|
|
252
|
|
|
(2,080
|
)
|
|||
Results of operations
|
$
|
(3,980
|
)
|
|
$
|
(709
|
)
|
|
$
|
(4,689
|
)
|
millions
|
United States
|
|
International
|
|
Total
|
||||||
December 31, 2017
|
|
|
|
|
|
||||||
Future cash inflows
|
$
|
38,909
|
|
|
$
|
8,741
|
|
|
$
|
47,650
|
|
Future production costs
|
16,947
|
|
|
3,164
|
|
|
20,111
|
|
|||
Future development costs
|
5,512
|
|
|
679
|
|
|
6,191
|
|
|||
Future income tax expenses
|
3,106
|
|
|
2,147
|
|
|
5,253
|
|
|||
Future net cash flows
|
13,344
|
|
|
2,751
|
|
|
16,095
|
|
|||
10% annual discount for estimated timing of cash flows
|
3,856
|
|
|
579
|
|
|
4,435
|
|
|||
Standardized measure of discounted future net cash flows
|
$
|
9,488
|
|
|
$
|
2,172
|
|
|
$
|
11,660
|
|
December 31, 2016
|
|
|
|
|
|
||||||
Future cash inflows
|
$
|
33,513
|
|
|
$
|
7,328
|
|
|
$
|
40,841
|
|
Future production costs
|
16,921
|
|
|
3,290
|
|
|
20,211
|
|
|||
Future development costs
|
7,292
|
|
|
566
|
|
|
7,858
|
|
|||
Future income tax expenses
|
2,606
|
|
|
1,408
|
|
|
4,014
|
|
|||
Future net cash flows
|
6,694
|
|
|
2,064
|
|
|
8,758
|
|
|||
10% annual discount for estimated timing of cash flows
|
1,658
|
|
|
470
|
|
|
2,128
|
|
|||
Standardized measure of discounted future net cash flows
|
$
|
5,036
|
|
|
$
|
1,594
|
|
|
$
|
6,630
|
|
December 31, 2015
|
|
|
|
|
|
||||||
Future cash inflows
|
$
|
42,919
|
|
|
$
|
10,392
|
|
|
$
|
53,311
|
|
Future production costs
|
21,100
|
|
|
3,829
|
|
|
24,929
|
|
|||
Future development costs
|
7,209
|
|
|
637
|
|
|
7,846
|
|
|||
Future income tax expenses
|
4,146
|
|
|
2,423
|
|
|
6,569
|
|
|||
Future net cash flows
|
10,464
|
|
|
3,503
|
|
|
13,967
|
|
|||
10% annual discount for estimated timing of cash flows
|
3,372
|
|
|
910
|
|
|
4,282
|
|
|||
Standardized measure of discounted future net cash flows
|
$
|
7,092
|
|
|
$
|
2,593
|
|
|
$
|
9,685
|
|
millions
|
United States
|
|
International
|
|
Total
|
||||||
2017
|
|
|
|
|
|
||||||
Balance at January 1
|
$
|
5,036
|
|
|
$
|
1,594
|
|
|
$
|
6,630
|
|
Sales and transfers of oil and gas produced, net of production costs
|
(4,924
|
)
|
|
(1,260
|
)
|
|
(6,184
|
)
|
|||
Net changes in prices and production costs
|
5,116
|
|
|
1,591
|
|
|
6,707
|
|
|||
Changes in estimated future development costs
|
184
|
|
|
(92
|
)
|
|
92
|
|
|||
Extensions, discoveries, additions, and improved recovery, less related costs
|
1,478
|
|
|
98
|
|
|
1,576
|
|
|||
Development costs incurred during the period
|
1,304
|
|
|
6
|
|
|
1,310
|
|
|||
Revisions of previous quantity estimates
|
2,918
|
|
|
882
|
|
|
3,800
|
|
|||
Purchases of minerals in place
|
28
|
|
|
—
|
|
|
28
|
|
|||
Sales of minerals in place
|
(864
|
)
|
|
—
|
|
|
(864
|
)
|
|||
Accretion of discount
|
674
|
|
|
260
|
|
|
934
|
|
|||
Net change in income taxes
|
(416
|
)
|
|
(641
|
)
|
|
(1,057
|
)
|
|||
Other
|
(1,046
|
)
|
|
(266
|
)
|
|
(1,312
|
)
|
|||
Balance at December 31
|
$
|
9,488
|
|
|
$
|
2,172
|
|
|
$
|
11,660
|
|
2016
|
|
|
|
|
|
||||||
Balance at January 1
|
$
|
7,092
|
|
|
$
|
2,593
|
|
|
$
|
9,685
|
|
Sales and transfers of oil and gas produced, net of production costs
|
(3,678
|
)
|
|
(856
|
)
|
|
(4,534
|
)
|
|||
Net changes in prices and production costs
|
(1,953
|
)
|
|
(1,607
|
)
|
|
(3,560
|
)
|
|||
Changes in estimated future development costs
|
742
|
|
|
(126
|
)
|
|
616
|
|
|||
Extensions, discoveries, additions, and improved recovery, less related costs
|
429
|
|
|
—
|
|
|
429
|
|
|||
Development costs incurred during the period
|
1,223
|
|
|
203
|
|
|
1,426
|
|
|||
Revisions of previous quantity estimates
|
1,388
|
|
|
320
|
|
|
1,708
|
|
|||
Purchases of minerals in place
|
193
|
|
|
—
|
|
|
193
|
|
|||
Sales of minerals in place
|
(1,277
|
)
|
|
—
|
|
|
(1,277
|
)
|
|||
Accretion of discount
|
949
|
|
|
431
|
|
|
1,380
|
|
|||
Net change in income taxes
|
690
|
|
|
717
|
|
|
1,407
|
|
|||
Other
|
(762
|
)
|
|
(81
|
)
|
|
(843
|
)
|
|||
Balance at December 31
|
$
|
5,036
|
|
|
$
|
1,594
|
|
|
$
|
6,630
|
|
millions
|
United States
|
|
International
|
|
Total
|
||||||
2015
|
|
|
|
|
|
||||||
Balance at January 1
|
$
|
24,148
|
|
|
$
|
6,512
|
|
|
$
|
30,660
|
|
Sales and transfers of oil and gas produced, net of production costs
|
(4,079
|
)
|
|
(1,153
|
)
|
|
(5,232
|
)
|
|||
Net changes in prices and production costs
|
(28,967
|
)
|
|
(8,010
|
)
|
|
(36,977
|
)
|
|||
Changes in estimated future development costs
|
4,408
|
|
|
221
|
|
|
4,629
|
|
|||
Extensions, discoveries, additions, and improved recovery, less related costs
|
219
|
|
|
—
|
|
|
219
|
|
|||
Development costs incurred during the period
|
2,311
|
|
|
379
|
|
|
2,690
|
|
|||
Revisions of previous quantity estimates
|
(1,890
|
)
|
|
47
|
|
|
(1,843
|
)
|
|||
Purchases of minerals in place
|
30
|
|
|
—
|
|
|
30
|
|
|||
Sales of minerals in place
|
(2,262
|
)
|
|
—
|
|
|
(2,262
|
)
|
|||
Accretion of discount
|
3,648
|
|
|
1,143
|
|
|
4,791
|
|
|||
Net change in income taxes
|
9,940
|
|
|
3,193
|
|
|
13,133
|
|
|||
Other
|
(414
|
)
|
|
261
|
|
|
(153
|
)
|
|||
Balance at December 31
|
$
|
7,092
|
|
|
$
|
2,593
|
|
|
$
|
9,685
|
|
(1)
|
The Consolidated Financial Statements of Anadarko Petroleum Corporation are listed on the Index to this Form 10-K, page 85.
|
(2)
|
Exhibits not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith or double asterisk (**) and are furnished herewith; all exhibits not so designated are incorporated herein by reference to a prior filing under File Number 1-8968 as indicated.
|
Exhibit
Number
|
|
Description
|
||
|
2
|
(i)
|
|
|
|
3
|
(i)
|
|
|
|
|
(ii)
|
|
|
|
4
|
(i)
|
|
|
|
|
(ii)
|
|
|
|
|
(iii)
|
|
|
|
|
(iv)
|
|
|
|
|
(v)
|
|
|
|
|
(vi)
|
|
|
|
|
(vii)
|
|
|
|
|
(viii)
|
|
|
|
|
(ix)
|
|
|
|
|
(x)
|
|
|
|
|
(xi)
|
|
|
|
|
(xii)
|
|
|
|
|
(xiii)
|
|
Exhibit
Number
|
|
Description
|
||
|
4
|
(xiv)
|
|
|
|
|
(xv)
|
|
|
|
|
(xvi)
|
|
|
|
|
(xvii)
|
|
|
|
|
(xviii)
|
|
|
|
|
(xix)
|
|
|
|
|
(xx)
|
|
|
|
|
(xxi)
|
|
|
|
|
(xxii)
|
|
|
|
|
(xxiii)
|
|
|
†
|
10
|
(i)
|
|
|
†
|
|
(ii)
|
|
|
†
|
|
(iii)
|
|
|
†
|
|
(iv)
|
|
|
†
|
|
(v)
|
|
|
†
|
|
(vi)
|
|
|
†
|
|
(vii)
|
|
|
†
|
|
(viii)
|
|
|
†
|
|
(ix)
|
|
|
†*
|
|
(x)
|
|
|
†*
|
|
(xi)
|
|
|
†*
|
|
(xii)
|
|
|
†
|
|
(xiii)
|
|
Exhibit
Number
|
|
Description
|
||
†
|
10
|
(xiv)
|
|
|
†
|
|
(xv)
|
|
|
†
|
|
(xvi)
|
|
|
†
|
|
(xvii)
|
|
|
†
|
|
(xviii)
|
|
|
†
|
|
(xix)
|
|
|
†
|
|
(xx)
|
|
|
†
|
|
(xxi)
|
|
|
†
|
|
(xxii)
|
|
|
†
|
|
(xxiii)
|
|
|
†
|
|
(xxiv)
|
|
|
†
|
|
(xxv)
|
|
|
†
|
|
(xxvi)
|
|
|
†
|
|
(xxvii)
|
|
|
†
|
|
(xxviii)
|
|
|
†
|
|
(xxix)
|
|
|
†
|
|
(xxx)
|
|
|
†
|
|
(xxxi)
|
|
|
†
|
|
(xxxii)
|
|
Exhibit
Number
|
|
Description
|
||
†
|
10
|
(xxxiii)
|
|
|
†
|
|
(xxxiv)
|
|
|
†
|
|
(xxxv)
|
|
|
†
|
|
(xxxvi)
|
|
|
†
|
|
(xxxvii)
|
|
|
†
|
|
(xxxviii)
|
|
|
†
|
|
(xxxix)
|
|
|
†
|
|
(xl)
|
|
|
†
|
|
(xli)
|
|
|
†
|
|
(xlii)
|
|
|
†
|
|
(xliii)
|
|
|
†
|
|
(xliv)
|
|
|
†
|
|
(xlv)
|
|
|
†
|
|
(xlvi)
|
|
|
†
|
|
(xlvii)
|
|
|
†
|
|
(xlviii)
|
|
|
†
|
|
(xlix)
|
|
|
|
|
(l)
|
|
Exhibit
Number
|
|
Description
|
||
|
10
|
(li)
|
|
|
|
|
(lii)
|
|
|
|
|
(liii)
|
|
|
|
|
(liv)
|
|
|
|
|
(lv)
|
|
|
†
|
|
(lvi)
|
|
|
|
|
(lvii)
|
|
|
|
|
(lviii)
|
|
|
|
|
(lix)
|
|
|
†
|
|
(lx)
|
|
|
†
|
|
(lxi)
|
|
|
*
|
12
|
|
|
|
*
|
21
|
|
|
|
*
|
23
|
(i)
|
|
|
*
|
23
|
(ii)
|
|
|
*
|
24
|
|
|
|
*
|
31
|
(i)
|
|
|
*
|
31
|
(ii)
|
|
|
**
|
32
|
|
|
|
*
|
99
|
|
|
|
*
|
101
|
.INS
|
|
XBRL Instance Document
|
*
|
101
|
.SCH
|
|
XBRL Schema Document
|
*
|
101
|
.CAL
|
|
XBRL Calculation Linkbase Document
|
*
|
101
|
.DEF
|
|
XBRL Definition Linkbase Document
|
*
|
101
|
.LAB
|
|
XBRL Label Linkbase Document
|
*
|
101
|
.PRE
|
|
XBRL Presentation Linkbase Document
|
†
|
Management contracts or compensatory plans or arrangements required to be filed pursuant to Item 15.
|
|
|
|
ANADARKO PETROLEUM CORPORATION
|
|
|
|
|
February 15, 2018
|
By:
|
|
/s/ ROBERT G. GWIN
|
|
|
|
Robert G. Gwin
Executive Vice President, Finance and Chief Financial Officer
|
By:
|
/s/ ROBERT G. GWIN
|
|
|
Robert G. Gwin, Attorney-in-Fact
|
|
|
Page
|
|
|
|
|
Article I.
Scope of Plan
|
1
|
|
1.01
|
Background and Purpose
|
1
|
1.02
|
Sources of Payments
|
2
|
|
|
|
Article II.
Definitions
|
2
|
|
2.01
|
Account
|
3
|
2.02
|
Affiliate
|
3
|
2.03
|
Beneficiary
|
3
|
2.04
|
Board
|
3
|
2.05
|
Code
|
3
|
2.06
|
Code Limits
|
3
|
2.07
|
Committee
|
3
|
2.08
|
Company
|
3
|
2.09
|
Company Matching Contributions
|
4
|
2.10
|
Company Stock
|
4
|
2.11
|
Contribution Rate
|
4
|
2.12
|
ERISA
|
4
|
2.13
|
Effective Date
|
4
|
2.14
|
Eligible Employee
|
4
|
2.15
|
Employee
|
4
|
2.16
|
Employer
|
4
|
2.17
|
Fund
|
4
|
2.18
|
Investment Experience
|
4
|
2.19
|
Key Employee
|
4
|
2.20
|
Limited 415 Participant
|
4
|
2.21
|
Participant
|
5
|
2.22
|
Plan
|
5
|
2.23
|
Plan Year
|
5
|
2.24
|
Post-2004 Savings Restoration Plan Account
|
5
|
2.25
|
Pre-2005 Savings Restoration Plan Account
|
5
|
2.26
|
Savings Plan
|
5
|
2.27
|
Section 16 Officer
|
5
|
2.28
|
Separation from Service
|
5
|
2.29
|
Valuation Date
|
5
|
|
|
|
Article III.
Eligibility and Participation
|
5
|
|
|
|
|
Article IV.
Amount of Benefits
|
6
|
|
4.01
|
Post-2004 Savings Restoration Plan Account
|
6
|
4.02
|
Pre-2005 Savings Restoration Plan Account
|
7
|
|
|
|
Article V.
Hypothetical Investment Options
|
7
|
|
5.01
|
Investment of Account in Investment Funds
|
7
|
5.02
|
No Warranties
|
8
|
|
|
|
Article VI.
Payment of Benefits
|
9
|
|
6.01
|
Payment of Participant’s Account
|
9
|
6.02
|
Six-Month Delay
|
9
|
6.03
|
Vesting
|
9
|
|
|
|
Article VII.
Administration
|
9
|
|
7.01
|
Administration by Committee
|
9
|
7.02
|
Administration of Plan
|
9
|
7.03
|
Action by Committee
|
10
|
7.04
|
Delegation
|
10
|
7.05
|
Reliance Upon Information
|
10
|
7.06
|
Rules of Conduct
|
10
|
7.07
|
Legal, Accounting, Clerical and Other Services
|
10
|
7.08
|
Indemnification
|
10
|
7.09
|
Claims Review Procedures
|
11
|
7.10
|
Finality of Determinations; Exhaustion of Remedies
|
13
|
7.11
|
Effect of Committee Action
|
13
|
7.12
|
Effect of Mistake
|
14
|
|
|
|
Article VIII.
General Provisions
|
14
|
|
8.01
|
Plan Amendment, Suspension and/or Termination
|
14
|
8.02
|
Plan Not an Employment Contract
|
15
|
8.03
|
Non-alienation of Benefits
|
15
|
8.04
|
Special Payment Situations
|
16
|
8.05
|
Spin-offs
|
16
|
8.06
|
Duty to Provide Data
|
16
|
8.07
|
Tax Consequences Not Guaranteed
|
17
|
8.08
|
Tax Withholding
|
17
|
8.09
|
Incompetency
|
17
|
8.10
|
Severability
|
18
|
8.11
|
Governing Law
|
18
|
8.12
|
Headings
|
18
|
|
|
|
(1)
|
Timing of Notice
. The notice of denial must be given within 90 days after the claim is received by the Committee. If special circumstances (such as a hearing) require a longer period, the Claimant will be notified in writing, before the expiration of the 90-day period, of the expected decision date and the reasons for an extension of time; provided, however, that no extensions will be permitted beyond 90 days after expiration of the initial 90-day period.
|
(2)
|
Content of Notice
. The notice will set forth:
|
(A)
|
the specific reasons for the denial of the claim;
|
(B)
|
a reference to specific provisions of the Plan on which the denial is based;
|
(C)
|
a description of any additional material or information necessary to perfect the claim and an explanation of why such material or information is necessary; and
|
(D)
|
an explanation of the procedure for review of the denied or partially denied claim, including the Claimant’s right to bring a civil action under ERISA Section 502(a) following an adverse benefit determination on review.
|
(1)
|
Scope of Review
. The review takes into account all comments, documents, records, and other information submitted by the Claimant relating to the claim, without regard to whether such information was submitted or considered in the initial benefit determination.
|
(2)
|
Timing of Request for Review
. A request for review of a claim must be submitted within 60 days of receipt by the Claimant of written notice of the denial of the claim (or, if the Claimant has not received a response to the initial claim, within 150 days of the filing of the initial claim). If the Claimant fails to file a request for review within 60 days of the denial notification (or deemed denial after 150 days), the claim under the Plan is forever abandoned and the Claimant is precluded from reasserting it.
|
(3)
|
Contents of Request for Review
. If the Claimant files a request for review, his request must include a description of the issues and evidence he deems relevant. Failure to raise issues or present evidence on review will preclude those issues or evidence from being presented in any subsequent proceeding or judicial review of the claim.
|
(1)
|
Timing of Denial Notice
. The Committee must render its decision on the review of the claim no more than 60 days after the Committee’s receipt of the request for review, except that this period may be extended for an additional 60 days if the Committee determines that special circumstances (such as a hearing) require such extension. If an extension of time is required, written notice of the expected decision date and the reasons for the extension will be furnished to the Claimant before the end of the initial 60-day period.
|
(2)
|
Contents of Denial
. If the Committee issues a negative decision, it shall provide a prompt written decision to the Claimant setting forth:
|
(A)
|
the specific reason or reasons for the adverse determination;
|
(B)
|
a reference to specific Plan provisions on which the adverse determination was made;
|
(C)
|
a statement that the Claimant is entitled to receive, upon request and free of charge, reasonable access to, and copies of, all documents, records, and other information relevant to the Claimant’s claim for benefits; and
|
(D)
|
a statement describing any voluntary appeal procedures offered by the Plan and the Claimant’s right to obtain the information about such procedures and a statement of the Claimant’s right to bring an action under ERISA Section 502(a).
|
(3)
|
Authority of Committee
. To the extent of its responsibility to review the denial of benefit claims, the Committee has full authority to interpret and apply in its discretion the provisions of the Plan. The decision of the Committee is final and binding upon any and all Claimants and any person making a claim through or under them.
|
ANADARKO PETROLEUM CORPORATION
|
|
|
|
By:
|
/s/ Joseph H. Mongrain
|
|
|
Name:
|
Joseph H. Mongrain
|
|
|
Title:
|
VP Human Resources
|
|
|
|
Page
|
|
|
Article I. Purposes of the Plan
|
1
|
|
|
|
|
|
|
Article II. Definitions
|
1
|
|
|
2.01
|
Definitions
|
1
|
|
|
|
|
|
Article III. Administration
|
3
|
|
|
3.01
|
Administration by Committee
|
3
|
|
3.02
|
Administration of Plan
|
4
|
|
3.03
|
Action by Committee
|
4
|
|
3.04
|
Delegation
|
4
|
|
3.05
|
Reliance Upon Information
|
4
|
|
3.06
|
Indemnity of Plan Administration Employee
|
4
|
|
|
|
|
|
Article IV. Eligibility
|
5
|
|
|
|
|
|
|
Article V. Amount of Benefit
|
5
|
|
|
5.01
|
General Benefits
|
5
|
|
5.02
|
Supplemental Benefits
|
6
|
|
5.03
|
Other Supplemental Benefits
|
6
|
|
|
|
|
|
Article VI. Payment of Benefits
|
7
|
|
|
6.01
|
Lump Sum Benefit
|
7
|
|
6.02
|
Payment Under Retirement Plan Before 2009
|
7
|
|
6.03
|
Specified Employees
|
7
|
|
|
|
|
|
Article VII. Participant's Rights and Nature of Plan
|
8
|
|
|
|
|
|
|
Article VIII. Amendment and Discontinuance
|
8
|
|
|
|
|
|
|
Article IX. Claims Procedure
|
9
|
|
|
9.01
|
Filing a Claim
|
9
|
|
9.02
|
Denial of Claim
|
9
|
|
9.03
|
Reasons for Denial
|
10
|
|
9.04
|
Review of Denial
|
10
|
|
9.05
|
Decision Upon Review
|
10
|
|
9.06
|
Other Procedures
|
11
|
|
9.07
|
Finality of Determinations; Exhaustion of Remedies
|
11
|
|
9.08
|
Effect of Committee Action
|
11
|
|
|
|
|
|
Article X. Miscellaneous
|
12
|
|
|
10.01
|
Construction
|
12
|
|
10.02
|
Powers of the Company
|
12
|
|
10.03
|
Beneficiary Designations
|
12
|
|
10.04
|
Limitation of Rights
|
13
|
|
10.05
|
Distribution due to Qualified Domestic Relations Order
|
13
|
|
10.06
|
Nonalienation of Benefits
|
13
|
|
10.07
|
Facility of Payments
|
13
|
|
10.08
|
Withholding of Taxes
|
14
|
|
10.09
|
Adoption of Plan by Affiliated Entity
|
14
|
|
10.10
|
Waiver
|
14
|
|
10.11
|
Notice
|
14
|
|
10.12
|
Severability
|
14
|
|
10.13
|
Gender, Tense and Headings
|
14
|
|
10.14
|
Governing Law
|
14
|
|
|
|
|
ANADARKO PETROLEUM CORPORATION
|
|
|
|
By:
|
/s/ Joseph H. Mongrain
|
|
|
Name:
|
Joseph H. Mongrain
|
|
|
Title:
|
VP Human Resources
|
|
|
|
Retiree Medical and Dental Supplemental Benefit
|
|
Page
|
|
|
|
|
|
|
Article I Purpose
|
1
|
|
|
|
|
|
|
Article II Definitions
|
1
|
|
|
2.01
|
Accrued Benefit
|
1
|
|
2.02
|
Affiliate
|
1
|
|
2.03
|
Basic Defined Benefit Plan Benefit
|
2
|
|
2.04
|
Beneficiary
|
2
|
|
2.05
|
Board of Directors
|
2
|
|
2.06
|
Code
|
2
|
|
2.07
|
Committee
|
2
|
|
2.08
|
Company
|
2
|
|
2.09
|
Defined Benefit Plan
|
2
|
|
2.10
|
ERISA
|
2
|
|
2.11
|
Effective Date
|
2
|
|
2.12
|
Eligible Employee
|
2
|
|
2.13
|
KMG Change of Control
|
2
|
|
2.14
|
Limited 415 Participant
|
2
|
|
2.15
|
Limits of the Code
|
3
|
|
2.16
|
Nondiscrimination Rules
|
3
|
|
2.17
|
Participant
|
3
|
|
2.18
|
Personal Wealth Account
|
3
|
|
2.19
|
Plan
|
3
|
|
2.20
|
Restored Defined Benefit Plan Benefit
|
3
|
|
2.21
|
Retirement Choice Accrued Benefit
|
3
|
|
2.22
|
Section 16 Officers
|
3
|
|
2.23
|
Senior Executive Group
|
3
|
|
2.24
|
Senior Executive Group Member
|
3
|
|
2.25
|
Separation from Service
|
4
|
|
|
|
|
|
Article III Eligibility and Participation
|
4
|
|
|
|
|
|
|
Article IV Provisions for Benefits
|
4
|
|
|
|
|
|
|
Article V Amount of Benefits
|
4
|
|
|
5.01
|
Restored Defined Benefit Plan Benefits
|
4
|
|
5.02
|
Restored Benefits
|
5
|
|
5.03
|
Payment to Beneficiary
|
5
|
|
5.04
|
Supplement to the Plan
|
5
|
|
|
|
|
|
Article VI Payment of Benefits
|
5
|
|
|
6.01
|
Payment of Restored Defined Benefit Plan Benefit
|
5
|
|
6.02
|
Payment Under Defined Benefit Plan Before 2009
|
6
|
|
6.03
|
Specified Employees
|
7
|
|
|
|
|
Article VII Administration
|
7
|
|
|
7.01
|
Administration by Committee
|
7
|
|
7.02
|
Rules of Conduct
|
7
|
|
7.03
|
Legal, Accounting, Clerical and Other Services
|
7
|
|
7.04
|
Records of Administration
|
7
|
|
7.05
|
Expenses
|
7
|
|
7.06
|
Indemnification
|
7
|
|
7.07
|
Liability
|
8
|
|
7.08
|
Claims Review Procedures
|
8
|
|
|
|
|
|
Article VIII General Provisions
|
11
|
|
|
8.01
|
Plan Amendment, Suspension and/or Termination
|
11
|
|
8.02
|
Plan Not an Employment Contract
|
11
|
|
8.03
|
Non-alienation of Benefits
|
12
|
|
8.04
|
Provisions relating to the KMG Change of Control
|
12
|
|
8.05
|
Special Payment Situations
|
12
|
|
8.06
|
Termination of Employment
|
13
|
|
8.07
|
Duty to Provide Data
|
14
|
|
8.08
|
Tax Consequences Not Guaranteed
|
14
|
|
8.09
|
Tax Withholding
|
14
|
|
8.10
|
Beneficiary Designations
|
15
|
|
8.11
|
Incompetency
|
15
|
|
8.12
|
Severability
|
16
|
|
8.13
|
Governing Law
|
16
|
|
|
|
|
(a)
|
Any corporation other than the Company (i.e., either a subsidiary corporation or an affiliated or associated corporation of the Company), which together with the Company is a member of a “controlled group” of corporations;
|
(b)
|
Any organization with which the Company is under “common control”;
|
(c)
|
Any organization which together with the Company is an “affiliated service group”;
|
(d)
|
A limited liability company wholly owned by the Company; or
|
(e)
|
Any foreign affiliate of the Company which is covered by an agreement under Section 3121(1) of the Code;
|
(a)
|
Filing a Claim
. A Participant or his authorized representative may file a claim for benefits under the Plan (hereafter, referred to as a “Claimant”). Any claim must be in writing and submitted to the Committee at such address as may be specified from time to time. Claimants will be notified in writing of approved claims, which will be processed as claimed. A claim is considered approved only if its approval is communicated in writing to the Claimant.
|
(b)
|
Denial of Claim
. In the case of the denial of a claim respecting benefits paid or payable with respect to a Participant, a written notice will be furnished to the Claimant within 90 days of the date on which the claim is received by the Committee. If special circumstances (such as for a hearing) require a longer period, the Claimant will be notified in writing, prior to the expiration of the 90-day period, of the reasons for an extension of time; provided, however, that no extensions will be permitted beyond 90 days after the expiration of the initial 90-day period.
|
(c)
|
Reasons for Denial
. A denial or partial denial of a claim will be dated and signed by the Committee and will clearly set forth:
|
(1)
|
the specific reason or reasons for the denial;
|
(2)
|
specific reference to pertinent Plan provisions on which the denial is based;
|
(3)
|
a description of any additional material or information necessary for the Claimant to perfect the claim and an explanation of why such material or information is necessary; and
|
(4)
|
an explanation of the procedure for review of the denied or partially denied claim set forth below, including the claimant’s right to bring a civil action under ERISA Section 502(a) following an adverse benefit determination on review.
|
(d)
|
Review of Denial
. Upon denial of a claim, in whole or in part, the Claimant or his duly authorized representative will have the right to submit a written
|
(e)
|
Decision Upon Review
. The Committee will provide a prompt written decision on review to the Claimant. If the claim is denied on review, the decision shall set forth:
|
(1)
|
the specific reason or reasons for the adverse determination;
|
(2)
|
specific reference to pertinent Plan provisions on which the adverse determination is based;
|
(3)
|
a statement that the Claimant is entitled to receive, upon request and free of charge, reasonable access to, and copies of, all documents, records, and other information relevant to the Claimant’s claim for benefits; and
|
(4)
|
a statement describing any voluntary appeal procedures offered by the Plan and the Claimant’s right to obtain the information about such procedures, as well as a statement of the Claimant’s right to bring an action under ERISA Section 502(a).
|
(f)
|
Other Procedures
. Notwithstanding the foregoing, the Committee, in its discretion, may adopt different procedures for different claims without being bound by past actions. Any procedures adopted, however, shall be designed to afford a Claimant a full and fair review of his claim and shall comply with applicable regulations under ERISA.
|
(g)
|
Finality of Determinations: Exhaustion of Remedies
. To the extent permitted by law, decisions reached under the claims procedures set forth in this
Section 7.08
shall be final and binding on all parties. No legal action for benefits under the Plan shall be brought unless and until the Claimant has exhausted his remedies under this Section. In any such legal action, the Claimant may only present evidence and theories which the Claimant presented during the claims procedure. Any claims which the Claimant does not in good faith pursue through the review stage of the procedure shall be treated as having been irrevocably waived. Judicial review of a Claimant’s denied claim shall be limited to a determination of whether the denial was an abuse of discretion based on the evidence and theories the Claimant presented during the claims procedure. Any suit or legal action initiated by a Claimant under the Plan must be brought by the Claimant no later than one year following a final decision on the claim for benefits by the Committee. The one-year limitation on suits for benefits will apply in any forum where a Claimant initiates such suit or legal action.
|
(h)
|
Effect of Committee Action
. The Plan shall be interpreted by the Committee in accordance with the terms of the Plan and their intended meanings. However, the Committee shall have the discretion to make any findings of fact needed in the administration of the Plan, and shall have the discretion to interpret or construe ambiguous, unclear or implied (but omitted) terms in any fashion they deem to be appropriate in their sole judgment. The validity of any such finding of fact, interpretation, construction or decision shall not be given
de novo
review if challenged in court, by arbitration or in any other forum, and shall be upheld unless clearly arbitrary or capricious. To the extent the Committee has been granted discretionary authority under the Plan, the Committee’s prior exercise of such authority shall not obligate it to exercise its authority in a like fashion thereafter. If, due to errors in drafting, any Plan provision does not accurately reflect its intended meaning, as demonstrated by consistent interpretations or other evidence of intent, or as determined by the Committee in its sole and exclusive judgment, the provision shall be considered ambiguous and shall be interpreted by the Committee in a fashion consistent with its intent, as determined by the Committee in its sole discretion. The Committee may amend the Plan retroactively to cure any such ambiguity. This
Section 7.08(h)
may not be invoked by any person to require the Plan to be interpreted in a manner which is inconsistent with its interpretation by the Committee. All actions taken and all determinations made in good faith by the Committee shall be final and binding upon all persons claiming any interest in or under the Plan.
|
(a)
|
Missing Participant or Beneficiary
. Payment of benefits to the person entitled thereto may be sent by first class mail, address correction requested, to the last known address on file with the Committee. If, within two months from the date of issuance of the payment, the payment letter cannot be delivered to the person entitled thereto or the payment has not been negotiated, the payment shall be treated as forfeited. However, if the person to whom the benefit became payable subsequently appears and identifies himself to the satisfaction of the Committee, the amount forfeited (without
|
(b)
|
Private Investigators
. If the Committee retains a private investigator or other person or service to assist in locating a missing person, all costs incurred for such services shall be charged against the benefit to which the missing person was believed to be entitled and the benefit shall be reduced by the amount of the costs incurred, except as the Committee may otherwise direct.
|
(c)
|
Delayed Payment
. Payments to Participants or Beneficiaries may be postponed by the Committee until any anticipated taxes, expenses or amounts to be paid under a qualified domestic relations order have been paid in full or until it is determined that such charges will not be imposed. A payment to a Participant or Beneficiary may also be delayed in the event payment might defeat an adverse potential or asserted claim by some other person to the payment. The cost incurred by the Company in dealing with any such adverse claim shall be charged against the benefit to which the claim relates, except as the Committee otherwise directs. No delay may be made under this
Section 8.05(c)
if such delay would result in taxation to the Participant under Code Section 409A.
|
(a)
|
General Rule
. A Participant’s employment with the Company or its Affiliates shall terminate upon the first to occur of his resignation from or discharge by the Company or its Affiliates (except as provided in subsection (c) with respect to business dispositions) or his death or retirement. A Participant’s employment shall not terminate on account of an authorized leave of absence, disability leave, sick leave, vacation, on account of a military leave described in subsection (b), or transfers between the Company and its Affiliates. However, failure to return to work upon expiration of any leave of absence, sick leave, disability leave, or vacation shall be considered a resignation effective as of the expiration of such leave of absence, sick leave, disability leave, or vacation.
|
(b)
|
Military Leaves
. Any Participant who leaves the Company or its Affiliates directly to perform service in the Armed Forces of the United States or in the United States Public Health Service under conditions entitling the Participant to reemployment rights, as provided in the laws of the United States, shall be on military leave. A Participant’s military leave shall expire if the Participant voluntarily resigns from the Company or its Affiliates during the leave or if he fails to make application for reemployment within the period specified by such law for the preservation of reemployment rights. In such event, the individual’s employment shall be deemed to terminate by resignation on the date the military leave expired.
|
(c)
|
Spinoffs
. Except to the extent otherwise provided by Code Section 409A, if a Participant ceases to be employed by the Company or its Affiliates because of the disposition by the Company or its Affiliates of its interest in a subsidiary, plant, facility or other business unit or if an entity which employs a Participant ceases to be an Affiliate, such Participant’s employment shall be considered terminated for all Plan purposes. This
Section 8.06(c)
shall not apply to the extent it is overridden by any contrary or inconsistent provision in applicable sales documents or any related documents, whether adopted before or after the sale and any such contrary or inconsistent provision shall instead apply and is hereby incorporated in the Plan by this reference.
|
(a)
|
Data Requests
. Every person with an interest in the Plan or claiming benefits under the Plan shall furnish the Committee on a timely and accurate basis with such documents, evidence or information as it considers necessary or desirable for the purpose of administering the Plan. The Committee may postpone payment of benefits (without accrual of interest) until such information and such documents have been furnished.
|
(b)
|
Addresses
. Every person claiming a benefit under the Plan shall give written notice to the Committee of his post office address and each change of post office address. Any communication, statement or notice addressed to such a person at his latest post office address as filed with the Committee will, on deposit in the United States mail with postage prepaid, be as binding upon such person for all purposes of the Plan as if it had been received, whether actually received or not. If a person fails to give notice of his correct address, the Committee, the Company and its Affiliates and Plan fiduciaries shall not be obliged to search for, or to ascertain, his whereabouts.
|
(c)
|
Failure to Comply
. If benefits which are otherwise currently payable cannot be paid to the person entitled to the benefits because the individual has failed to comply with this Section or other Plan provisions relating to claims for benefits, any unpaid past due amount shall be forfeited on the individual’s death or presumed death.
|
ANADARKO PETROLEUM CORPORATION
|
|
|
|
By:
|
/s/ Joseph H. Mongrain
|
|
|
Name:
|
Joseph H. Mongrain
|
|
|
Title:
|
VP Human Resources
|
|
|
(A)
|
Applicability of First Supplement
|
(1)
|
This First Supplement to the Kerr-McGee Corporation Benefits Restoration Plan (the “First Supplement”) forms a part of the Kerr-McGee Corporation Benefits Restoration Plan as in effect on and after May 1, 1999 (the “Plan”). The provisions of this First Supplement shall apply only to those Participants who were Participants in the Oryx Energy Company Pension Restoration Plan (the “Oryx Plan”) as of December 31, 1999 (“Former Oryx Participants”) who became Participants in the Plan effective January 1, 2000 (hereinafter referred to as “First Supplement Participants”).
|
(2)
|
There shall be no duplication of benefits provided under the Plan and this First Supplement, and the actuarially equivalent benefits payable under one shall be inclusive of the actuarially equivalent benefits payable under the other unless specifically provided otherwise in the provisions of the Plan or this First Supplement.
|
(3)
|
All terms used in this First Supplement shall have the meanings assigned to them in the provisions of the Plan, unless a different meaning is plainly required by the context.
|
(B)
|
Merger of Oryx Plan into the Plan Effective January 1, 2000
|
(1)
|
The Oryx Plan had previously been sponsored by Oryx Energy Company (“Oryx”). Oryx was merged with Kerr-McGee Corporation (“KMG”) effective February 26, 1999 (the “Merger”). Due to the Merger, KMG assumed the Oryx Plan and obligations thereunder including those to the Former Oryx Participants.
|
(2)
|
KMG believed that it would be in the best interest of the Oryx Plan, the Plan and the Participants therein that the Oryx Plan be merged and continued in the Plan effective January 1, 2000.
|
(3)
|
The effective date of the merger of the Oryx Plan into the Plan shall be January 1, 2000.
|
(4)
|
Upon merger of the Oryx Plan into the Plan effective January 1, 2000, there shall be no further benefit accruals pursuant to the terms of the Oryx Plan, and benefits for all First Supplement Participants shall accrue thereafter in accordance with the terms of the Plan. Following the merger, all benefits earned under the Oryx Plan prior to January 1, 2000, and benefits earned pursuant to the Plan from and after
|
(C)
|
Benefits Applicable to First Supplement Participants
|
(1)
|
The term “Defined Benefit Plan” as applicable for a First Supplement Participant means the Kerr-McGee Corporation Retirement Plan or its successor plan or the Oryx Energy Company Retirement Plan prior to its merger with the Kerr-McGee Corporation Retirement Plan on January 1, 2000.
|
(2)
|
The Restored Defined Benefit Plan Benefit under the Plan accrued by a First Supplement Participant under Section 7 of the Oryx Plan as of January 1, 2000, immediately prior to the merger of the Oryx Plan with the Plan (hereinafter referred to as the “Oryx Plan Restored Benefit”) will be paid at the same time as the benefits under the Defined Benefit Plan and in the form of a lump sum, subject to offset pursuant to Section 9 of the Oryx Plan, if applicable, regardless of the form of payment of the benefit under the Defined Benefit Plan. The amount of such lump sum will be determined as the actuarial equivalent of the Oryx Plan Restored Benefit. Such actuarial equivalency will be determined in the same manner as and on the same basis as the actuarial assumptions provided in the Defined Benefit Plan. The provisions of
Section 6.01
of the Plan are not applicable to the Oryx Plan Restored Benefit of a First Supplement Participant.
|
(3)
|
Effective January 1, 2000, that portion, if any, of the Restored Defined Benefit Plan Benefit under the Plan payable to a First Supplement Participant that is in excess of the Participant’s Oryx Plan Restored Benefit will be payable in accordance with
Section 6.01
of the Plan.
|
(4)
|
Former Oryx Participants who were receiving or who were eligible to receive benefits from the Sun Company, Inc. Pension Restoration Plan and who were transferred to the Oryx Plan as of November 1, 1988, shall continue to receive or be eligible to receive their benefits under the Plan.
|
(D)
|
Right to Amend or Terminate First Supplement
|
|
|
|
Years Ended December 31,
|
||||||||||||||||||
|
|
|
(Unaudited)
|
||||||||||||||||||
millions except ratio amounts
|
2017
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
||||||||||||
Income (loss) from continuing operations before income taxes
|
$
|
(1,688
|
)
|
|
$
|
(3,829
|
)
|
|
$
|
(9,689
|
)
|
|
$
|
54
|
|
|
$
|
2,106
|
|
||
Equity (income) adjustment
|
(148
|
)
|
|
(120
|
)
|
|
(86
|
)
|
|
(119
|
)
|
|
(64
|
)
|
|||||||
Fixed charges
|
1,397
|
|
|
1,337
|
|
|
1,240
|
|
|
1,245
|
|
|
1,173
|
|
|||||||
Amortization of capitalized interest
|
111
|
|
|
82
|
|
|
74
|
|
|
61
|
|
|
46
|
|
|||||||
Distributed income of equity investees
|
171
|
|
|
141
|
|
|
105
|
|
|
121
|
|
|
25
|
|
|||||||
Capitalized interest
|
(71
|
)
|
|
(132
|
)
|
|
(164
|
)
|
|
(201
|
)
|
|
(263
|
)
|
|||||||
Preference security dividend requirements of consolidated subsidiaries
|
(52
|
)
|
|
(105
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Non-controlling interest in pre-tax income of subsidiaries that have not incurred fixed charges
|
(11
|
)
|
|
(11
|
)
|
|
(21
|
)
|
|
(14
|
)
|
|
(11
|
)
|
|||||||
|
Total Earnings
|
$
|
(291
|
)
|
|
$
|
(2,637
|
)
|
|
$
|
(8,541
|
)
|
|
$
|
1,147
|
|
|
$
|
3,012
|
|
|
Interest expense including capitalized interest
|
1,058
|
|
|
1,043
|
|
|
990
|
|
|
974
|
|
|
930
|
|
|||||||
Interest expense included in other (income) expense
|
64
|
|
|
49
|
|
|
37
|
|
|
36
|
|
|
37
|
|
|||||||
Estimated interest portion of rental expenditures
|
223
|
|
|
140
|
|
|
213
|
|
|
235
|
|
|
206
|
|
|||||||
Preference security dividend requirements of consolidated subsidiaries
|
52
|
|
|
105
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
|
Total Fixed Charges
|
$
|
1,397
|
|
|
$
|
1,337
|
|
|
$
|
1,240
|
|
|
$
|
1,245
|
|
|
$
|
1,173
|
|
|
Preferred Stock Dividends
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Combined Fixed Charges and Preferred Stock Dividends
|
$
|
1,397
|
|
|
$
|
1,337
|
|
|
$
|
1,240
|
|
|
$
|
1,245
|
|
|
$
|
1,173
|
|
||
Ratio of Earnings to Fixed Charges
|
*
|
|
|
*
|
|
|
*
|
|
|
*
|
|
|
2.57
|
|
|||||||
Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends
|
*
|
|
|
*
|
|
|
*
|
|
|
*
|
|
|
2.57
|
|
*
|
Anadarko’s earnings did not cover total fixed charges by $1,688 for 2017, $3,974 for 2016, $9,781 million for 2015, and $98 million for 2014.
|
LIST OF SUBSIDIARIES
(1)
|
|
At December 31, 2017
|
|
|
|
Name of Subsidiary
|
State, Province, or Country in Which Organized
|
Anadarko 20-32 Company
|
Cayman Islands
|
Anadarko 20-42 Company
|
Cayman Islands
|
Anadarko Algeria Company, LLC
|
Delaware
|
Anadarko Brazil Investment I LLC
|
Delaware
|
Anadarko China Holdings 2 Company
|
Cayman Islands
|
Anadarko Colombia Company
(2)
|
Cayman Islands
|
Anadarko Consolidated Holdings LLC
(2)
|
Delaware
|
Anadarko Côte d'Ivoire Block 103 Company
(2)
|
Cayman Islands
|
Anadarko Côte d'Ivoire Company
|
Cayman Islands
|
Anadarko Development Company
|
Cayman Islands
|
Anadarko Development Holding Limited
|
Gibraltar
|
Anadarko E&P Onshore LLC
(2)
|
Delaware
|
Anadarko Egypt Holdings Company
|
Delaware
|
Anadarko Energy Marketing, Inc.
|
Delaware
|
Anadarko Energy Services Company
(2)
|
Delaware
|
Anadarko Exploracao e Producao de Petroleo e Gas Natural Ltda.
|
Brazil
|
Anadarko Gathering Company LLC
|
Delaware
|
Anadarko Ghana Mahogany-1 Company
|
Cayman Islands
|
Anadarko Global Energy S.a.r.l.
(2)
|
Luxembourg
|
Anadarko Global Funding 1 Company
|
Cayman Islands
|
Anadarko Global Funding II Ltd.
|
Bahama Islands
|
Anadarko Holding Company
(2)
|
Utah
|
Anadarko International Development S.a.r.l.
|
Luxembourg
|
Anadarko Land Corp.
|
Nebraska
|
Anadarko Midkiff/Chaney Dell LLC
|
Delaware
|
Anadarko Moçambique Área 1, Limitada
|
Mozambique
|
Anadarko Offshore Holding Company, LLC
|
Delaware
|
Anadarko Offshore Well Containment Company LLC
|
Delaware
|
Anadarko Petroleum Corporation
(2)
|
Delaware
|
Anadarko Realty, LLC
|
Texas
|
Anadarko Rockies LLC
(2)
|
Delaware
|
Anadarko Uintah Midstream, LLC
|
Delaware
|
Anadarko US Offshore LLC
(2)
|
Delaware
|
Anadarko USH1 Corporation
(2)
|
Delaware
|
Anadarko Venezuela Company
|
Cayman Islands
|
Anadarko Venezuela LLC
|
Delaware
|
Anadarko Wattenberg Oil Complex LLC
|
Delaware
|
Anadarko WCTP Company
(2)
|
Cayman Islands
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Anadarko West Texas LLC
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Delaware
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Anadarko Worldwide Holdings C.V.
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The Netherlands
|
APC International Holdings LLC
|
Delaware
|
APC Midstream Holdings, LLC
|
Delaware
|
Bitter Creek Coal Company
|
Utah
|
Chipeta Processing LLC
|
Delaware
|
Delaware Basin JV Gathering LLC
|
Delaware
|
Delaware Basin Midstream, LLC
|
Delaware
|
Headwater II, LLC
|
Delaware
|
Kerr-McGee Corporation
(2)
|
Delaware
|
Kerr-McGee Energy Services Corporation
|
Delaware
|
Kerr-McGee Gathering LLC
(2)
|
Colorado
|
Kerr-McGee Oil & Gas Onshore LP
(2)
|
Delaware
|
Kerr-McGee Shared Services Company LLC
(2)
|
Delaware
|
Kerr-McGee Worldwide Corporation
(2)
|
Delaware
|
KM BM-C-Seven Ltd.
(2)
|
Cayman Islands
|
Mountain Gas Resources LLC
|
Delaware
|
Rock Springs Royalty Company LLC
|
Utah
|
Springfield Pipeline LLC
|
Texas
|
Upland Industries Corporation
|
Nebraska
|
Venezuela US SRL
|
Barbados
|
Western Gas Equity Partners, LP
|
Delaware
|
Western Gas Holdings, LLC
|
Delaware
|
Western Gas Partners, LP
(2)
|
Delaware
|
Western Gas Resources, Inc.
(2)
|
Delaware
|
Western Gas Resources-Westana, Inc.
|
Delaware
|
WGR Asset Holding Company LLC
(2)
|
Delaware
|
WGR Operating, LP
(2)
|
Delaware
|
(1)
|
The names of certain subsidiaries have been omitted since, considered in the aggregate as a single subsidiary, they would not constitute a significant subsidiary, as of the end of the year covered by this report, as defined under the Securities and Exchange Commission Regulation S-X 210.1-02(w).
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(2)
|
Subsidiary meets the conditions of a significant subsidiary under the Securities and Exchange Commission Regulation S-X 210.1-02(w).
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/s/ KPMG LLP
|
|
Houston, Texas
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February 15, 2018
|
Re:
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Securities and Exchange Commission
|
|
Form 10-K of Anadarko Petroleum Corporation
|
|
Very truly yours,
|
|
|
|
|
|
MILLER AND LENTS, LTD.
|
|
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Texas Registered Engineering Firm No. F-1442
|
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By:
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/s/ ROBERT J. OBERST
|
|
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Robert J. Oberst,
P.E.
|
|
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Chairman
|
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/s/ R. A. WALKER
|
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/s/ ANTHONY R. CHASE
|
R. A. Walker
|
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Anthony R. Chase
|
|
|
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/s/ DAVID E. CONSTABLE
|
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/s/ H. PAULETT EBERHART
|
David E. Constable
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H. Paulett Eberhart
|
|
|
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/s/ CLAIRE S. FARLEY
|
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/s/ PETER J. FLUOR
|
Claire S. Farley
|
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Peter J. Fluor
|
|
|
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/s/ JOSEPH W. GORDER
|
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/s/ JOHN R. GORDON
|
Joseph W. Gorder
|
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John R. Gordon
|
|
|
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/s/ SEAN GOURLEY
|
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/s/ MARK C. MCKINLEY
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Sean Gourley
|
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Mark C. McKinley
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/s/ ERIC D. MULLINS
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Eric D. Mullins
|
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1.
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I have reviewed this annual report on Form 10-K of Anadarko Petroleum Corporation;
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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;
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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;
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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.
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/s/ R. A. WALKER
|
R. A. Walker
|
Chairman, President and Chief Executive Officer
|
1.
|
I have reviewed this annual report on Form 10-K of Anadarko Petroleum 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.
|
/s/ ROBERT G. GWIN
|
Robert G. Gwin
|
Executive Vice President, Finance and Chief Financial Officer
|
(1)
|
the Annual Report on Form 10-K of the Company for the period ended
December 31, 2017
, as filed with the Securities and Exchange Commission on the date hereof (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 15, 2018
|
|
|
|
|
|
|
|
/s/ R. A. WALKER
|
|
|
R. A. Walker
|
|
|
Chairman, President and Chief Executive Officer
|
|
|
|
February 15, 2018
|
|
|
|
|
|
|
|
/s/ ROBERT G. GWIN
|
|
|
Robert G. Gwin
|
|
|
Executive Vice President, Finance and Chief Financial Officer
|
Re:
|
Procedures and Methods Review of Anadarko Petroleum Corporation
|
|
Proved Reserves and Future Net Cash Flows As of December 31, 2017
|
|
Yours very truly,
|
|
|
|
MILLER AND LENTS, LTD.
|
|
Texas Registered Engineering Firm No. F-1442
|
By:
|
/s/ ROBERT J. OBERST
|
|
Robert J. Oberst
|
|
Chairman
|