ý
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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
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Delaware
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|
76-0146568
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(State or other jurisdiction of incorporation or organization)
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(I.R.S. Employer Identification No.)
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1201 Lake Robbins Drive, The Woodlands, Texas
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77380-1046
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(Address of principal executive offices)
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(Zip Code)
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Title of each class
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Name of each exchange on which registered
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Common Stock, par value $0.10 per share
|
|
New York Stock Exchange
|
7.50% Tangible Equity Units
|
|
New York Stock Exchange
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Title of Class
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|
Number of Shares Outstanding
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Common Stock, par value $0.10 per share
|
|
558,979,551
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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.
|
|
Oil
(MMBbls)
|
|
Natural Gas
(Bcf)
|
|
NGLs
(MMBbls)
|
|
Total
(MMBOE)
|
||||
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
|
|
|
|
|
|
|
|
|
|
||||
December 31, 2014
|
|
|
|
|
|
|
|
||||
Proved
|
|
|
|
|
|
|
|
||||
Developed
|
|
|
|
|
|
|
|
||||
United States
|
352
|
|
|
6,635
|
|
|
304
|
|
|
1,762
|
|
International
|
190
|
|
|
27
|
|
|
13
|
|
|
207
|
|
Undeveloped
|
|
|
|
|
|
|
|
||||
United States
|
352
|
|
|
2,033
|
|
|
162
|
|
|
853
|
|
International
|
35
|
|
|
4
|
|
|
—
|
|
|
36
|
|
Total proved
|
929
|
|
|
8,699
|
|
|
479
|
|
|
2,858
|
|
MMBOE
|
2016
|
|
2015
|
|
2014
|
|||
Proved Reserves
|
|
|
|
|
|
|||
January 1
|
2,057
|
|
|
2,858
|
|
|
2,792
|
|
Reserves additions and revisions
|
|
|
|
|
|
|||
Discoveries and extensions
|
40
|
|
|
29
|
|
|
63
|
|
Infill-drilling additions
(1)
|
69
|
|
|
89
|
|
|
577
|
|
Drilling-related reserves additions and revisions
|
109
|
|
|
118
|
|
|
640
|
|
Other non-price-related revisions
(1)
|
191
|
|
|
289
|
|
|
(137
|
)
|
Net organic reserves additions
|
300
|
|
|
407
|
|
|
503
|
|
Acquisition of proved reserves in place
|
97
|
|
|
1
|
|
|
—
|
|
Price-related revisions
(1)
|
(147
|
)
|
|
(624
|
)
|
|
(1
|
)
|
Total reserves additions and revisions
|
250
|
|
|
(216
|
)
|
|
502
|
|
Sales in place
|
(294
|
)
|
|
(279
|
)
|
|
(124
|
)
|
Production
|
(291
|
)
|
|
(306
|
)
|
|
(312
|
)
|
December 31
|
1,722
|
|
|
2,057
|
|
|
2,858
|
|
Proved Developed Reserves
|
|
|
|
|
|
|||
January 1
|
1,632
|
|
|
1,969
|
|
|
2,003
|
|
December 31
|
1,325
|
|
|
1,632
|
|
|
1,969
|
|
(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 in
2016
are primarily a reflection of performance improvements coupled with the benefit of reduced year-end costs.
|
MMBOE
|
|
|
PUDs at January 1, 2016
|
425
|
|
Revisions of prior estimates
|
70
|
|
Extensions, discoveries, and other additions
|
5
|
|
Conversions to developed
|
(118
|
)
|
Purchases
|
30
|
|
Sales
|
(15
|
)
|
PUDs at December 31, 2016
|
397
|
|
MMBOE
|
December 31, 2016
|
|
Revisions due to changes in year-end prices (price impact to opening balance)
|
(74
|
)
|
Other revisions of prior estimates
|
|
|
Revisions due to performance
|
10
|
|
Revisions due to cost reductions
|
53
|
|
Revisions due to successful infill drilling
|
60
|
|
Revisions due to development plan updates
|
3
|
|
Other revisions
|
18
|
|
Total other revisions of prior estimates
|
144
|
|
Revisions of prior estimates
|
70
|
|
•
|
Performance
The Company experienced an increase in PUDs primarily due to improved well performance in the DJ basin and U.S. shale play areas.
|
•
|
Cost reductions
Ongoing cost-optimization efforts and a reduced cost structure associated with the lower commodity-price environment resulted in an increase in PUDs. The DJ basin and Eagleford areas experienced an increase of 45 MMBOE of PUDs 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 PUDs due to the improved cost structure is attributable to several other areas across the Company.
|
•
|
Infill drilling
The Company added 60 MMBOE of infill PUDs during 2016, with a majority of the additions in the DJ basin and the K2 and Caesar/Tonga areas of the Gulf of Mexico.
|
•
|
Other revisions
Certain projects that had negative price-related revisions associated with the opening PUDs balance were also either converted to developed status during the year or moved to other unproved categories, primarily as a result of changes to development plans. In an effort to provide full transparency of price sensitivity, the price-related revisions and these other changes were disclosed completely and independently rather than as a net impact. The multi-step process to reconcile and explain changes in reserves resulted in an immaterial duplicative reduction of reserves. These other revisions eliminate the duplicative adjustments to the opening reserves balance.
|
|
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)
|
|
|||||||||
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Wattenberg (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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Wattenberg (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
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Wattenberg (DJ basin)
|
27
|
|
|
125
|
|
|
13
|
|
|
62
|
|
|
87.76
|
|
|
4.19
|
|
|
36.46
|
|
|
8.28
|
|
Other United States
|
47
|
|
|
820
|
|
|
30
|
|
|
213
|
|
|
88.13
|
|
|
4.05
|
|
|
35.03
|
|
|
9.04
|
|
Total United States
|
74
|
|
|
945
|
|
|
43
|
|
|
275
|
|
|
87.99
|
|
|
4.07
|
|
|
35.48
|
|
|
8.87
|
|
International
|
32
|
|
|
—
|
|
|
1
|
|
|
33
|
|
|
99.79
|
|
|
—
|
|
|
56.16
|
|
|
8.22
|
|
Total
|
106
|
|
|
945
|
|
|
44
|
|
|
308
|
|
|
91.58
|
|
|
4.07
|
|
|
36.01
|
|
|
8.80
|
|
(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
|
3,230
|
|
|
1,896
|
|
|
2,976
|
|
|
1,127
|
|
|
9,906
|
|
|
8,212
|
|
|
16,112
|
|
|
11,235
|
|
Offshore
|
351
|
|
|
198
|
|
|
1,525
|
|
|
1,144
|
|
|
—
|
|
|
—
|
|
|
1,876
|
|
|
1,342
|
|
Total United States
|
3,581
|
|
|
2,094
|
|
|
4,501
|
|
|
2,271
|
|
|
9,906
|
|
|
8,212
|
|
|
17,988
|
|
|
12,577
|
|
International
|
611
|
|
|
132
|
|
|
46,315
|
|
|
32,481
|
|
|
—
|
|
|
—
|
|
|
46,926
|
|
|
32,613
|
|
Total
|
4,192
|
|
|
2,226
|
|
|
50,816
|
|
|
34,752
|
|
|
9,906
|
|
|
8,212
|
|
|
64,914
|
|
|
45,190
|
|
(1)
|
The Company’s fee mineral acreage is primarily undeveloped.
|
|
Net Exploratory
|
|
Net Development
|
|
Total
|
|||||||||||||||
|
Productive
|
|
Dry Holes
|
|
Total
|
|
Productive
|
|
Dry Holes
|
|
Total
|
|
||||||||
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
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
United States
|
35.6
|
|
|
1.6
|
|
|
37.2
|
|
|
811.4
|
|
|
6.0
|
|
|
817.4
|
|
|
854.6
|
|
International
|
0.9
|
|
|
4.5
|
|
|
5.4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5.4
|
|
Total
|
36.5
|
|
|
6.1
|
|
|
42.6
|
|
|
811.4
|
|
|
6.0
|
|
|
817.4
|
|
|
860.0
|
|
|
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
|
3
|
|
|
9
|
|
|
51
|
|
|
643
|
|
Net
|
2.1
|
|
|
5.8
|
|
|
21.9
|
|
|
375.3
|
|
International
|
|
|
|
|
|
|
|
||||
Gross
|
2
|
|
|
—
|
|
|
54
|
|
|
11
|
|
Net
|
1.0
|
|
|
—
|
|
|
17.4
|
|
|
2.6
|
|
Total
|
|
|
|
|
|
|
|
||||
Gross
|
5
|
|
|
9
|
|
|
105
|
|
|
654
|
|
Net
|
3.1
|
|
|
5.8
|
|
|
39.3
|
|
|
377.9
|
|
(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 106 MMBOE of PUDs assigned to U.S. onshore development wells suspended or waiting on completion at December 31, 2016. 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
|
3,949
|
|
|
12,615
|
|
Net
|
2,505.9
|
|
|
9,518.6
|
|
International
|
|
|
|
||
Gross
|
208
|
|
|
9
|
|
Net
|
37.4
|
|
|
2.2
|
|
Total
|
|
|
|
||
Gross
|
4,157
|
|
|
12,624
|
|
Net
|
2,543.3
|
|
|
9,520.8
|
|
(1)
|
Includes wells containing multiple completions as follows:
|
Gross
|
209
|
|
|
2,405
|
|
Net
|
182.4
|
|
|
2,089.0
|
|
Area
|
|
Miles of
Pipelines
|
|
Total
Horsepower
|
|
2016
Average Net
Throughput
(MMcf/d)
|
|||
DJ basin
|
|
5,700
|
|
|
357,500
|
|
|
1,100
|
|
Delaware basin
|
|
1,600
|
|
|
275,900
|
|
|
500
|
|
Greater Natural Buttes
|
|
1,300
|
|
|
233,700
|
|
|
900
|
|
Marcellus
|
|
800
|
|
|
104,200
|
|
|
1,000
|
|
Eagleford
|
|
900
|
|
|
203,900
|
|
|
500
|
|
Other
|
|
6,200
|
|
|
245,800
|
|
|
900
|
|
Total
|
|
16,500
|
|
|
1,421,000
|
|
|
4,900
|
|
•
|
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 emissions
|
•
|
the U.S. Federal Water Pollution Control Act, also known as the federal Clean Water Act (CWA), 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 (OPA), 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
|
Name
|
|
Age at
January 31,
2017
|
|
Position
|
R. A. Walker
|
|
59
|
|
Chairman, President and Chief Executive Officer
|
Robert G. Gwin
|
|
53
|
|
Executive Vice President, Finance and Chief Financial Officer
|
Darrell E. Hollek
|
|
59
|
|
Executive Vice President, Operations
|
Mitchell W. Ingram
|
|
54
|
|
Executive Vice President, Global LNG
|
Ernest A. Leyendecker
|
|
56
|
|
Executive Vice President, International and Deepwater Exploration
|
Robert K. Reeves
|
|
59
|
|
Executive Vice President, Law and Chief Administrative Officer
|
Christopher O. Champion
|
|
47
|
|
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 risks
|
•
|
processing volumes and pipeline throughput
|
•
|
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
|
•
|
uncertainties associated with acquired properties and businesses
|
•
|
disruptions in international oil and NGLs cargo shipping activities
|
•
|
physical, digital, 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
|
•
|
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, liquefied natural gas, 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 restrict the exploration, development, and production of oil and natural gas in order to minimize emissions of carbon dioxide, a greenhouse gas (GHG)
|
•
|
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, and 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 (NAAQS) 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 is expected to make final geographical attainment designations and issue final non-attainment area requirements pursuant to this NAAQS rule by late 2017, and any designations or requirements that result in reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modified sources of air pollution in newly designated non-attainment areas. Moreover, states are expected to implement more stringent regulations, which could apply to our operations. Compliance with this rule 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 comprised of New Source Performance Standards, known as Subpart Quad OOOOa, that require 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 Quad OOOOa standards will expand previously issued New Source Performance Standards published by the EPA in 2012, known as Subpart OOOO, 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 equipment leaks at natural-gas processing plants and pneumatic pumps. Moreover, in November 2016, the EPA issued a final Information Collection Request seeking information about methane emissions from facilities and operators in the oil and natural-gas industry. The EPA has indicated that it intended to use the information from this request to develop Existing Source Performance Standards for the oil and gas industry. Compliance with this rule could, among other things, require installation of new emission controls on some of our equipment and significantly 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, Oklahoma issued new rules for wastewater disposal wells in 2014 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 adopted similar permitting, operating, and reporting rules for disposal wells in 2014. 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 efforts, 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 legislations, 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 requires 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. Substantial limitations on GHG emissions 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 such as 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 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
|
||||||||
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
|
|
2015
|
|
|
|
|
|
|
|
||||||||
Market Price
|
|
|
|
|
|
|
|
||||||||
High
|
$
|
90.10
|
|
|
$
|
95.94
|
|
|
$
|
78.70
|
|
|
$
|
73.87
|
|
Low
|
$
|
73.82
|
|
|
$
|
77.75
|
|
|
$
|
58.10
|
|
|
$
|
44.50
|
|
Dividends
|
$
|
0.27
|
|
|
$
|
0.27
|
|
|
$
|
0.27
|
|
|
$
|
0.27
|
|
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
|
|
6,620,252
|
|
|
$
|
76.10
|
|
|
33,927,750
|
|
Equity compensation plans not approved by security holders
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total
|
|
6,620,252
|
|
|
$
|
76.10
|
|
|
33,927,750
|
|
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
|
|
Approximate dollar
value of shares that
may yet be
purchased under the
plans or programs
|
||||||
October 1-31, 2016
|
|
29,815
|
|
|
$
|
61.63
|
|
|
—
|
|
|
|
||
November 1-30, 2016
|
|
46,041
|
|
|
$
|
59.09
|
|
|
—
|
|
|
|
||
December 1-31, 2016
|
|
13,067
|
|
|
$
|
69.44
|
|
|
—
|
|
|
|
||
Total
|
|
88,923
|
|
|
$
|
61.46
|
|
|
—
|
|
|
$
|
—
|
|
(1)
|
During the fourth quarter of
2016
, all purchased shares related to stock received by the Company for the payment of withholding taxes due on employee share issuances under share-based compensation plans.
|
Fiscal Year Ended December 31
|
2011
|
|
2012
|
|
2013
|
|
2014
|
|
2015
|
|
2016
|
||||||||||||
Anadarko Petroleum Corporation
|
$
|
100.00
|
|
|
$
|
97.84
|
|
|
$
|
105.07
|
|
|
$
|
110.47
|
|
|
$
|
66.07
|
|
|
$
|
95.18
|
|
S&P 500
|
100.00
|
|
|
116.00
|
|
|
153.58
|
|
|
174.60
|
|
|
177.01
|
|
|
198.18
|
|
||||||
2016 Peer Group
|
100.00
|
|
|
101.98
|
|
|
128.16
|
|
|
118.26
|
|
|
90.77
|
|
|
118.40
|
|
||||||
2015 Peer Group
|
100.00
|
|
|
101.04
|
|
|
127.81
|
|
|
117.70
|
|
|
89.44
|
|
|
116.70
|
|
|
Summary Financial Information
(1)
|
||||||||||||||||||
millions except per-share amounts
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
Sales Revenues
|
$
|
8,447
|
|
|
$
|
9,486
|
|
|
$
|
16,375
|
|
|
$
|
14,867
|
|
|
$
|
13,307
|
|
Gains (Losses) on Divestitures and Other, net
|
(578
|
)
|
|
(788
|
)
|
|
2,095
|
|
|
(286
|
)
|
|
104
|
|
|||||
Total Revenues and Other
|
7,869
|
|
|
8,698
|
|
|
18,470
|
|
|
14,581
|
|
|
13,411
|
|
|||||
Other Operating (Income) Expense
|
|
|
|
|
|
|
|
|
|
||||||||||
Algeria Exceptional Profits Tax Settlement
|
—
|
|
|
—
|
|
|
—
|
|
|
33
|
|
|
(1,797
|
)
|
|||||
Operating Income (Loss)
|
(2,599
|
)
|
|
(8,809
|
)
|
|
5,403
|
|
|
3,333
|
|
|
3,727
|
|
|||||
Tronox-related Contingent Loss
|
—
|
|
|
5
|
|
|
4,360
|
|
|
850
|
|
|
(250
|
)
|
|||||
Income (Loss)
|
(2,808
|
)
|
|
(6,812
|
)
|
|
(1,563
|
)
|
|
941
|
|
|
2,445
|
|
|||||
Net Income (Loss) Attributable to Common Stockholders
|
(3,071
|
)
|
|
(6,692
|
)
|
|
(1,750
|
)
|
|
801
|
|
|
2,391
|
|
|||||
Per Common Share (amounts attributable to common stockholders)
|
|
|
|
|
|
|
|
|
|
||||||||||
Net Income (Loss)—Basic
|
$
|
(5.90
|
)
|
|
$
|
(13.18
|
)
|
|
$
|
(3.47
|
)
|
|
$
|
1.58
|
|
|
$
|
4.76
|
|
Net Income (Loss)—Diluted
|
$
|
(5.90
|
)
|
|
$
|
(13.18
|
)
|
|
$
|
(3.47
|
)
|
|
$
|
1.58
|
|
|
$
|
4.74
|
|
Dividends
|
$
|
0.20
|
|
|
$
|
1.08
|
|
|
$
|
0.99
|
|
|
$
|
0.54
|
|
|
$
|
0.36
|
|
Average Number of Common Shares Outstanding—Basic
|
522
|
|
|
508
|
|
|
506
|
|
|
502
|
|
|
500
|
|
|||||
Average Number of Common Shares Outstanding—Diluted
|
522
|
|
|
508
|
|
|
506
|
|
|
505
|
|
|
502
|
|
|||||
Cash Provided by (Used in) Operating Activities
|
3,000
|
|
|
(1,877
|
)
|
|
8,466
|
|
|
8,888
|
|
|
8,339
|
|
|||||
Capital Expenditures
|
$
|
3,314
|
|
|
$
|
5,888
|
|
|
$
|
9,256
|
|
|
$
|
8,523
|
|
|
$
|
7,311
|
|
Short-term Debt
(4)
|
$
|
42
|
|
|
$
|
32
|
|
|
$
|
—
|
|
|
$
|
500
|
|
|
$
|
—
|
|
Long-term Debt
(2)
(4)
|
15,281
|
|
|
15,636
|
|
|
15,004
|
|
|
12,984
|
|
|
13,180
|
|
|||||
Total Debt
(4)
|
$
|
15,323
|
|
|
$
|
15,668
|
|
|
$
|
15,004
|
|
|
$
|
13,484
|
|
|
$
|
13,180
|
|
Total Stockholders’ Equity
|
12,212
|
|
|
12,819
|
|
|
19,725
|
|
|
21,857
|
|
|
20,629
|
|
|||||
Total Assets
|
$
|
45,564
|
|
|
$
|
46,414
|
|
|
$
|
60,967
|
|
|
$
|
55,421
|
|
|
$
|
52,261
|
|
Annual Sales Volumes
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (MMBbls)
|
116
|
|
|
116
|
|
|
106
|
|
|
91
|
|
|
86
|
|
|||||
Natural Gas (Bcf)
|
766
|
|
|
852
|
|
|
945
|
|
|
968
|
|
|
913
|
|
|||||
Natural Gas Liquids (MMBbls)
|
46
|
|
|
47
|
|
|
44
|
|
|
33
|
|
|
30
|
|
|||||
Total (MMBOE)
(3)
|
290
|
|
|
305
|
|
|
308
|
|
|
285
|
|
|
268
|
|
|||||
Average Daily Sales Volumes
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil (MBbls/d)
|
316
|
|
|
317
|
|
|
292
|
|
|
248
|
|
|
233
|
|
|||||
Natural Gas (MMcf/d)
|
2,093
|
|
|
2,334
|
|
|
2,589
|
|
|
2,652
|
|
|
2,495
|
|
|||||
Natural Gas Liquids (MBbls/d)
|
128
|
|
|
130
|
|
|
119
|
|
|
91
|
|
|
83
|
|
|||||
Total (MBOE/d)
|
793
|
|
|
836
|
|
|
843
|
|
|
781
|
|
|
732
|
|
|||||
Proved Reserves
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil Reserves (MMBbls)
|
702
|
|
|
713
|
|
|
929
|
|
|
851
|
|
|
767
|
|
|||||
Natural-gas Reserves (Tcf)
|
4.4
|
|
|
6.0
|
|
|
8.7
|
|
|
9.2
|
|
|
8.3
|
|
|||||
Natural-gas Liquids Reserves (MMBbls)
|
283
|
|
|
340
|
|
|
479
|
|
|
407
|
|
|
405
|
|
|||||
Total Proved Reserves (MMBOE)
|
1,722
|
|
|
2,057
|
|
|
2,858
|
|
|
2,792
|
|
|
2,560
|
|
|||||
Number of Employees
|
4,500
|
|
|
5,800
|
|
|
6,100
|
|
|
5,700
|
|
|
5,200
|
|
(1)
|
Consolidated for Anadarko and its subsidiaries. Certain amounts for prior years have been reclassified to conform to the current presentation.
|
(2)
|
Includes WGP debt of $28 million at December 31, 2016. Includes WES debt of $3.1 billion at
December 31, 2016
, $2.7 billion at
December 31, 2015
, $2.4 billion at
December 31, 2014
, $1.4 billion at
December 31, 2013
, and $1.2 billion at December 31,
2012
.
|
(3)
|
Natural gas is converted to equivalent barrels at the rate of 6,000 cubic feet of gas per barrel.
|
(4)
|
As a result of adopting ASU 2015-03,
Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs
and ASU 2015-15,
Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements
, the Company reduced other current assets and short-term debt by $1 million and reduced other assets and long-term debt by $82 million in 2015, $88 million in 2014, $81 million in 2013, and $89 million in 2012. See
Note 1 - Summary of Significant Accounting Policies
in the
Notes to the Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
•
|
The Company’s oil sales volumes were flat year over year, while the Company’s 2016 capital budget (excluding WES) was reduced by nearly 50%.
|
•
|
The Company’s overall sales-volume product mix increased to
56%
liquids in
2016
compared to 53% in
2015
.
|
•
|
The Company improved its cost structure by approximately $800 million annually after 2016 through a dividend decrease and a workforce reduction program.
|
•
|
The Company closed approximately $4 billion of monetizations in 2016, including asset divestitures in the U.S. onshore, the sale of Anadarko’s interest in Springfield Pipeline LLC to WES, the sale of a portion of the Company’s common units in WGP to the public, and the Company’s conveyance of a limited-term nonparticipating royalty interest in certain of its coal and trona leases to a third party.
|
•
|
In December 2016, the Company entered into an agreement to sell its Marcellus oil and gas assets and certain related midstream assets for approximately $1.2 billion. In January 2017, the Company entered into an agreement to sell its Eagleford oil and gas assets for approximately $2.3 billion. These transactions are expected to close in the first quarter of 2017.
|
•
|
Total sales volumes in the DJ basin averaged
244
MBOE/d, representing a
9%
or
20
MBOE/d increase from 2015.
|
•
|
Total sales volumes in the Delaware basin averaged
45
MBOE/d, representing a
41%
or
13
MBOE/d increase from 2015. Oil sales volumes in the Delaware basin increased
8
MBbls/d, representing a
50%
increase from 2015.
|
•
|
The Company increased rig activity in the Delaware and DJ basins during the year, ending 2016 with nine operated rigs in the Delaware basin and five operated rigs in the DJ basin, compared to six rigs in the Delaware basin and two in the DJ basin in the first quarter of 2016.
|
•
|
In December 2016, the Company acquired oil and gas assets in the Gulf of Mexico for
$1.8 billion
net of purchase-price adjustments, expanding its operated infrastructure and substantial tie-back inventory.
|
•
|
Oil sales volumes averaged
65
MBbls/d, representing a
23%
increase from 2015, primarily due to new wells coming online in 2016 at Caesar/Tonga and K2, first oil from Heidelberg, and an increased flow rate at Lucius.
|
•
|
The TEN development project (19% nonoperated participating interest) in Ghana achieved first oil in the third quarter of 2016.
|
•
|
In 2016, the operator at the Jubilee field in Ghana announced that damage to the FPSO turret bearing had occurred. As a result, new production and offtake procedures were implemented and the partners agreed to a long-term solution to convert the FPSO to a permanently-moored facility. Interim mooring of the vessel commenced in the fourth quarter of 2016 and is expected to be completed during the first quarter of 2017. Final decisions and approvals will be sought for the long-term turret system solution in the first half of 2017. It is anticipated that a facility shutdown of up to 12 weeks may be required in the second half of 2017. The partnership is actively seeking optimization solutions to minimize the duration of any shutdown period.
|
•
|
The Company’s Algeria operations achieved the highest production rates since 2009 due to the completion of the increased water-handling project at the Ourhoud facility and obtaining approval of a new reservoir development plan for the El Merk fields allowing for higher plateau rates.
|
•
|
During the fourth quarter of 2016, the Development Plan for the initial two-train onshore LNG project in Mozambique was submitted to the Government of Mozambique.
|
•
|
The Company generated
$3.0 billion
of cash flow from operations and ended
2016
with
$3.2 billion
of cash.
|
•
|
During the second quarter of 2016, the Company used proceeds from a March 2016 public offering of Senior Notes totaling $3.0 billion due 2021, 2026, and 2046 to redeem its
$1.750 billion
Senior Notes due 2016 and to purchase and retire $1.25 billion of its Senior Notes due 2017. In the fourth quarter of 2016, Anadarko redeemed its remaining $750 million Senior Notes due 2017.
|
•
|
During the third quarter of 2016, the Company completed a public offering of
40.5 million
shares of its common stock for net proceeds of
$2.16 billion
. Net proceeds were primarily used to fund the GOM Acquisition.
|
millions except per-share amounts
|
2016
|
|
2015
|
|
2014
|
||||||
Oil, natural-gas, and NGLs sales
|
$
|
7,153
|
|
|
$
|
8,260
|
|
|
$
|
15,169
|
|
Gathering, processing, and marketing sales
|
1,294
|
|
|
1,226
|
|
|
1,206
|
|
|||
Gains (losses) on divestitures and other, net
|
(578
|
)
|
|
(788
|
)
|
|
2,095
|
|
|||
Revenues and other
|
$
|
7,869
|
|
|
$
|
8,698
|
|
|
$
|
18,470
|
|
Costs and expenses
|
10,468
|
|
|
17,507
|
|
|
13,067
|
|
|||
Other (income) expense
|
1,230
|
|
|
880
|
|
|
5,349
|
|
|||
Income tax expense (benefit)
|
(1,021
|
)
|
|
(2,877
|
)
|
|
1,617
|
|
|||
Net income (loss) attributable to common stockholders
|
$
|
(3,071
|
)
|
|
$
|
(6,692
|
)
|
|
$
|
(1,750
|
)
|
Net income (loss) per common share attributable to common stockholders—diluted
|
$
|
(5.90
|
)
|
|
$
|
(13.18
|
)
|
|
$
|
(3.47
|
)
|
Average number of common shares outstanding—diluted
|
522
|
|
|
508
|
|
|
506
|
|
millions
|
Oil
|
|
Natural
Gas
|
|
NGLs
|
|
Total
|
||||||||
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
|
)%
|
||||
|
|
|
|
|
|
|
|
||||||||
2014 sales revenues
|
$
|
9,748
|
|
|
$
|
3,849
|
|
|
$
|
1,572
|
|
|
$
|
15,169
|
|
Changes associated with prices
|
(5,189
|
)
|
|
(1,462
|
)
|
|
(871
|
)
|
|
(7,522
|
)
|
||||
Changes associated with sales volumes
|
861
|
|
|
(380
|
)
|
|
132
|
|
|
613
|
|
||||
2015 sales revenues
|
$
|
5,420
|
|
|
$
|
2,007
|
|
|
$
|
833
|
|
|
$
|
8,260
|
|
Increase/(decrease) vs. 2014
|
(44
|
)%
|
|
(48
|
)%
|
|
(47
|
)%
|
|
(46
|
)%
|
|
|
2016
|
|
Inc (Dec)
vs. 2015 |
|
2015
|
|
Inc (Dec)
vs. 2014 |
|
2014
|
|||||
Barrels of Oil Equivalent
|
|
|
|
|
|
|
|
|
|
|
|||||
(MMBOE except percentages)
|
|
|
|
|
|
|
|
|
|
|
|||||
United States
|
|
257
|
|
|
(5
|
)%
|
|
272
|
|
|
(1
|
)%
|
|
275
|
|
International
|
|
33
|
|
|
(1
|
)
|
|
33
|
|
|
(1
|
)
|
|
33
|
|
Total barrels of oil equivalent
|
|
290
|
|
|
(5
|
)
|
|
305
|
|
|
(1
|
)
|
|
308
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Barrels of Oil Equivalent per Day
|
|
|
|
|
|
|
|
|
|
|
|||||
(MBOE/d except percentages)
|
|
|
|
|
|
|
|
|
|
|
|||||
United States
|
|
704
|
|
|
(5
|
)%
|
|
745
|
|
|
(1
|
)%
|
|
751
|
|
International
|
|
89
|
|
|
(1
|
)
|
|
91
|
|
|
(1
|
)
|
|
92
|
|
Total barrels of oil equivalent per day
|
|
793
|
|
|
(5
|
)
|
|
836
|
|
|
(1
|
)
|
|
843
|
|
|
2016
|
|
Inc (Dec)
vs. 2015 |
|
2015
|
|
Inc (Dec)
vs. 2014 |
|
2014
|
||||||||
Oil sales revenues (millions)
|
$
|
4,668
|
|
|
(14
|
)%
|
|
$
|
5,420
|
|
|
(44
|
)%
|
|
$
|
9,748
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
United States
|
|
|
|
|
|
|
|
|
|
||||||||
Sales volumes—MMBbls
|
85
|
|
|
1
|
%
|
|
85
|
|
|
14
|
%
|
|
74
|
|
|||
MBbls/d
|
233
|
|
|
1
|
|
|
232
|
|
|
14
|
|
|
203
|
|
|||
Price per barrel
|
$
|
39.06
|
|
|
(13
|
)
|
|
$
|
45.00
|
|
|
(49
|
)
|
|
$
|
87.99
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
International
|
|
|
|
|
|
|
|
|
|
||||||||
Sales volumes—MMBbls
|
31
|
|
|
(2
|
)%
|
|
31
|
|
|
(4
|
)%
|
|
32
|
|
|||
MBbls/d
|
83
|
|
|
(2
|
)
|
|
85
|
|
|
(4
|
)
|
|
89
|
|
|||
Price per barrel
|
$
|
43.93
|
|
|
(15
|
)
|
|
$
|
51.68
|
|
|
(48
|
)
|
|
$
|
99.79
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Total
|
|
|
|
|
|
|
|
|
|
||||||||
Sales volumes—MMBbls
|
116
|
|
|
—
|
%
|
|
116
|
|
|
9
|
%
|
|
106
|
|
|||
MBbls/d
|
316
|
|
|
—
|
|
|
317
|
|
|
9
|
|
|
292
|
|
|||
Price per barrel
|
$
|
40.34
|
|
|
(14
|
)
|
|
$
|
46.79
|
|
|
(49
|
)
|
|
$
|
91.58
|
|
millions
|
Change in Revenues
|
|
Due to Change
in Prices
|
|
Due to Change
in Volumes
|
||||||
2016 vs. 2015
|
$
|
(752
|
)
|
|
$
|
(745
|
)
|
|
$
|
(7
|
)
|
2015 vs. 2014
|
(4,328
|
)
|
|
(5,189
|
)
|
|
861
|
|
•
|
Sales volumes for the Delaware basin increased by
8
MBbls/d primarily due to continued field development.
|
•
|
Sales volumes for the DJ basin
decrease
d by
6
MBbls/d primarily due to reduced capital activity.
|
•
|
Sales volumes decreased by
7
MBbls/d primarily due to the sale of certain EOR assets in 2015 and the sale of certain Wyoming and East Texas/Louisiana assets in 2016.
|
•
|
Sales volumes increased by 12 MBbls/d, primarily due to new wells coming online at K2 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.
|
•
|
Sales volumes for the DJ basin increased by 21 MBbls/d primarily due to continued horizontal drilling activity.
|
•
|
Sales volumes for the Delaware basin increased by 3 MBbls/d primarily due to wells brought online as a result of additional infrastructure and continued drilling.
|
•
|
Sales volumes decreased by 10 MBbls/d primarily due to the sale of certain EOR assets in 2015.
|
•
|
Sales volumes for Lucius increased by 14 MBbls/d primarily due to the achievement of first oil in the first quarter of 2015.
|
|
2016
|
|
Inc (Dec)
vs. 2015 |
|
2015
|
|
Inc (Dec)
vs. 2014 |
|
2014
|
||||||||
Natural-gas sales revenues (millions)
|
$
|
1,564
|
|
|
(22
|
)%
|
|
$
|
2,007
|
|
|
(48
|
)%
|
|
$
|
3,849
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
United States
|
|
|
|
|
|
|
|
|
|
||||||||
Sales volumes—Bcf
|
766
|
|
|
(10
|
)%
|
|
852
|
|
|
(10
|
)%
|
|
945
|
|
|||
MMcf/d
|
2,093
|
|
|
(10
|
)
|
|
2,334
|
|
|
(10
|
)
|
|
2,589
|
|
|||
Price per Mcf
|
$
|
2.04
|
|
|
(14
|
)
|
|
$
|
2.36
|
|
|
(42
|
)
|
|
$
|
4.07
|
|
millions
|
Change in Revenues
|
|
Due to Change
in Prices
|
|
Due to Change
in Volumes
|
||||||
2016 vs 2015
|
$
|
(443
|
)
|
|
$
|
(241
|
)
|
|
$
|
(202
|
)
|
2015 vs 2014
|
(1,842
|
)
|
|
(1,462
|
)
|
|
(380
|
)
|
•
|
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 certain coalbed methane properties and certain U.S. onshore properties and related midstream assets in East Texas in 2015 and the sale of certain Wyoming and East Texas/Louisiana assets in 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.
|
•
|
Sales volumes for Marcellus shale decreased by 118 MMcf/d primarily due to production modulation and third-party infrastructure downtime.
|
•
|
Sales volumes for Greater Natural Buttes decreased by 89 MMcf/d primarily due to production modulation.
|
•
|
Sales volumes for the DJ basin increased by 144 MMcf/d primarily due to continued horizontal drilling activity.
|
•
|
Sales volumes decreased by 137 MMcf/d primarily due to the sale of certain U.S. onshore properties and related midstream assets in East Texas and the sale of certain coalbed methane properties in 2015.
|
•
|
Sales volumes decreased by 60 MMcf/d primarily due to natural production decline at Independence Hub.
|
|
2016
|
|
Inc (Dec)
vs. 2015 |
|
2015
|
|
Inc (Dec)
vs. 2014 |
|
2014
|
||||||||
Natural-gas liquids sales revenues (millions)
|
$
|
921
|
|
|
11
|
%
|
|
$
|
833
|
|
|
(47
|
)%
|
|
$
|
1,572
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
United States
|
|
|
|
|
|
|
|
|
|
||||||||
Sales volumes—MMBbls
|
44
|
|
|
(1
|
)%
|
|
45
|
|
|
6
|
%
|
|
43
|
|
|||
MBbls/d
|
122
|
|
|
(1
|
)
|
|
124
|
|
|
6
|
|
|
116
|
|
|||
Price per barrel
|
$
|
19.32
|
|
|
13
|
|
|
$
|
17.03
|
|
|
(52
|
)
|
|
$
|
35.48
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
International
|
|
|
|
|
|
|
|
|
|
||||||||
Sales volumes—MMBbls
|
2
|
|
|
10
|
%
|
|
2
|
|
|
91
|
%
|
|
1
|
|
|||
MBbls/d
|
6
|
|
|
10
|
|
|
6
|
|
|
91
|
|
|
3
|
|
|||
Price per barrel
|
$
|
25.63
|
|
|
(14
|
)
|
|
$
|
29.85
|
|
|
(47
|
)
|
|
$
|
56.16
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Total
|
|
|
|
|
|
|
|
|
|
||||||||
Sales volumes—MMBbls
|
46
|
|
|
(1
|
)%
|
|
47
|
|
|
8
|
%
|
|
44
|
|
|||
MBbls/d
|
128
|
|
|
(1
|
)
|
|
130
|
|
|
8
|
|
|
119
|
|
|||
Price per barrel
|
$
|
19.64
|
|
|
12
|
|
|
$
|
17.61
|
|
|
(51
|
)
|
|
$
|
36.01
|
|
millions
|
Change in Revenues
|
|
Due to Change
in Prices
|
|
Due to Change
in Volumes
|
||||||
2016 vs. 2015
|
$
|
88
|
|
|
$
|
95
|
|
|
$
|
(7
|
)
|
2015 vs. 2014
|
(739
|
)
|
|
(871
|
)
|
|
132
|
|
millions except percentages
|
2016
|
|
Inc (Dec)
vs. 2015 |
|
2015
|
|
Inc (Dec)
vs. 2014 |
|
2014
|
||||||||
Gathering, processing, and marketing sales
|
$
|
1,294
|
|
|
6
|
%
|
|
$
|
1,226
|
|
|
2
|
%
|
|
$
|
1,206
|
|
Gathering, processing, and marketing expense
|
1,087
|
|
|
3
|
|
|
1,054
|
|
|
2
|
|
|
1,030
|
|
|||
Total gathering, processing, and marketing, net
|
$
|
207
|
|
|
20
|
|
|
$
|
172
|
|
|
(2
|
)
|
|
$
|
176
|
|
millions except percentages
|
2016
|
|
Inc (Dec)
vs. 2015 |
|
2015
|
|
Inc (Dec)
vs. 2014 |
|
2014
|
||||||||
Gains (losses) on divestitures, net
|
$
|
(757
|
)
|
|
26
|
%
|
|
$
|
(1,022
|
)
|
|
(154
|
)%
|
|
$
|
1,891
|
|
Other
|
179
|
|
|
(24
|
)
|
|
234
|
|
|
15
|
|
|
204
|
|
|||
Total gains (losses) on divestitures and other, net
|
$
|
(578
|
)
|
|
27
|
|
|
$
|
(788
|
)
|
|
(138
|
)
|
|
$
|
2,095
|
|
millions
|
2016
|
|
2015
|
|
2014
|
||||||
Oil and gas operating
|
$
|
811
|
|
|
$
|
1,014
|
|
|
$
|
1,171
|
|
Oil and gas transportation
|
1,002
|
|
|
1,117
|
|
|
1,116
|
|
|||
Exploration
|
946
|
|
|
2,644
|
|
|
1,639
|
|
|||
Gathering, processing, and marketing
|
1,087
|
|
|
1,054
|
|
|
1,030
|
|
|||
General and administrative
|
1,440
|
|
|
1,176
|
|
|
1,316
|
|
|||
DD&A
|
4,301
|
|
|
4,603
|
|
|
4,550
|
|
|||
Production, property, and other taxes
|
536
|
|
|
553
|
|
|
1,244
|
|
|||
Impairments
|
227
|
|
|
5,075
|
|
|
836
|
|
|||
Other operating expense
|
118
|
|
|
271
|
|
|
165
|
|
|||
Total
|
$
|
10,468
|
|
|
$
|
17,507
|
|
|
$
|
13,067
|
|
|
2016
|
|
Inc (Dec)
vs. 2015 |
|
2015
|
|
Inc (Dec)
vs. 2014 |
|
2014
|
||||||||
Oil and gas operating (millions)
|
$
|
811
|
|
|
(20
|
)%
|
|
$
|
1,014
|
|
|
(13
|
)%
|
|
$
|
1,171
|
|
Oil and gas operating—per BOE
|
2.79
|
|
|
(16
|
)
|
|
3.32
|
|
|
(13
|
)
|
|
3.81
|
|
|||
Oil and gas transportation (millions)
|
1,002
|
|
|
(10
|
)
|
|
1,117
|
|
|
—
|
|
|
1,116
|
|
|||
Oil and gas transportation—per BOE
|
3.46
|
|
|
(5
|
)
|
|
3.66
|
|
|
1
|
|
|
3.63
|
|
•
|
lower expenses of
$112 million
as a result of 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 $73 million as a result of divestitures
|
•
|
lower workover costs of $49 million as a result of reduced activity primarily in the U.S. onshore
|
•
|
lower surface maintenance expenses of $21 million primarily in the U.S. onshore
|
millions
|
2016
|
|
2015
|
|
2014
|
||||||
Dry hole expense
|
$
|
397
|
|
|
$
|
1,052
|
|
|
$
|
762
|
|
Impairments of unproved properties
|
216
|
|
|
1,215
|
|
|
483
|
|
|||
Geological and geophysical expense
|
121
|
|
|
168
|
|
|
168
|
|
|||
Exploration overhead and other
|
212
|
|
|
209
|
|
|
226
|
|
|||
Total exploration expense
|
$
|
946
|
|
|
$
|
2,644
|
|
|
$
|
1,639
|
|
•
|
The Company expensed suspended exploratory well costs of
$231 million
related to certain wells in the Gulf of Mexico and $92 million related to certain wells in Mozambique. See
Note 6—Suspended Exploratory Well Costs
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
•
|
The Company expensed $39 million for a well in Côte d’Ivoire that finished drilling in the third quarter of 2016 and encountered noncommercial quantities of hydrocarbons.
|
•
|
Anadarko expensed $35 million due to unsuccessful drilling activities primarily associated with Gulf of Mexico and U.S. onshore properties.
|
•
|
The Company expensed suspended exploratory well costs of $746 million in 2015, primarily related to Brazil where the Company does not expect to have substantive exploration and development activities for the foreseeable future given the current oil-price environment and other considerations.
|
•
|
The Company expensed $306 million due to unsuccessful drilling activities in 2015 primarily in Colombia and the Gulf of Mexico.
|
•
|
Anadarko expensed $762 million due to unsuccessful drilling activities in 2014 associated with wells in the Gulf of Mexico, U.S. onshore, and Mozambique.
|
•
|
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.
|
•
|
The Company recognized impairments of $302 million primarily related to lower oil prices, a reduction of reserves, and the expiration of certain leases in the Gulf of Mexico.
|
•
|
The Company recognized impairments of $50 million due to the decision not to pursue further drilling in Sierra Leone.
|
•
|
The Company recognized impairments of $38 million in 2014 as a result of changes in the Company’s drilling plans for certain U.S. onshore oil and gas properties.
|
millions except percentages
|
2016
|
|
Inc (Dec)
vs. 2015 |
|
2015
|
|
Inc (Dec)
vs. 2014 |
|
2014
|
||||||||
General and administrative
|
$
|
1,440
|
|
|
22
|
%
|
|
$
|
1,176
|
|
|
(11
|
)%
|
|
$
|
1,316
|
|
millions except percentages
|
2016
|
|
Inc (Dec)
vs. 2015 |
|
2015
|
|
Inc (Dec)
vs. 2014 |
|
2014
|
||||||||
DD&A
|
$
|
4,301
|
|
|
(7
|
)%
|
|
$
|
4,603
|
|
|
1
|
%
|
|
$
|
4,550
|
|
•
|
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
|
2016
|
|
2015
|
|
2014
|
||||||
Oil and gas exploration and production
|
|
|
|
|
|
||||||
U.S. onshore properties
|
$
|
28
|
|
|
$
|
3,684
|
|
|
$
|
545
|
|
Gulf of Mexico properties
|
27
|
|
|
349
|
|
|
276
|
|
|||
Cost-method investment
|
59
|
|
|
3
|
|
|
3
|
|
|||
Midstream
|
73
|
|
|
1,039
|
|
|
12
|
|
|||
Other
|
40
|
|
|
—
|
|
|
—
|
|
|||
Total impairments
(1)
|
$
|
227
|
|
|
$
|
5,075
|
|
|
$
|
836
|
|
(1)
|
In 2015, $3.0 billion of oil and gas exploration and production impairments and $482 million of midstream asset impairments related to Greater Natural Buttes.
|
millions
|
2016
|
|
2015
|
|
2014
|
||||||
Interest expense
|
$
|
890
|
|
|
$
|
825
|
|
|
$
|
772
|
|
Loss on early extinguishment of debt
(1)
|
155
|
|
|
—
|
|
|
—
|
|
|||
(Gains) losses on derivatives, net
(2)
|
286
|
|
|
(99
|
)
|
|
197
|
|
|||
Other (income) expense, net
|
(101
|
)
|
|
149
|
|
|
20
|
|
|||
Tronox-related contingent loss
(3)
|
—
|
|
|
5
|
|
|
4,360
|
|
|||
Total
|
$
|
1,230
|
|
|
$
|
880
|
|
|
$
|
5,349
|
|
(1)
|
See
Note 11—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.
|
(2)
|
See
Note 9—Derivative Instruments
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
(3)
|
See
Note 16—Contingencies
—Tronox Litigation
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
millions
|
2016
|
|
2015
|
|
2014
|
||||||
Current debt, long-term debt, and other
|
$
|
1,022
|
|
|
$
|
989
|
|
|
$
|
973
|
|
Capitalized interest
|
(132
|
)
|
|
(164
|
)
|
|
(201
|
)
|
|||
Total interest expense
|
$
|
890
|
|
|
$
|
825
|
|
|
$
|
772
|
|
•
|
Interest expense on debt and other
increased
by
$33 million
primarily related to WES debt issuances in 2015 and 2016 and interest expense related to the Ghana TEN capital lease commencement in the third quarter of 2016.
|
•
|
Capitalized interest decreased by
$32 million
primarily due to lower construction-in-progress balances for long-term capital projects in Brazil and the completion of the Heidelberg development, partially offset by higher construction in progress balances related to projects in Mozambique, Côte d’Ivoire, and Colombia.
|
•
|
Interest expense on debt and other increased by $16 million primarily due to higher debt outstanding during 2015, partially offset by decreased debt amortization costs for the $5.0 Billion Facility.
|
•
|
Capitalized interest decreased by $37 million primarily due to the completion of the Lucius development and lower construction-in-progress balances for long-term capital projects in Brazil, partially offset by higher construction-in-progress balances for long-term capital projects primarily in Ghana.
|
millions except percentages
|
2016
|
|
2015
|
|
2014
|
||||||
Income tax expense (benefit)
|
$
|
(1,021
|
)
|
|
$
|
(2,877
|
)
|
|
$
|
1,617
|
|
Income (loss) before income taxes
|
(3,829
|
)
|
|
(9,689
|
)
|
|
54
|
|
|||
Effective tax rate
|
27
|
%
|
|
30
|
%
|
|
2,994
|
%
|
millions
|
2016
|
|
2015
|
|
2014
|
||||||
Net cash provided by (used in) operating activities
|
$
|
3,000
|
|
|
$
|
(1,877
|
)
|
|
$
|
8,466
|
|
Net cash provided by (used in) investing activities
|
(2,762
|
)
|
|
(4,771
|
)
|
|
(6,472
|
)
|
|||
Net cash provided by (used in) financing activities
|
2,008
|
|
|
220
|
|
|
1,675
|
|
millions
|
2016
|
|
2015
|
|
2014
|
||||||
Cash Flows from Investing Activities
|
|
|
|
|
|
||||||
Additions to properties and equipment
(1)
|
$
|
3,505
|
|
|
$
|
6,067
|
|
|
$
|
9,508
|
|
Adjustments for capital expenditures
|
|
|
|
|
|
||||||
Changes in capital accruals
|
(205
|
)
|
|
(226
|
)
|
|
(237
|
)
|
|||
Other
|
14
|
|
|
47
|
|
|
(15
|
)
|
|||
Total capital expenditures
(2)
|
$
|
3,314
|
|
|
$
|
5,888
|
|
|
$
|
9,256
|
|
(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)
|
Includes WES capital expenditures of
$491 million
in
2016
, $525 million in
2015
, and $696 million in
2014
. Capital expenditures exclude the FPSO capital lease asset; see Financing Activities
—Capital Lease Obligations
below.
|
•
|
decreased development costs of $2.1 billion primarily in the U.S. onshore
|
•
|
decreased exploration costs of $432 million primarily in the U.S. onshore, Colombia, and Mozambique, partially offset by increased exploration costs of $251 million in the Gulf of Mexico and Côte d’Ivoire
|
•
|
decreased gathering, processing, and other capital costs of $284 million primarily in the U.S. onshore and Gulf of Mexico
|
•
|
decreased development costs of $2.1 billion primarily in the U.S. onshore
|
•
|
lower exploration costs of $710 million primarily in the U.S. onshore and Gulf of Mexico
|
•
|
lower gathering, processing, and other capital costs of $498 million primarily in the U.S. onshore
|
millions except percentages
|
2016
|
|
2015
|
||||
Anadarko
|
$
|
12,204
|
|
|
$
|
12,977
|
|
WES
|
3,091
|
|
|
2,691
|
|
||
WGP
|
28
|
|
|
—
|
|
||
Total debt
|
$
|
15,323
|
|
|
$
|
15,668
|
|
Total equity
|
15,497
|
|
|
15,457
|
|
||
Debt to total capitalization ratio
|
49.7
|
%
|
|
50.3
|
%
|
millions
|
2016
|
|
2015
|
|
2014
|
|
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
|
|||
|
—
|
|
|
—
|
|
|
625
|
|
|
3.450% Senior Notes due 2024
|
|||
|
—
|
|
|
—
|
|
|
625
|
|
|
4.500% Senior Notes due 2044
|
|||
|
—
|
|
|
—
|
|
|
100
|
|
|
WES 2.600% Senior Notes due 2018
|
|||
|
200
|
|
|
—
|
|
|
400
|
|
|
WES 5.450% Senior Notes due 2044
|
|||
Borrowings
|
1,750
|
|
|
1,800
|
|
|
—
|
|
|
364-Day Facility
|
|||
|
—
|
|
|
1,500
|
|
|
—
|
|
|
$5.0 Billion Facility
|
|||
|
600
|
|
|
400
|
|
|
1,160
|
|
|
WES RCF
|
|||
|
28
|
|
|
—
|
|
|
—
|
|
|
WGP RCF
|
|||
|
—
|
|
|
250
|
|
|
—
|
|
|
Commercial paper notes, net
(2)
|
|||
Repayments
|
(1,750
|
)
|
|
—
|
|
|
—
|
|
|
5.950% Senior Notes due 2016
|
|||
|
(2,000
|
)
|
|
—
|
|
|
—
|
|
|
6.375% Senior Notes due 2017
|
|||
|
—
|
|
|
—
|
|
|
(500
|
)
|
|
7.625% Senior Notes due 2014
|
|||
|
—
|
|
|
—
|
|
|
(275
|
)
|
|
5.750% Senior Notes due 2014
|
|||
|
(1,750
|
)
|
|
(1,800
|
)
|
|
—
|
|
|
364-Day Facility
|
|||
|
—
|
|
|
(1,500
|
)
|
|
—
|
|
|
$5.0 Billion Facility
|
|||
|
(900
|
)
|
|
(610
|
)
|
|
(650
|
)
|
|
WES RCF
|
|||
|
(250
|
)
|
|
—
|
|
|
—
|
|
|
Commercial paper notes, net
|
|||
|
(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
|
2016
|
|
2015
|
|
2014
|
||||||
WES distributions to unitholders (excluding Anadarko and WGP)
(1)
|
$
|
258
|
|
|
$
|
231
|
|
|
$
|
175
|
|
WES distributions to Series A Preferred unit holders
(2)
|
31
|
|
|
—
|
|
|
—
|
|
|||
WGP distributions to unitholders (excluding Anadarko)
(3)
|
59
|
|
|
37
|
|
|
24
|
|
(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 $0.860 per common unit for the fourth quarter of
2016
(paid in February
2017
).
|
(2)
|
WES has made distributions of $0.68 per unit, prorated based on issuance date, to its Series A Preferred unitholders quarterly since the unit issuances in March and April 2016.
|
(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 $0.46250 per unit for the fourth quarter of
2016
(to be paid in February
2017
).
|
|
|
|
Obligations by Period
|
||||||||||||||||||
millions
|
Note Reference
(1)
|
|
2017
|
|
2018-2019
|
|
2020-2021
|
|
2022 and beyond
|
|
Total
|
||||||||||
Total debt
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Principal—total borrowings
(2)
|
|
$
|
34
|
|
|
$
|
1,409
|
|
|
$
|
1,300
|
|
|
$
|
13,963
|
|
|
$
|
16,706
|
|
|
Interest on borrowings
|
|
|
862
|
|
|
1,667
|
|
|
1,506
|
|
|
9,332
|
|
|
13,367
|
|
|||||
Capital lease obligation and interest
|
|
|
57
|
|
|
84
|
|
|
85
|
|
|
391
|
|
|
617
|
|
|||||
Investee entities’ debt and interest
(3)
|
|
61
|
|
|
167
|
|
|
196
|
|
|
5,060
|
|
|
5,484
|
|
||||||
Operating leases
|
|
673
|
|
|
714
|
|
|
110
|
|
|
23
|
|
|
1,520
|
|
||||||
Oil and gas activities
(4)
|
|
478
|
|
|
542
|
|
|
178
|
|
|
125
|
|
|
1,323
|
|
||||||
Midstream and marketing activities
|
|
850
|
|
|
1,666
|
|
|
1,433
|
|
|
1,099
|
|
|
5,048
|
|
||||||
AROs
|
|
137
|
|
|
234
|
|
|
520
|
|
|
2,040
|
|
|
2,931
|
|
||||||
Derivative liabilities
(5)
|
|
159
|
|
|
803
|
|
|
438
|
|
|
—
|
|
|
1,400
|
|
||||||
Uncertain tax positions
|
|
70
|
|
|
85
|
|
|
—
|
|
|
1,301
|
|
|
1,456
|
|
||||||
Other
(6)
|
|
|
19
|
|
|
166
|
|
|
71
|
|
|
96
|
|
|
352
|
|
|||||
Total
(7)
|
|
|
$
|
3,400
|
|
|
$
|
7,537
|
|
|
$
|
5,837
|
|
|
$
|
33,430
|
|
|
$
|
50,204
|
|
(1)
|
For additional information, see the
Notes to the 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
2021
. 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
$883 million
in October
2017
(the next potential put date).
|
(3)
|
The obligations and related investments are presented net on the Company’s Consolidated Balance Sheets in other long-term liabilities-other for all periods presented. Future interest payments are estimated using the relevant forward LIBOR rate curve. Further, the above table does not reflect the preferred return that Anadarko receives on its investment in these entities.
|
(4)
|
The table includes long-term drilling and work-related commitments of
$1.3 billion
, comprised of approximately
$1.1 billion
related to the United States and
$180 million
related to international locations. These amounts are presented on an undiscounted basis 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)
|
Includes environmental liabilities; for additional information, see
Note 16—Contingencies
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
(7)
|
This table does not include 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 16—Contingencies
,
Note 18—Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans
, and
Note 14—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 17, 2017
|
/s/ KPMG LLP
|
|
Houston, Texas
|
February 17, 2017
|
/s/ KPMG LLP
|
|
Houston, Texas
|
February 17, 2017
|
|
Years Ended December 31,
|
||||||||||
millions except per-share amounts
|
2016
|
|
2015
|
|
2014
|
||||||
Revenues and Other
|
|
|
|
|
|
||||||
Oil sales
|
$
|
4,668
|
|
|
$
|
5,420
|
|
|
$
|
9,748
|
|
Natural-gas sales
|
1,564
|
|
|
2,007
|
|
|
3,849
|
|
|||
Natural-gas liquids sales
|
921
|
|
|
833
|
|
|
1,572
|
|
|||
Gathering, processing, and marketing sales
|
1,294
|
|
|
1,226
|
|
|
1,206
|
|
|||
Gains (losses) on divestitures and other, net
|
(578
|
)
|
|
(788
|
)
|
|
2,095
|
|
|||
Total
|
7,869
|
|
|
8,698
|
|
|
18,470
|
|
|||
Costs and Expenses
|
|
|
|
|
|
||||||
Oil and gas operating
|
811
|
|
|
1,014
|
|
|
1,171
|
|
|||
Oil and gas transportation
|
1,002
|
|
|
1,117
|
|
|
1,116
|
|
|||
Exploration
|
946
|
|
|
2,644
|
|
|
1,639
|
|
|||
Gathering, processing, and marketing
|
1,087
|
|
|
1,054
|
|
|
1,030
|
|
|||
General and administrative
|
1,440
|
|
|
1,176
|
|
|
1,316
|
|
|||
Depreciation, depletion, and amortization
|
4,301
|
|
|
4,603
|
|
|
4,550
|
|
|||
Production, property, and other taxes
|
536
|
|
|
553
|
|
|
1,244
|
|
|||
Impairments
|
227
|
|
|
5,075
|
|
|
836
|
|
|||
Other operating expense
|
118
|
|
|
271
|
|
|
165
|
|
|||
Total
|
10,468
|
|
|
17,507
|
|
|
13,067
|
|
|||
Operating Income (Loss)
|
(2,599
|
)
|
|
(8,809
|
)
|
|
5,403
|
|
|||
Other (Income) Expense
|
|
|
|
|
|
||||||
Interest expense
|
890
|
|
|
825
|
|
|
772
|
|
|||
Loss on early extinguishment of debt
|
155
|
|
|
—
|
|
|
—
|
|
|||
(Gains) losses on derivatives, net
|
286
|
|
|
(99
|
)
|
|
197
|
|
|||
Other (income) expense, net
|
(101
|
)
|
|
149
|
|
|
20
|
|
|||
Tronox-related contingent loss
|
—
|
|
|
5
|
|
|
4,360
|
|
|||
Total
|
1,230
|
|
|
880
|
|
|
5,349
|
|
|||
Income (Loss) Before Income Taxes
|
(3,829
|
)
|
|
(9,689
|
)
|
|
54
|
|
|||
Income tax expense (benefit)
|
(1,021
|
)
|
|
(2,877
|
)
|
|
1,617
|
|
|||
Net Income (Loss)
|
(2,808
|
)
|
|
(6,812
|
)
|
|
(1,563
|
)
|
|||
Net income (loss) attributable to noncontrolling interests
|
263
|
|
|
(120
|
)
|
|
187
|
|
|||
Net Income (Loss) Attributable to Common Stockholders
|
$
|
(3,071
|
)
|
|
$
|
(6,692
|
)
|
|
$
|
(1,750
|
)
|
|
|
|
|
|
|
||||||
Per Common Share
|
|
|
|
|
|
||||||
Net income (loss) attributable to common stockholders—basic
|
$
|
(5.90
|
)
|
|
$
|
(13.18
|
)
|
|
$
|
(3.47
|
)
|
Net income (loss) attributable to common stockholders—diluted
|
$
|
(5.90
|
)
|
|
$
|
(13.18
|
)
|
|
$
|
(3.47
|
)
|
Average Number of Common Shares Outstanding—Basic
|
522
|
|
|
508
|
|
|
506
|
|
|||
Average Number of Common Shares Outstanding—Diluted
|
522
|
|
|
508
|
|
|
506
|
|
|||
Dividends (per Common Share)
|
$
|
0.20
|
|
|
$
|
1.08
|
|
|
$
|
0.99
|
|
|
Years Ended December 31,
|
||||||||||
millions
|
2016
|
|
2015
|
|
2014
|
||||||
Net Income (Loss)
|
$
|
(2,808
|
)
|
|
$
|
(6,812
|
)
|
|
$
|
(1,563
|
)
|
Other Comprehensive Income (Loss)
|
|
|
|
|
|
||||||
Adjustments for derivative instruments
|
|
|
|
|
|
||||||
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net
|
8
|
|
|
10
|
|
|
9
|
|
|||
Income taxes on reclassification of previously deferred derivative losses to (gains) losses on derivatives, net
|
(3
|
)
|
|
(4
|
)
|
|
(3
|
)
|
|||
Total adjustments for derivative instruments, net of taxes
|
5
|
|
|
6
|
|
|
6
|
|
|||
Adjustments for pension and other postretirement plans
|
|
|
|
|
|
||||||
Net gain (loss) incurred during period
|
(175
|
)
|
|
49
|
|
|
(405
|
)
|
|||
Income taxes on net gain (loss) incurred during period
|
68
|
|
|
(18
|
)
|
|
149
|
|
|||
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
|
188
|
|
|
63
|
|
|
27
|
|
|||
Income taxes on amortization of net actuarial (gain) loss to general and administrative expense
|
(73
|
)
|
|
(20
|
)
|
|
(9
|
)
|
|||
Amortization of net prior service (credit) cost to general and administrative expense
|
(34
|
)
|
|
(4
|
)
|
|
—
|
|
|||
Income taxes on amortization of net prior service (credit) cost to general and administrative expense
|
13
|
|
|
2
|
|
|
—
|
|
|||
Total adjustments for pension and other postretirement plans, net of taxes
|
(13
|
)
|
|
128
|
|
|
(238
|
)
|
|||
Total
|
(8
|
)
|
|
134
|
|
|
(232
|
)
|
|||
Comprehensive Income (Loss)
|
(2,816
|
)
|
|
(6,678
|
)
|
|
(1,795
|
)
|
|||
Comprehensive income (loss) attributable to noncontrolling interests
|
263
|
|
|
(120
|
)
|
|
187
|
|
|||
Comprehensive Income (Loss) Attributable to Common Stockholders
|
$
|
(3,079
|
)
|
|
$
|
(6,558
|
)
|
|
$
|
(1,982
|
)
|
|
December 31,
|
||||||
millions
|
2016
|
|
2015
|
||||
ASSETS
|
|
|
|
||||
Current Assets
|
|
|
|
||||
Cash and cash equivalents ($359 and $100 related to VIEs)
|
$
|
3,184
|
|
|
$
|
939
|
|
Accounts receivable (net of allowance of $14 and $11)
|
|
|
|
||||
Customers ($70 and $81 related to VIEs)
|
1,007
|
|
|
652
|
|
||
Others ($80 and $84 related to VIEs)
|
721
|
|
|
1,817
|
|
||
Other current assets
|
354
|
|
|
573
|
|
||
Total
|
5,266
|
|
|
3,981
|
|
||
Properties and Equipment
|
|
|
|
||||
Cost
|
69,013
|
|
|
70,683
|
|
||
Less accumulated depreciation, depletion, and amortization
|
36,845
|
|
|
36,932
|
|
||
Net properties and equipment ($5,050 and $4,859 related to VIEs)
|
32,168
|
|
|
33,751
|
|
||
Other Assets
($609 and $644 related to VIEs)
|
2,226
|
|
|
2,268
|
|
||
Goodwill and Other Intangible Assets
($1,221 and $1,220 related to VIEs)
|
5,904
|
|
|
6,331
|
|
||
Total Assets
|
$
|
45,564
|
|
|
$
|
46,331
|
|
|
|
|
|
||||
LIABILITIES AND EQUITY
|
|
|
|
||||
Current Liabilities
|
|
|
|
||||
Accounts payable ($239 and $179 related to VIEs)
|
$
|
2,288
|
|
|
$
|
2,850
|
|
Accrued expenses
|
386
|
|
|
424
|
|
||
Interest payable
|
244
|
|
|
247
|
|
||
Production, property, and other taxes payable ($24 and $18 related to VIEs)
|
239
|
|
|
318
|
|
||
Current asset retirement obligations
|
129
|
|
|
309
|
|
||
Short-term debt
|
42
|
|
|
32
|
|
||
Total
|
3,328
|
|
|
4,180
|
|
||
Long-term Debt
|
15,281
|
|
|
15,636
|
|
||
Other Long-term Liabilities
|
|
|
|
||||
Deferred income taxes
|
4,324
|
|
|
5,400
|
|
||
Asset retirement obligations ($140 and $127 related to VIEs)
|
2,802
|
|
|
1,750
|
|
||
Other
|
4,332
|
|
|
3,908
|
|
||
Total
|
11,458
|
|
|
11,058
|
|
||
|
|
|
|
||||
Equity
|
|
|
|
||||
Stockholders’ equity
|
|
|
|
||||
Common stock, par value $0.10 per share
(1.0 billion shares authorized, 572.0 million and 528.3 million shares issued) |
57
|
|
|
52
|
|
||
Paid-in capital
|
11,875
|
|
|
9,265
|
|
||
Retained earnings
|
1,704
|
|
|
4,880
|
|
||
Treasury stock (20.8 million and 20.0 million shares)
|
(1,033
|
)
|
|
(995
|
)
|
||
Accumulated other comprehensive income (loss)
|
(391
|
)
|
|
(383
|
)
|
||
Total Stockholders’ Equity
|
12,212
|
|
|
12,819
|
|
||
Noncontrolling interests
|
3,285
|
|
|
2,638
|
|
||
Total Equity
|
15,497
|
|
|
15,457
|
|
||
Total Liabilities and Equity
|
$
|
45,564
|
|
|
$
|
46,331
|
|
|
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, 2013
|
$
|
52
|
|
|
$
|
8,629
|
|
|
$
|
14,356
|
|
|
$
|
(895
|
)
|
|
$
|
(285
|
)
|
|
$
|
1,793
|
|
|
$
|
23,650
|
|
Net income (loss)
|
—
|
|
|
—
|
|
|
(1,750
|
)
|
|
—
|
|
|
—
|
|
|
187
|
|
|
(1,563
|
)
|
|||||||
Common stock issued
|
—
|
|
|
286
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
286
|
|
|||||||
Dividends—common stock
|
—
|
|
|
—
|
|
|
(505
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(505
|
)
|
|||||||
Repurchase of common stock
|
—
|
|
|
—
|
|
|
—
|
|
|
(45
|
)
|
|
—
|
|
|
—
|
|
|
(45
|
)
|
|||||||
Subsidiary equity transactions
|
—
|
|
|
90
|
|
|
24
|
|
|
—
|
|
|
—
|
|
|
829
|
|
|
943
|
|
|||||||
Distributions to noncontrolling interest owners
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(216
|
)
|
|
(216
|
)
|
|||||||
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6
|
|
|
—
|
|
|
6
|
|
|||||||
Adjustments for pension and other postretirement plans
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(238
|
)
|
|
—
|
|
|
(238
|
)
|
|||||||
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
|
—
|
|
|
209
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
209
|
|
|||||||
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
|
|
|
2,347
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,352
|
|
|||||||
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
|
|
|
Years Ended December 31,
|
||||||||||
millions
|
2016
|
|
2015
|
|
2014
|
||||||
Cash Flows from Operating Activities
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
(2,808
|
)
|
|
$
|
(6,812
|
)
|
|
$
|
(1,563
|
)
|
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
|
|
|
|
|
|
||||||
Depreciation, depletion, and amortization
|
4,301
|
|
|
4,603
|
|
|
4,550
|
|
|||
Deferred income taxes
|
(1,238
|
)
|
|
(3,152
|
)
|
|
(105
|
)
|
|||
Dry hole expense and impairments of unproved properties
|
613
|
|
|
2,267
|
|
|
1,245
|
|
|||
Impairments
|
227
|
|
|
5,075
|
|
|
836
|
|
|||
(Gains) losses on divestitures, net
|
757
|
|
|
1,022
|
|
|
(1,891
|
)
|
|||
Loss on early extinguishment of debt
|
155
|
|
|
—
|
|
|
—
|
|
|||
Total (gains) losses on derivatives, net
|
292
|
|
|
(100
|
)
|
|
207
|
|
|||
Operating portion of net cash received (paid) in settlement of derivative instruments
|
267
|
|
|
335
|
|
|
371
|
|
|||
Other
|
342
|
|
|
320
|
|
|
327
|
|
|||
Changes in assets and liabilities
|
|
|
|
|
|
||||||
Tronox-related contingent liability
|
—
|
|
|
(5,210
|
)
|
|
4,360
|
|
|||
(Increase) decrease in accounts receivable
|
677
|
|
|
(2
|
)
|
|
103
|
|
|||
Increase (decrease) in accounts payable and accrued expenses
|
(669
|
)
|
|
(995
|
)
|
|
97
|
|
|||
Other items, net
|
84
|
|
|
772
|
|
|
(71
|
)
|
|||
Net cash provided by (used in) operating activities
|
3,000
|
|
|
(1,877
|
)
|
|
8,466
|
|
|||
Cash Flows from Investing Activities
|
|
|
|
|
|
||||||
Additions to properties and equipment
|
(3,505
|
)
|
|
(6,067
|
)
|
|
(9,508
|
)
|
|||
Acquisition of businesses
|
(1,740
|
)
|
|
(3
|
)
|
|
(1,527
|
)
|
|||
Divestitures of properties and equipment and other assets
|
2,356
|
|
|
1,415
|
|
|
4,968
|
|
|||
Other, net
|
127
|
|
|
(116
|
)
|
|
(405
|
)
|
|||
Net cash provided by (used in) investing activities
|
(2,762
|
)
|
|
(4,771
|
)
|
|
(6,472
|
)
|
|||
Cash Flows from Financing Activities
|
|
|
|
|
|
||||||
Borrowings, net of issuance costs
|
6,042
|
|
|
4,632
|
|
|
2,879
|
|
|||
Repayments of debt
|
(6,832
|
)
|
|
(4,033
|
)
|
|
(1,425
|
)
|
|||
Financing portion of net cash received (paid) for derivative instruments
|
(333
|
)
|
|
(35
|
)
|
|
(222
|
)
|
|||
Increase (decrease) in outstanding checks
|
(103
|
)
|
|
(23
|
)
|
|
62
|
|
|||
Dividends paid
|
(105
|
)
|
|
(553
|
)
|
|
(505
|
)
|
|||
Repurchase of common stock
|
(38
|
)
|
|
(55
|
)
|
|
(45
|
)
|
|||
Issuance of common stock, including tax benefit on share-based compensation awards
|
2,188
|
|
|
34
|
|
|
121
|
|
|||
Sale of subsidiary units
|
1,163
|
|
|
187
|
|
|
1,026
|
|
|||
Issuance of tangible equity units — equity component
|
—
|
|
|
348
|
|
|
—
|
|
|||
Distributions to noncontrolling interest owners
|
(362
|
)
|
|
(282
|
)
|
|
(216
|
)
|
|||
Proceeds from conveyance of future hard minerals royalty revenues,
net of transaction costs
|
413
|
|
|
—
|
|
|
—
|
|
|||
Payments of future hard minerals royalty revenues conveyed
|
(25
|
)
|
|
—
|
|
|
—
|
|
|||
Net cash provided by (used in) financing activities
|
2,008
|
|
|
220
|
|
|
1,675
|
|
|||
Effect of Exchange Rate Changes on Cash
|
(1
|
)
|
|
(2
|
)
|
|
2
|
|
|||
Net Increase (Decrease) in Cash and Cash Equivalents
|
2,245
|
|
|
(6,430
|
)
|
|
3,671
|
|
|||
Cash and Cash Equivalents at Beginning of Period
|
939
|
|
|
7,369
|
|
|
3,698
|
|
|||
Cash and Cash Equivalents at End of Period
|
$
|
3,184
|
|
|
$
|
939
|
|
|
$
|
7,369
|
|
millions
|
2016
|
|
2015
|
||||
Oil
|
$
|
169
|
|
|
$
|
116
|
|
Natural gas
|
38
|
|
|
36
|
|
||
NGLs
|
106
|
|
|
64
|
|
||
Total inventories
|
$
|
313
|
|
|
$
|
216
|
|
millions
|
|
|
||
Current assets
|
|
$
|
8
|
|
Properties and equipment
|
|
2,471
|
|
|
Other assets
|
|
145
|
|
|
AROs
|
|
(813
|
)
|
|
Net assets acquired
|
|
$
|
1,811
|
|
Accounts receivable
|
|
91
|
|
|
Accounts payable
|
|
(5
|
)
|
|
Other long-term liabilities
|
|
(98
|
)
|
|
Cash paid at closing
|
|
$
|
1,799
|
|
millions
|
2016
|
|
2015
|
||||
Revenues
|
$
|
8,849
|
|
|
$
|
9,786
|
|
Net income (loss)
|
(2,623
|
)
|
|
(6,560
|
)
|
millions
|
2016
|
|
2015
|
|
2014
|
||||||
Proceeds received, net of closing adjustments
|
$
|
2,356
|
|
|
$
|
1,415
|
|
|
$
|
4,968
|
|
Gains (losses) on divestitures, net
(1)
|
(757
|
)
|
|
(1,022
|
)
|
|
1,891
|
|
(1)
|
Includes goodwill allocated to divestitures of
$397 million
in 2016,
$184 million
in 2015, and
$152 million
in 2014.
|
•
|
certain East Texas/Louisiana assets in the oil and gas exploration and production and midstream reporting segments for net proceeds of
$1.0 billion
and a net loss of
$439 million
|
•
|
certain Kansas assets in the oil and gas exploration and production and midstream reporting segments for net proceeds of
$159 million
and a loss of
$4 million
|
•
|
certain East Texas assets in the oil and gas exploration and production and midstream reporting segments for net proceeds of
$89 million
and a loss of
$64 million
|
•
|
certain West Texas assets in the oil and gas exploration and production and midstream reporting segments for net proceeds of
$221 million
and a loss of
$52 million
|
•
|
certain Wyoming assets in the oil and gas exploration and production reporting segment for net proceeds of
$588 million
and a loss of
$58 million
|
•
|
certain coalbed methane assets in the oil and gas exploration and production and midstream reporting segments for net proceeds of
$154 million
and a loss of
$538 million
|
•
|
certain assets in the oil and gas exploration and production and midstream reporting segments in East Texas for net proceeds of
$425 million
and a loss of
$110 million
|
•
|
certain EOR assets in the oil and gas exploration and production reporting segment for net proceeds of
$675 million
and a loss of
$350 million
, in addition to the loss recognized in 2014 when the asset was originally held for sale as discussed below
|
•
|
a
10%
working interest in Offshore Area 1 in Mozambique for
$2.64 billion
and a gain of
$1.5 billion
|
•
|
a Chinese subsidiary for
$1.075 billion
and a gain of
$510 million
|
•
|
interest in the nonoperated Vito deepwater development, along with several surrounding exploration blocks in the Gulf of Mexico, for
$500 million
and a gain of
$237 million
|
•
|
interest in the Pinedale/Jonah assets in Wyoming for
$581 million
|
millions
|
2016
|
|
2015
|
||||
Oil and gas exploration and production
(1)
|
$
|
57,581
|
|
|
$
|
59,389
|
|
Midstream
|
8,613
|
|
|
8,458
|
|
||
Other
|
2,819
|
|
|
2,836
|
|
||
Gross properties and equipment
|
$
|
69,013
|
|
|
$
|
70,683
|
|
Less accumulated DD&A
|
36,845
|
|
|
36,932
|
|
||
Net properties and equipment
|
$
|
32,168
|
|
|
$
|
33,751
|
|
(1)
|
Includes costs associated with unproved properties of
$4.1 billion
at
December 31, 2016
, and
$3.5 billion
at
December 31, 2015
.
|
|
2016
|
|
2015
|
|
2014
|
||||||||||||||||||
millions
|
Impairment
|
|
Fair Value
(1)
|
|
Impairment
|
|
Fair Value
(1)
|
|
Impairment
|
|
Fair Value
(1)
|
||||||||||||
Oil and gas exploration and production
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
U.S. onshore properties
|
$
|
28
|
|
|
$
|
617
|
|
|
$
|
3,684
|
|
|
$
|
1,253
|
|
|
$
|
545
|
|
|
$
|
552
|
|
Gulf of Mexico properties
|
27
|
|
|
61
|
|
|
349
|
|
|
65
|
|
|
276
|
|
|
223
|
|
||||||
Cost-method investment
(2)
|
59
|
|
|
—
|
|
|
3
|
|
|
59
|
|
|
3
|
|
|
62
|
|
||||||
Midstream
|
73
|
|
|
32
|
|
|
1,039
|
|
|
212
|
|
|
12
|
|
|
—
|
|
||||||
Other
|
40
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total impairments
|
$
|
227
|
|
|
$
|
710
|
|
|
$
|
5,075
|
|
|
$
|
1,589
|
|
|
$
|
836
|
|
|
$
|
837
|
|
(1)
|
Measured as of the impairment date using the income approach and Level 3 inputs.
|
(2)
|
The after-tax net investment fair value was
$32 million
at December 31, 2015 and 2014.
|
millions
|
2016
|
|
2015
|
|
2014
|
||||||
Balance at January 1
|
$
|
1,124
|
|
|
$
|
1,522
|
|
|
$
|
2,232
|
|
Additions pending the determination of proved reserves
|
490
|
|
|
461
|
|
|
421
|
|
|||
Divestitures and other
(1)
|
(11
|
)
|
|
(33
|
)
|
|
(913
|
)
|
|||
Reclassifications to proved properties
|
(50
|
)
|
|
(104
|
)
|
|
(100
|
)
|
|||
Charges to exploration expense
(2) (3) (4)
|
(323
|
)
|
|
(722
|
)
|
|
(118
|
)
|
|||
Balance at December 31
|
$
|
1,230
|
|
|
$
|
1,124
|
|
|
$
|
1,522
|
|
(1)
|
Includes
$(744) million
during 2014 related to the Company’s sale of a
10%
working interest in Offshore Area 1 in Mozambique.
|
(2)
|
Includes
$(565) million
during 2015 related to Brazil. The Company does not expect to have substantive exploration and development activities in Brazil in the foreseeable future.
|
(3)
|
Includes
$(92) million
during 2016 related to 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.
|
(4)
|
Includes
$(231) million
during 2016 for the Gulf of Mexico primarily related to the Yeti project, as the Company does 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, if a final investment decision is reached.
|
millions except projects
|
Number of Projects
|
|
Total
|
|
2015
|
|
2014
|
|
2013 and
prior |
||||||||
U.S. Onshore
|
15
|
|
$
|
58
|
|
|
$
|
12
|
|
|
$
|
25
|
|
|
$
|
21
|
|
U.S. Offshore
|
3
|
|
296
|
|
|
86
|
|
|
13
|
|
|
197
|
|
||||
International
|
5
|
|
416
|
|
|
184
|
|
|
49
|
|
|
183
|
|
||||
|
23
|
|
$
|
770
|
|
|
$
|
282
|
|
|
$
|
87
|
|
|
$
|
401
|
|
millions
|
2016
|
|
2015
|
||||
Gross carrying amount
|
$
|
1,013
|
|
|
$
|
1,013
|
|
Accumulated amortization
|
(109
|
)
|
|
(77
|
)
|
||
Net carrying amount
|
$
|
904
|
|
|
$
|
936
|
|
Amortization expense
|
$
|
32
|
|
|
$
|
33
|
|
|
|
2017 Settlement
|
|
2018 Settlement
|
||||
Oil
|
|
|
|
|
||||
Three-Way Collars (MBbls/d)
|
|
91
|
|
|
—
|
|
||
Average price per barrel
|
|
|
|
|
||||
Ceiling sold price (call)
|
|
$
|
59.80
|
|
|
$
|
—
|
|
Floor purchased price (put)
|
|
$
|
50.00
|
|
|
$
|
—
|
|
Floor sold price (put)
|
|
$
|
40.00
|
|
|
$
|
—
|
|
Natural Gas
|
|
|
|
|
||||
Three-Way Collars (thousand MMBtu/d)
|
|
682
|
|
|
250
|
|
||
Average price per MMBtu
|
|
|
|
|
||||
Ceiling sold price (call)
|
|
$
|
3.60
|
|
|
$
|
3.54
|
|
Floor purchased price (put)
|
|
$
|
2.75
|
|
|
$
|
2.75
|
|
Floor sold price (put)
|
|
$
|
2.00
|
|
|
$
|
2.00
|
|
Fixed-Price Contracts (thousand MMBtu/d)
|
|
37
|
|
|
—
|
|
||
Average price per MMBtu
|
|
$
|
3.23
|
|
|
$
|
—
|
|
NGLs
|
|
|
|
|
||||
Fixed-Price Contracts (MBbls/d)
|
|
2
|
|
|
—
|
|
||
Average price per barrel
|
|
$
|
15.84
|
|
|
$
|
—
|
|
millions except percentages
|
|
|
|
Mandatory
|
|
Weighted-Average
|
|||
Notional Principal Amount
|
|
Reference Period
|
|
Termination Date
|
|
Interest Rate
|
|||
$
|
500
|
|
|
|
September 2016 – 2046
|
|
September 2018
|
|
6.559%
|
$
|
300
|
|
|
|
September 2016 – 2046
|
|
September 2020
|
|
6.509%
|
$
|
450
|
|
|
|
September 2017 – 2047
|
|
September 2018
|
|
6.445%
|
$
|
100
|
|
|
|
September 2017 – 2047
|
|
September 2020
|
|
6.891%
|
$
|
250
|
|
|
|
September 2017 – 2047
|
|
September 2021
|
|
6.570%
|
millions
|
|
Gross
Derivative Assets
|
|
Gross
Derivative Liabilities
|
||||||||||||
Balance Sheet Classification
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Commodity derivatives
|
|
|
|
|
|
|
|
|
||||||||
Other current assets
|
|
$
|
10
|
|
|
$
|
462
|
|
|
$
|
(3
|
)
|
|
$
|
(177
|
)
|
Other assets
|
|
9
|
|
|
8
|
|
|
—
|
|
|
—
|
|
||||
Accrued expenses
|
|
66
|
|
|
—
|
|
|
(201
|
)
|
|
(3
|
)
|
||||
Other liabilities
|
|
—
|
|
|
—
|
|
|
(12
|
)
|
|
—
|
|
||||
|
|
85
|
|
|
470
|
|
|
(216
|
)
|
|
(180
|
)
|
||||
Interest-rate derivatives
|
|
|
|
|
|
|
|
|
||||||||
Other current assets
|
|
8
|
|
|
2
|
|
|
—
|
|
|
—
|
|
||||
Other assets
|
|
23
|
|
|
54
|
|
|
—
|
|
|
—
|
|
||||
Accrued expenses
|
|
—
|
|
|
—
|
|
|
(48
|
)
|
|
(54
|
)
|
||||
Other liabilities
|
|
—
|
|
|
—
|
|
|
(1,328
|
)
|
|
(1,488
|
)
|
||||
|
|
31
|
|
|
56
|
|
|
(1,376
|
)
|
|
(1,542
|
)
|
||||
Total derivatives
|
|
$
|
116
|
|
|
$
|
526
|
|
|
$
|
(1,592
|
)
|
|
$
|
(1,722
|
)
|
millions
|
|
|
|
|
|
|
||||||
Classification of (Gain) Loss Recognized
|
|
2016
|
|
2015
|
|
2014
|
||||||
Commodity derivatives
|
|
|
|
|
|
|
||||||
Gathering, processing, and marketing sales
(1)
|
|
$
|
6
|
|
|
$
|
(1
|
)
|
|
$
|
10
|
|
(Gains) losses on derivatives, net
|
|
147
|
|
|
(367
|
)
|
|
(589
|
)
|
|||
Interest-rate derivatives
|
|
|
|
|
|
|
||||||
(Gains) losses on derivatives, net
|
|
139
|
|
|
268
|
|
|
786
|
|
|||
Total (gains) losses on derivatives, net
|
|
$
|
292
|
|
|
$
|
(100
|
)
|
|
$
|
207
|
|
(1)
|
Represents the effect of Marketing and Trading Derivative Activities.
|
millions
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Netting
(1)
|
|
Collateral
|
|
Total
|
||||||||||||
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
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Assets
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity derivatives
|
$
|
10
|
|
|
$
|
460
|
|
|
$
|
—
|
|
|
$
|
(178
|
)
|
|
$
|
(8
|
)
|
|
$
|
284
|
|
Interest-rate derivatives
|
—
|
|
|
56
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
56
|
|
||||||
Total derivative assets
|
$
|
10
|
|
|
$
|
516
|
|
|
$
|
—
|
|
|
$
|
(178
|
)
|
|
$
|
(8
|
)
|
|
$
|
340
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity derivatives
|
$
|
(1
|
)
|
|
$
|
(179
|
)
|
|
$
|
—
|
|
|
$
|
178
|
|
|
$
|
—
|
|
|
$
|
(2
|
)
|
Interest-rate derivatives
|
—
|
|
|
(1,542
|
)
|
|
—
|
|
|
—
|
|
|
58
|
|
|
(1,484
|
)
|
||||||
Total derivative liabilities
|
$
|
(1
|
)
|
|
$
|
(1,721
|
)
|
|
$
|
—
|
|
|
$
|
178
|
|
|
$
|
58
|
|
|
$
|
(1,486
|
)
|
(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 $69.1181 (Threshold Appreciation Price)
|
|
0.7234 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 $57.5901 (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
|
|
0.8682 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)
|
|
Anadarko Consolidated
|
|
Description
|
||||||||
Balance at December 31, 2014
|
$
|
2,409
|
|
|
$
|
—
|
|
|
$
|
12,574
|
|
|
$
|
14,983
|
|
|
|
Issuances
|
490
|
|
|
—
|
|
|
—
|
|
|
490
|
|
|
WES 3.950% Senior Notes due 2025
|
||||
|
—
|
|
|
—
|
|
|
97
|
|
|
97
|
|
|
TEUs - senior amortizing notes
|
||||
Borrowings
|
—
|
|
|
—
|
|
|
1,500
|
|
|
1,500
|
|
|
$5.0 Billion Facility
|
||||
|
—
|
|
|
—
|
|
|
1,800
|
|
|
1,800
|
|
|
364-Day Facility
|
||||
|
400
|
|
|
—
|
|
|
—
|
|
|
400
|
|
|
WES RCF
|
||||
|
—
|
|
|
—
|
|
|
250
|
|
|
250
|
|
|
Commercial paper notes, net
(3)
|
||||
Repayments
|
—
|
|
|
—
|
|
|
(1,500
|
)
|
|
(1,500
|
)
|
|
$5.0 Billion Facility
|
||||
|
—
|
|
|
—
|
|
|
(1,800
|
)
|
|
(1,800
|
)
|
|
364-Day Facility
|
||||
|
(610
|
)
|
|
—
|
|
|
—
|
|
|
(610
|
)
|
|
WES RCF
|
||||
|
—
|
|
|
—
|
|
|
(16
|
)
|
|
(16
|
)
|
|
TEUs - senior amortizing notes
|
||||
Other, net
|
2
|
|
|
—
|
|
|
52
|
|
|
54
|
|
|
Amortization of discounts, premiums, and debt issuance costs
|
||||
Balance at December 31, 2015
|
$
|
2,691
|
|
|
$
|
—
|
|
|
$
|
12,957
|
|
|
$
|
15,648
|
|
|
|
Issuances
|
—
|
|
|
—
|
|
|
794
|
|
|
794
|
|
|
4.850% Senior Notes due 2021
(4)
|
||||
|
—
|
|
|
—
|
|
|
1,088
|
|
|
1,088
|
|
|
5.550% Senior Notes due 2026
(4)
|
||||
|
—
|
|
|
—
|
|
|
1,088
|
|
|
1,088
|
|
|
6.600% Senior Notes due 2046
(4)
|
||||
|
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
|
|
|
|
(1)
|
Excludes WES.
|
(2)
|
Excludes WES and WGP.
|
(3)
|
Includes repayments of
$(106) million
related to commercial paper notes with maturities greater than 90 days.
|
(4)
|
Represent senior notes issued in March 2016.
|
|
December 31, 2016
|
||||||||||||||
millions
|
WES
|
|
WGP
(1)
|
|
Anadarko
(2)
|
|
Anadarko 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
|
|
|
December 31, 2015
|
||||||||||||||
millions
|
WES
|
|
WGP
(1)
|
|
Anadarko
(2)
|
|
Anadarko Consolidated
|
||||||||
Commercial paper
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
250
|
|
|
$
|
250
|
|
5.950% Senior Notes due 2016
|
—
|
|
|
—
|
|
|
1,750
|
|
|
1,750
|
|
||||
6.375% Senior Notes due 2017
|
—
|
|
|
—
|
|
|
2,000
|
|
|
2,000
|
|
||||
7.050% Debentures due 2018
|
—
|
|
|
—
|
|
|
114
|
|
|
114
|
|
||||
TEUs - senior amortizing notes due 2018
|
—
|
|
|
—
|
|
|
85
|
|
|
85
|
|
||||
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
|
|
||||
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
|
|
||||
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
|
400
|
|
|
—
|
|
|
—
|
|
|
400
|
|
||||
7.730% Debentures due 2096
|
—
|
|
|
—
|
|
|
61
|
|
|
61
|
|
||||
7.500% Debentures due 2096
|
—
|
|
|
—
|
|
|
78
|
|
|
78
|
|
||||
7.250% Debentures due 2096
|
—
|
|
|
—
|
|
|
49
|
|
|
49
|
|
||||
WES RCF
|
300
|
|
|
—
|
|
|
—
|
|
|
300
|
|
||||
Total borrowings at face value
|
$
|
2,720
|
|
|
$
|
—
|
|
|
$
|
14,592
|
|
|
$
|
17,312
|
|
Net unamortized discounts, premiums, and debt issuance costs
(3)
|
(29
|
)
|
|
—
|
|
|
(1,635
|
)
|
|
(1,664
|
)
|
||||
Total borrowings
(4)
|
2,691
|
|
|
—
|
|
|
12,957
|
|
|
15,648
|
|
||||
Capital lease obligations
|
—
|
|
|
—
|
|
|
20
|
|
|
20
|
|
||||
Less short-term debt
|
—
|
|
|
—
|
|
|
32
|
|
|
32
|
|
||||
Total long-term debt
|
$
|
2,691
|
|
|
$
|
—
|
|
|
$
|
12,945
|
|
|
$
|
15,636
|
|
(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 revolving credit facilities 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)
|
|
Anadarko Consolidated
|
||||||||
2017
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
34
|
|
|
$
|
34
|
|
2018
|
350
|
|
|
—
|
|
|
131
|
|
|
481
|
|
||||
2019
|
—
|
|
|
28
|
|
|
900
|
|
|
928
|
|
||||
2020
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
2021
|
500
|
|
|
—
|
|
|
800
|
|
|
1,300
|
|
(1)
|
Excludes WES.
|
(2)
|
Excludes WES and WGP.
|
millions
|
|
||
2017
|
$
|
57
|
|
2018
|
42
|
|
|
2019
|
42
|
|
|
2020
|
43
|
|
|
2021
|
42
|
|
|
Remaining years
|
391
|
|
|
Total future minimum lease payments
|
$
|
617
|
|
Less portion representing imputed interest
|
372
|
|
|
Capital lease obligations
|
$
|
245
|
|
millions
|
2016
|
|
2015
|
|
2014
|
||||||
Debt and other
|
$
|
1,022
|
|
|
$
|
989
|
|
|
$
|
973
|
|
Capitalized interest
|
(132
|
)
|
|
(164
|
)
|
|
(201
|
)
|
|||
Total interest expense
|
$
|
890
|
|
|
$
|
825
|
|
|
$
|
772
|
|
millions
|
2016
|
|
2015
|
|
2014
|
||||||
Current
|
|
|
|
|
|
||||||
Federal
|
$
|
(140
|
)
|
|
$
|
(177
|
)
|
|
$
|
188
|
|
State
|
(1
|
)
|
|
(18
|
)
|
|
2
|
|
|||
Foreign
|
378
|
|
|
495
|
|
|
1,574
|
|
|||
|
237
|
|
|
300
|
|
|
1,764
|
|
|||
Deferred
|
|
|
|
|
|
||||||
Federal
|
(1,020
|
)
|
|
(2,929
|
)
|
|
(389
|
)
|
|||
State
|
(148
|
)
|
|
(145
|
)
|
|
27
|
|
|||
Foreign
|
(90
|
)
|
|
(103
|
)
|
|
215
|
|
|||
|
(1,258
|
)
|
|
(3,177
|
)
|
|
(147
|
)
|
|||
Total income tax expense (benefit)
|
$
|
(1,021
|
)
|
|
$
|
(2,877
|
)
|
|
$
|
1,617
|
|
millions except percentages
|
2016
|
|
2015
|
|
2014
|
||||||
Income (loss) before income taxes
|
|
|
|
|
|
||||||
Domestic
|
$
|
(3,728
|
)
|
|
$
|
(9,155
|
)
|
|
$
|
(3,564
|
)
|
Foreign
|
(101
|
)
|
|
(534
|
)
|
|
3,618
|
|
|||
Total
|
$
|
(3,829
|
)
|
|
$
|
(9,689
|
)
|
|
$
|
54
|
|
U.S. federal statutory tax rate
|
35
|
%
|
|
35
|
%
|
|
35
|
%
|
|||
Tax computed at the U.S. federal statutory rate
|
$
|
(1,340
|
)
|
|
$
|
(3,391
|
)
|
|
$
|
19
|
|
Adjustments resulting from
|
|
|
|
|
|
||||||
State income taxes (net of federal income tax benefit)
|
(108
|
)
|
|
(81
|
)
|
|
(11
|
)
|
|||
Tax impact from foreign operations
|
80
|
|
|
299
|
|
|
62
|
|
|||
Non-deductible Algerian exceptional profits tax
|
106
|
|
|
102
|
|
|
193
|
|
|||
Net changes in uncertain tax positions
|
90
|
|
|
54
|
|
|
1,427
|
|
|||
(Income) loss attributable to noncontrolling interests
|
(92
|
)
|
|
42
|
|
|
(66
|
)
|
|||
Dispositions of non-deductible goodwill
|
205
|
|
|
62
|
|
|
21
|
|
|||
Other, net
|
38
|
|
|
36
|
|
|
(28
|
)
|
|||
Total income tax expense (benefit)
|
$
|
(1,021
|
)
|
|
$
|
(2,877
|
)
|
|
$
|
1,617
|
|
Effective tax rate
|
27
|
%
|
|
30
|
%
|
|
2,994
|
%
|
millions
|
2016
|
|
2015
|
||||
Federal
|
$
|
(3,805
|
)
|
|
$
|
(4,721
|
)
|
State, net of federal
|
(173
|
)
|
|
(248
|
)
|
||
Foreign
|
(332
|
)
|
|
(431
|
)
|
||
Total deferred taxes
|
$
|
(4,310
|
)
|
|
$
|
(5,400
|
)
|
millions
|
2016
|
|
2015
|
||||
Deferred tax liabilities
|
|
|
|
||||
Oil and gas exploration and development operations
|
$
|
(5,054
|
)
|
|
$
|
(5,643
|
)
|
Midstream and other depreciable properties
|
(870
|
)
|
|
(1,049
|
)
|
||
Mineral operations
|
(550
|
)
|
|
(492
|
)
|
||
Other
|
(147
|
)
|
|
(470
|
)
|
||
Gross long-term deferred tax liabilities
|
(6,621
|
)
|
|
(7,654
|
)
|
||
Deferred tax assets
|
|
|
|
||||
Foreign and state net operating loss carryforwards
|
648
|
|
|
586
|
|
||
U.S. foreign tax credit carryforwards
|
1,834
|
|
|
1,254
|
|
||
Compensation and benefit plans
|
672
|
|
|
615
|
|
||
Mark to market on derivatives
|
324
|
|
|
441
|
|
||
Other
|
588
|
|
|
761
|
|
||
Gross long-term deferred tax assets
|
4,066
|
|
|
3,657
|
|
||
Valuation allowances on deferred tax assets not expected to be realized
|
(1,755
|
)
|
|
(1,403
|
)
|
||
Net long-term deferred tax assets
|
2,311
|
|
|
2,254
|
|
||
Total deferred taxes
|
$
|
(4,310
|
)
|
|
$
|
(5,400
|
)
|
millions
|
2016
|
|
2015
|
|
2014
|
||||||
Balance at January 1
|
$
|
(1,403
|
)
|
|
$
|
(864
|
)
|
|
$
|
(818
|
)
|
Changes due to U.S. foreign tax credits
|
(477
|
)
|
|
(384
|
)
|
|
11
|
|
|||
Changes due to foreign and state net operating loss carryforwards
|
13
|
|
|
10
|
|
|
64
|
|
|||
Changes due to foreign capitalized costs
|
112
|
|
|
(165
|
)
|
|
(121
|
)
|
|||
Balance at December 31
|
$
|
(1,755
|
)
|
|
$
|
(1,403
|
)
|
|
$
|
(864
|
)
|
millions
|
Domestic
|
|
Foreign
|
|
Expiration
|
||||
Net operating loss—foreign
|
$
|
—
|
|
|
$
|
1,498
|
|
|
2017 - Indefinite
|
Net operating loss—state
|
$
|
4,888
|
|
|
$
|
—
|
|
|
2017-2036
|
Foreign tax credits
|
$
|
1,834
|
|
|
$
|
—
|
|
|
2023-2027
|
Texas margins tax credit
|
$
|
34
|
|
|
$
|
—
|
|
|
2026
|
millions
|
|
|
|
|
||||
Balance Sheet Classification
|
|
2016
|
|
2015
|
||||
Income taxes receivable
|
|
|
|
|
||||
Accounts receivable—other
|
|
$
|
180
|
|
|
$
|
1,046
|
|
Other assets
|
|
67
|
|
|
61
|
|
||
|
|
247
|
|
|
1,107
|
|
||
Income taxes (payable)
|
|
|
|
|
||||
Accrued expense
|
|
(6
|
)
|
|
(9
|
)
|
||
Total net income taxes receivable (payable)
|
|
$
|
241
|
|
|
$
|
1,098
|
|
|
Assets (Liabilities)
|
||||||||||
millions
|
2016
|
|
2015
|
|
2014
|
||||||
Balance at January 1
|
$
|
(1,780
|
)
|
|
$
|
(1,687
|
)
|
|
$
|
(147
|
)
|
Increases related to prior-year tax positions
|
(86
|
)
|
|
(99
|
)
|
|
(11
|
)
|
|||
Decreases related to prior-year tax positions
|
436
|
|
|
89
|
|
|
39
|
|
|||
Increases related to current-year tax positions
|
(26
|
)
|
|
(263
|
)
|
|
(1,568
|
)
|
|||
Settlements
|
—
|
|
|
180
|
|
|
—
|
|
|||
Balance at December 31
|
$
|
(1,456
|
)
|
|
$
|
(1,780
|
)
|
|
$
|
(1,687
|
)
|
|
Tax Years
|
United States
|
2012-2015
|
Algeria
|
2012-2015
|
Ghana
|
2006-2015
|
millions
|
2016
|
|
2015
|
||||
Carrying amount at January 1
|
$
|
2,059
|
|
|
$
|
2,053
|
|
Liabilities acquired
(1)
|
813
|
|
|
—
|
|
||
Liabilities incurred
|
93
|
|
|
104
|
|
||
Property dispositions
|
(88
|
)
|
|
(108
|
)
|
||
Liabilities settled
|
(225
|
)
|
|
(298
|
)
|
||
Accretion expense
|
100
|
|
|
102
|
|
||
Revisions in estimated liabilities
|
179
|
|
|
206
|
|
||
Carrying amount at December 31
|
$
|
2,931
|
|
|
$
|
2,059
|
|
(1)
|
In December 2016, the Company closed the GOM Acquisition. See
Note 3—Acquisitions, Divestitures, and Assets Held for Sale
for additional information.
|
millions
|
|
||
2017
|
$
|
50
|
|
2018
|
50
|
|
|
2019
|
52
|
|
|
2020
|
56
|
|
|
2021
|
57
|
|
|
Later years
|
263
|
|
|
Total
|
$
|
528
|
|
millions
|
|
||
2017
|
$
|
673
|
|
2018
|
480
|
|
|
2019
|
234
|
|
|
2020
|
81
|
|
|
2021
|
29
|
|
|
Later years
|
23
|
|
|
Total future minimum lease payments
|
$
|
1,520
|
|
millions
|
|
||
2017
|
$
|
1,328
|
|
2018
|
1,207
|
|
|
2019
|
1,001
|
|
|
2020
|
934
|
|
|
2021
|
677
|
|
|
Later years
|
1,224
|
|
|
Total future minimum lease payments
(1)
|
$
|
6,371
|
|
(1)
|
Excludes purchase commitments for jointly owned fields and facilities for which the Company is not the operator.
|
millions
|
Total
Expected Costs
|
|
Year Ended December 31, 2016
|
||||
Costs by category
|
|
|
|
||||
Cash severance
|
$
|
153
|
|
|
$
|
153
|
|
Retirement benefits
(1)
|
239
|
|
|
197
|
|
||
Share-based compensation
|
39
|
|
|
39
|
|
||
Total
|
$
|
431
|
|
|
$
|
389
|
|
(1)
|
Includes termination benefits, curtailments, and settlements. See
Note 18—Pension Plans and Other Postretirement Benefits
.
|
millions
|
2016
|
||
Balance at January 1
|
$
|
—
|
|
Accruals
|
153
|
|
|
Payments
|
(145
|
)
|
|
Balance at December 31
|
$
|
8
|
|
|
Pension Benefits
|
|
Other Benefits
|
||||||||||||
millions
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Change in benefit obligation
|
|
|
|
|
|
|
|
||||||||
Benefit obligation at beginning of year
|
$
|
2,431
|
|
|
$
|
2,528
|
|
|
$
|
266
|
|
|
$
|
373
|
|
Service cost
|
99
|
|
|
118
|
|
|
3
|
|
|
9
|
|
||||
Interest cost
|
95
|
|
|
101
|
|
|
12
|
|
|
15
|
|
||||
Plan amendments
|
—
|
|
|
—
|
|
|
—
|
|
|
(89
|
)
|
||||
Actuarial (gain) loss
(1)
|
211
|
|
|
(115
|
)
|
|
34
|
|
|
(27
|
)
|
||||
Participant contributions
|
—
|
|
|
—
|
|
|
4
|
|
|
5
|
|
||||
Benefit payments
|
(513
|
)
|
|
(194
|
)
|
|
(23
|
)
|
|
(20
|
)
|
||||
Foreign-currency exchange-rate changes
|
(22
|
)
|
|
(7
|
)
|
|
—
|
|
|
—
|
|
||||
Benefit obligation at end of year
(2)
|
$
|
2,301
|
|
|
$
|
2,431
|
|
|
$
|
296
|
|
|
$
|
266
|
|
Change in plan assets
|
|
|
|
|
|
|
|
||||||||
Fair value of plan assets at beginning of year
|
$
|
1,674
|
|
|
$
|
1,818
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Actual return on plan assets
|
107
|
|
|
16
|
|
|
—
|
|
|
—
|
|
||||
Employer contributions
|
101
|
|
|
43
|
|
|
19
|
|
|
15
|
|
||||
Participant contributions
|
—
|
|
|
—
|
|
|
4
|
|
|
5
|
|
||||
Benefit payments
|
(513
|
)
|
|
(194
|
)
|
|
(23
|
)
|
|
(20
|
)
|
||||
Foreign-currency exchange-rate changes
|
(29
|
)
|
|
(9
|
)
|
|
—
|
|
|
—
|
|
||||
Fair value of plan assets at end of year
|
$
|
1,340
|
|
|
$
|
1,674
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
||||||||
Funded status of the plans at end of year
|
$
|
(961
|
)
|
|
$
|
(757
|
)
|
|
$
|
(296
|
)
|
|
$
|
(266
|
)
|
|
|
|
|
|
|
|
|
||||||||
Total recognized amounts in the balance sheet consist of
|
|
|
|
|
|
|
|
||||||||
Other assets
|
$
|
44
|
|
|
$
|
41
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Accrued expenses
|
(66
|
)
|
|
(24
|
)
|
|
(23
|
)
|
|
(16
|
)
|
||||
Other long-term liabilities—other
|
(939
|
)
|
|
(774
|
)
|
|
(273
|
)
|
|
(250
|
)
|
||||
Total
|
$
|
(961
|
)
|
|
$
|
(757
|
)
|
|
$
|
(296
|
)
|
|
$
|
(266
|
)
|
|
|
|
|
|
|
|
|
||||||||
Total recognized amounts in accumulated other comprehensive income consist of
|
|
|
|
|
|
|
|
||||||||
Prior service cost (credit)
|
$
|
—
|
|
|
$
|
(1
|
)
|
|
$
|
(50
|
)
|
|
$
|
(84
|
)
|
Net actuarial (gain) loss
|
616
|
|
|
655
|
|
|
—
|
|
|
(25
|
)
|
||||
Total
|
$
|
616
|
|
|
$
|
654
|
|
|
$
|
(50
|
)
|
|
$
|
(109
|
)
|
(1)
|
Includes
$44 million
of termination benefits,
$2 million
related to curtailment for pension, and
$9 million
related to curtailment for other benefits at December 31, 2016, associated with the Company’s workforce reduction program initiated in the first quarter of 2016. See
Note 17—Restructuring Charges
.
|
(2)
|
The accumulated benefit obligation for all defined-benefit pension plans was
$2.0 billion
at
December 31, 2016
and
$2.1 billion
at
December 31, 2015
.
|
millions
|
2016
|
|
2015
|
||||
Projected benefit obligation
|
$
|
2,175
|
|
|
$
|
2,309
|
|
Accumulated benefit obligation
|
1,866
|
|
|
1,954
|
|
||
Fair value of plan assets
|
1,171
|
|
|
1,511
|
|
|
Pension Benefits
|
|
Other Benefits
|
||||||||||||||||||||
millions
|
2016
|
|
2015
|
|
2014
|
|
2016
|
|
2015
|
|
2014
|
||||||||||||
Components of net periodic benefit cost
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Service cost
|
$
|
99
|
|
|
$
|
118
|
|
|
$
|
99
|
|
|
$
|
3
|
|
|
$
|
9
|
|
|
$
|
7
|
|
Interest cost
|
95
|
|
|
101
|
|
|
99
|
|
|
12
|
|
|
15
|
|
|
15
|
|
||||||
Expected (return) loss on plan assets
|
(97
|
)
|
|
(109
|
)
|
|
(106
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Amortization of net actuarial loss (gain)
|
42
|
|
|
52
|
|
|
34
|
|
|
—
|
|
|
—
|
|
|
(7
|
)
|
||||||
Amortization of net prior service cost (credit)
|
—
|
|
|
—
|
|
|
—
|
|
|
(25
|
)
|
|
(4
|
)
|
|
—
|
|
||||||
Settlement expense
(1)
|
146
|
|
|
11
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Termination benefits expense
(1)
|
44
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Curtailment expense
(1)
|
8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Net periodic benefit cost
|
$
|
337
|
|
|
$
|
173
|
|
|
$
|
126
|
|
|
$
|
(10
|
)
|
|
$
|
20
|
|
|
$
|
15
|
|
(1)
|
During 2016, settlement expenses, termination benefits expense, and curtailment expense primarily relate to the workforce reduction program initiated in the first quarter of 2016. See
Note 17—Restructuring Charges
.
|
|
Pension Benefits
|
|
Other Benefits
|
||||||||||||||||||||
millions
|
2016
|
|
2015
|
|
2014
|
|
2016
|
|
2015
|
|
2014
|
||||||||||||
Amounts recognized in other comprehensive income (expense)
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net actuarial gain (loss)
|
$
|
(150
|
)
|
|
$
|
22
|
|
|
$
|
(333
|
)
|
|
$
|
(25
|
)
|
|
$
|
27
|
|
|
$
|
(72
|
)
|
Amortization of net actuarial (gain) loss
|
188
|
|
|
63
|
|
|
34
|
|
|
—
|
|
|
—
|
|
|
(7
|
)
|
||||||
Net prior service (cost) credit
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
89
|
|
|
—
|
|
||||||
Amortization of net prior service cost (credit)
|
—
|
|
|
—
|
|
|
—
|
|
|
(34
|
)
|
|
(4
|
)
|
|
—
|
|
||||||
Total amounts recognized in other comprehensive income (expense)
|
$
|
38
|
|
|
$
|
85
|
|
|
$
|
(299
|
)
|
|
$
|
(59
|
)
|
|
$
|
112
|
|
|
$
|
(79
|
)
|
|
Pension Benefits
|
|
Other Benefits
|
||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
2016
|
|
2015
|
|
2014
|
||||||
Benefit obligation assumptions
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Discount rate
|
4.06
|
%
|
|
4.50
|
%
|
|
4.00
|
%
|
|
4.26
|
%
|
|
5.00
|
%
|
|
4.25
|
%
|
Rates of increase in compensation levels
|
5.40
|
%
|
|
5.25
|
%
|
|
5.25
|
%
|
|
5.48
|
%
|
|
5.50
|
%
|
|
5.25
|
%
|
Net periodic benefit cost assumptions
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Discount rate
|
4.62
|
%
|
|
4.00
|
%
|
|
4.75
|
%
|
|
5.00
|
%
|
|
4.25
|
%
|
|
5.25
|
%
|
Long-term rate of return on plan assets
|
6.77
|
%
|
|
6.75
|
%
|
|
6.75
|
%
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
Rates of increase in compensation levels
|
5.34
|
%
|
|
5.25
|
%
|
|
5.00
|
%
|
|
5.41
|
%
|
|
5.25
|
%
|
|
5.25
|
%
|
millions
|
|
|
|
|
|
|
|
||||||||
December 31, 2016
|
Level 1
|
|
Level 2
|
|
Level 3
(3)
|
|
Total
|
||||||||
Investments
|
|
|
|
|
|
|
|
||||||||
Cash and cash equivalents
|
$
|
2
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2
|
|
Fixed income
|
|
|
|
|
|
|
|
||||||||
Mortgage-backed securities
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
||||
Other fixed-income securities
|
59
|
|
|
32
|
|
|
—
|
|
|
91
|
|
||||
Equity securities
|
|
|
|
|
|
|
|
||||||||
Domestic
|
248
|
|
|
—
|
|
|
—
|
|
|
248
|
|
||||
International
|
99
|
|
|
—
|
|
|
—
|
|
|
99
|
|
||||
Other
|
|
|
|
|
|
|
|
||||||||
Real estate
|
—
|
|
|
—
|
|
|
10
|
|
|
10
|
|
||||
Other
|
—
|
|
|
28
|
|
|
—
|
|
|
28
|
|
||||
Investments measured at net asset value
(1)
|
—
|
|
|
—
|
|
|
—
|
|
|
861
|
|
||||
Total investments
(2)
|
$
|
408
|
|
|
$
|
61
|
|
|
$
|
10
|
|
|
$
|
1,340
|
|
|
|
|
|
|
|
|
|
||||||||
December 31, 2015
|
|
|
|
|
|
|
|
||||||||
Investments
|
|
|
|
|
|
|
|
||||||||
Cash and cash equivalents
|
$
|
5
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
5
|
|
Fixed income
|
|
|
|
|
|
|
|
||||||||
Mortgage-backed securities
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
||||
U.S. government securities
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
||||
Other fixed-income securities
|
46
|
|
|
32
|
|
|
—
|
|
|
78
|
|
||||
Equity securities
|
|
|
|
|
|
|
|
||||||||
Domestic
|
330
|
|
|
—
|
|
|
—
|
|
|
330
|
|
||||
International
|
130
|
|
|
—
|
|
|
—
|
|
|
130
|
|
||||
Other
|
|
|
|
|
|
|
|
||||||||
Real estate
|
—
|
|
|
—
|
|
|
13
|
|
|
13
|
|
||||
Hedge funds
|
7
|
|
|
—
|
|
|
—
|
|
|
7
|
|
||||
Other
|
—
|
|
|
30
|
|
|
—
|
|
|
30
|
|
||||
Investments measured at net asset value
(1)
|
—
|
|
|
—
|
|
|
—
|
|
|
1,081
|
|
||||
Total investments
(2)
|
$
|
518
|
|
|
$
|
64
|
|
|
$
|
13
|
|
|
$
|
1,676
|
|
Liabilities
|
|
|
|
|
|
|
|
||||||||
Hedge funds
|
$
|
(3
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(3
|
)
|
Total liabilities
|
$
|
(3
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(3
|
)
|
(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, 2016
, and
$1 million
for the year ended
December 31, 2015
, were attributable to the actual return on plan assets still held at the reporting date.
|
millions
|
Expected 2017
|
|
2016
|
||||
Funded pension plans
|
$
|
140
|
|
|
$
|
3
|
|
Unfunded pension plans
|
67
|
|
|
98
|
|
||
Unfunded other postretirement plans
|
24
|
|
|
19
|
|
||
Total
|
$
|
231
|
|
|
$
|
120
|
|
millions
|
Pension
Benefit
Payments
|
|
Other
Benefit
Payments
|
||||
2017
|
$
|
302
|
|
|
$
|
24
|
|
2018
|
147
|
|
|
20
|
|
||
2019
|
166
|
|
|
20
|
|
||
2020
|
164
|
|
|
20
|
|
||
2021
|
171
|
|
|
19
|
|
||
2022-2026
|
1,009
|
|
|
93
|
|
millions
|
2016
|
|
2015
|
|
2014
|
|||
Shares of common stock issued
|
|
|
|
|
|
|||
Shares at January 1
|
528
|
|
|
526
|
|
|
523
|
|
Exercise of stock options
|
1
|
|
|
1
|
|
|
2
|
|
Issuance of common stock
|
41
|
|
|
—
|
|
|
—
|
|
Issuance of restricted stock
|
2
|
|
|
1
|
|
|
1
|
|
Shares at December 31
|
572
|
|
|
528
|
|
|
526
|
|
Shares of common stock held in treasury
|
|
|
|
|
|
|||
Shares at January 1
|
20
|
|
|
19
|
|
|
19
|
|
Shares received for restricted stock vested and stock options exercised
|
1
|
|
|
1
|
|
|
—
|
|
Shares at December 31
|
21
|
|
|
20
|
|
|
19
|
|
Shares of common stock outstanding at December 31
|
551
|
|
|
508
|
|
|
507
|
|
millions except per-share amounts
|
2016
|
|
2015
|
|
2014
|
||||||
Net income (loss)
|
|
|
|
|
|
||||||
Net income (loss) attributable to common stockholders
|
$
|
(3,071
|
)
|
|
$
|
(6,692
|
)
|
|
$
|
(1,750
|
)
|
Income (loss) effect of TEUs
|
(6
|
)
|
|
—
|
|
|
—
|
|
|||
Less distributions on participating securities
|
1
|
|
|
3
|
|
|
4
|
|
|||
Basic
|
$
|
(3,078
|
)
|
|
$
|
(6,695
|
)
|
|
$
|
(1,754
|
)
|
Income (loss) effect of TEUs
|
(1
|
)
|
|
—
|
|
|
—
|
|
|||
Diluted
|
$
|
(3,079
|
)
|
|
$
|
(6,695
|
)
|
|
$
|
(1,754
|
)
|
Shares
|
|
|
|
|
|
||||||
Average number of common shares outstanding—basic
|
522
|
|
|
508
|
|
|
506
|
|
|||
Average number of common shares outstanding—diluted
|
522
|
|
|
508
|
|
|
506
|
|
|||
Excluded due to anti-dilutive effect
|
11
|
|
|
11
|
|
|
11
|
|
|||
Net income (loss) per common share
|
|
|
|
|
|
||||||
Basic
|
$
|
(5.90
|
)
|
|
$
|
(13.18
|
)
|
|
$
|
(3.47
|
)
|
Diluted
|
$
|
(5.90
|
)
|
|
$
|
(13.18
|
)
|
|
$
|
(3.47
|
)
|
millions
|
Interest-rate
Derivatives
Previously
Subject to Hedge
Accounting
|
|
Pension and Other Postretirement
Plans
|
|
Total
|
||||||
Balance at December 31, 2013
|
$
|
(54
|
)
|
|
$
|
(231
|
)
|
|
$
|
(285
|
)
|
Other comprehensive income (loss), before reclassifications
|
—
|
|
|
(256
|
)
|
|
(256
|
)
|
|||
Reclassifications to Consolidated Statement of Income
|
6
|
|
|
18
|
|
|
24
|
|
|||
Net other comprehensive income (loss)
|
6
|
|
|
(238
|
)
|
|
(232
|
)
|
|||
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
|
)
|
millions
|
2016
|
|
2015
|
|
2014
|
||||||
Restricted stock
(1)
|
$
|
175
|
|
|
$
|
157
|
|
|
$
|
144
|
|
Stock options
(1)
|
20
|
|
|
19
|
|
|
21
|
|
|||
Other equity-classified awards
|
2
|
|
|
1
|
|
|
1
|
|
|||
Value creation plan
|
—
|
|
|
(4
|
)
|
|
136
|
|
|||
Performance-based unit awards
(1)
|
38
|
|
|
(1
|
)
|
|
23
|
|
|||
Pretax share-based compensation expense
|
$
|
235
|
|
|
$
|
172
|
|
|
$
|
325
|
|
Income tax benefit
|
$
|
86
|
|
|
$
|
64
|
|
|
$
|
120
|
|
(1)
|
Includes restructuring charges of
$31 million
for restricted stock,
$1 million
for stock options, and
$7 million
for performance-based unit awards in 2016. See
Note 17—Restructuring Charges
for further discussion.
|
|
Shares
(millions)
|
|
Weighted-Average
Grant-Date
Fair Value
(per share)
|
|||
Non-vested at January 1, 2016
|
3.98
|
|
|
$
|
82.39
|
|
Granted
|
3.11
|
|
|
$
|
52.03
|
|
Vested
|
(2.43
|
)
|
|
$
|
81.19
|
|
Forfeited
|
(0.12
|
)
|
|
$
|
63.78
|
|
Non-vested at December 31, 2016
|
4.54
|
|
|
$
|
62.74
|
|
•
|
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.
|
•
|
Expected forfeiture
—Based on historical forfeiture experience.
|
|
2016
|
|
2015
|
|
2014
|
|||||||||
Weighted-average grant-date fair value
|
$
|
15.92
|
|
|
$
|
18.18
|
|
|
$
|
23.55
|
|
|||
Assumptions
|
|
|
|
|
|
|
|
|
||||||
Expected option life—years
|
4.1
|
|
|
4.9
|
|
|
4.9
|
|
||||||
Volatility
|
38.2
|
%
|
|
32.4
|
%
|
|
29.9
|
%
|
||||||
Risk-free interest rate
|
1.3
|
%
|
|
1.4
|
%
|
|
1.6
|
%
|
||||||
Dividend yield
|
0.6
|
%
|
|
1.4
|
%
|
|
1.1
|
%
|
|
Shares
(millions)
|
|
Weighted-
Average
Exercise
Price
(per share)
|
|
Weighted-
Average
Remaining
Contractual
Term
(years)
|
|
Aggregate
Intrinsic
Value
(millions)
|
|||||
Outstanding at January 1, 2016
|
7.05
|
|
|
$
|
71.86
|
|
|
|
|
|
||
Granted
|
1.38
|
|
|
$
|
67.74
|
|
|
|
|
|
||
Exercised
(1)
|
(0.90
|
)
|
|
$
|
33.69
|
|
|
|
|
|
||
Forfeited or expired
|
(0.91
|
)
|
|
$
|
72.40
|
|
|
|
|
|
||
Outstanding at December 31, 2016
|
6.62
|
|
|
$
|
76.10
|
|
|
3.18
|
|
$
|
10.6
|
|
Vested or expected to vest at December 31, 2016
|
6.56
|
|
|
$
|
76.15
|
|
|
3.16
|
|
$
|
10.4
|
|
Exercisable at December 31, 2016
|
5.05
|
|
|
$
|
78.61
|
|
|
2.22
|
|
$
|
3.5
|
|
(1)
|
The total intrinsic value of stock options exercised was
$7 million
during
2016
,
$23 million
during
2015
, and
$88 million
during
2014
, based on the difference between the market price at the exercise date and the exercise price.
|
millions
|
2016
|
|
2015
|
|
2014
|
||||||
Cash paid (received)
|
|
|
|
|
|
||||||
Interest, net of amounts capitalized
(1)
|
$
|
856
|
|
|
$
|
2,019
|
|
|
$
|
689
|
|
Income taxes, net of refunds
(2)
|
(882
|
)
|
|
26
|
|
|
956
|
|
|||
Non-cash investing activities
|
|
|
|
|
|
||||||
Fair value of properties and equipment from non-cash transactions
|
$
|
3
|
|
|
$
|
178
|
|
|
$
|
18
|
|
Asset retirement cost additions
|
298
|
|
|
273
|
|
|
348
|
|
|||
Accruals of property, plant, and equipment
|
549
|
|
|
754
|
|
|
1,177
|
|
|||
Net liabilities assumed (divested) in acquisitions and divestitures
|
723
|
|
|
(114
|
)
|
|
(92
|
)
|
|||
Property insurance receivable
|
—
|
|
|
49
|
|
|
—
|
|
|||
Acquisition receivable
|
(32
|
)
|
|
—
|
|
|
—
|
|
|||
Non-cash investing and financing activities
|
|
|
|
|
|
||||||
Acquisition contingent consideration
|
$
|
103
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Capital lease obligation
(3)
|
10
|
|
|
—
|
|
|
13
|
|
|||
FPSO construction period obligation
(3)
|
11
|
|
|
59
|
|
|
128
|
|
|||
Deferred drilling lease liability
|
30
|
|
|
—
|
|
|
—
|
|
(1)
|
Includes
$1.2 billion
of interest related to the Tronox settlement payment in 2015.
|
(2)
|
Includes
$881 million
from a tax refund 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 11—Debt and Interest Expense
.
|
millions
|
2016
|
|
2015
|
|
2014
|
||||||
Income (loss) before income taxes
|
$
|
(3,829
|
)
|
|
$
|
(9,689
|
)
|
|
$
|
54
|
|
(Gains) losses on divestitures, net
|
757
|
|
|
1,022
|
|
|
(1,891
|
)
|
|||
Exploration expense
|
946
|
|
|
2,644
|
|
|
1,639
|
|
|||
DD&A
|
4,301
|
|
|
4,603
|
|
|
4,550
|
|
|||
Impairments
|
227
|
|
|
5,075
|
|
|
836
|
|
|||
Interest expense
|
890
|
|
|
825
|
|
|
772
|
|
|||
Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives
|
559
|
|
|
235
|
|
|
578
|
|
|||
Restructuring charges
|
389
|
|
|
—
|
|
|
—
|
|
|||
Other operating expense
|
1
|
|
|
74
|
|
|
97
|
|
|||
Loss on early extinguishment of debt
|
155
|
|
|
—
|
|
|
—
|
|
|||
Tronox-related contingent loss
|
—
|
|
|
5
|
|
|
4,360
|
|
|||
Certain other nonoperating items
|
(58
|
)
|
|
22
|
|
|
22
|
|
|||
Less net income (loss) attributable to noncontrolling interests
|
263
|
|
|
(120
|
)
|
|
187
|
|
|||
Consolidated Adjusted EBITDAX
|
$
|
4,075
|
|
|
$
|
4,936
|
|
|
$
|
10,830
|
|
millions
|
Oil and Gas
Exploration
& Production
|
|
Midstream
|
|
Marketing
|
|
Other and
Intersegment
Eliminations
|
|
Total
|
||||||||||
2016
|
|
|
|
|
|
|
|
|
|
||||||||||
Sales revenues
|
$
|
4,191
|
|
|
$
|
635
|
|
|
$
|
3,621
|
|
|
$
|
—
|
|
|
$
|
8,447
|
|
Intersegment revenues
|
2,651
|
|
|
1,403
|
|
|
(3,094
|
)
|
|
(960
|
)
|
|
—
|
|
|||||
Other
|
—
|
|
|
—
|
|
|
—
|
|
|
179
|
|
|
179
|
|
|||||
Total revenues and other
(1)
|
6,842
|
|
|
2,038
|
|
|
527
|
|
|
(781
|
)
|
|
8,626
|
|
|||||
Operating costs and expenses
(2)
|
3,238
|
|
|
978
|
|
|
691
|
|
|
(303
|
)
|
|
4,604
|
|
|||||
Net cash from settlement of commodity derivatives
|
—
|
|
|
—
|
|
|
—
|
|
|
(265
|
)
|
|
(265
|
)
|
|||||
Other (income) expense, net
(3)
|
—
|
|
|
—
|
|
|
—
|
|
|
(43
|
)
|
|
(43
|
)
|
|||||
Net income (loss) attributable to noncontrolling interests
|
—
|
|
|
263
|
|
|
—
|
|
|
—
|
|
|
263
|
|
|||||
Total expenses and other
|
3,238
|
|
|
1,241
|
|
|
691
|
|
|
(611
|
)
|
|
4,559
|
|
|||||
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement
|
—
|
|
|
—
|
|
|
8
|
|
|
—
|
|
|
8
|
|
|||||
Adjusted EBITDAX
|
$
|
3,604
|
|
|
$
|
797
|
|
|
$
|
(156
|
)
|
|
$
|
(170
|
)
|
|
$
|
4,075
|
|
Net properties and equipment
|
$
|
24,251
|
|
|
$
|
5,913
|
|
|
$
|
—
|
|
|
$
|
2,004
|
|
|
$
|
32,168
|
|
Capital expenditures
|
$
|
2,685
|
|
|
$
|
550
|
|
|
$
|
—
|
|
|
$
|
79
|
|
|
$
|
3,314
|
|
Goodwill
|
$
|
4,550
|
|
|
$
|
450
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
5,000
|
|
(1)
|
Total revenues and other excludes gains (losses) on divestitures, net since these gains and losses are excluded from Adjusted EBITDAX.
|
(2)
|
Operating costs and expenses excludes exploration expense, DD&A, impairments, restructuring charges, and other operating expense since these expenses are excluded from Adjusted EBITDAX.
|
(3)
|
Other (income) expense, net excludes certain other nonoperating items since these items are excluded from Adjusted EBITDAX.
|
millions
|
Oil and Gas
Exploration
& Production
|
|
Midstream
|
|
Marketing
|
|
Other and
Intersegment
Eliminations
|
|
Total
|
||||||||||
2015
|
|
|
|
|
|
|
|
|
|
||||||||||
Sales revenues
|
$
|
4,734
|
|
|
$
|
727
|
|
|
$
|
4,025
|
|
|
$
|
—
|
|
|
$
|
9,486
|
|
Intersegment revenues
|
3,178
|
|
|
1,207
|
|
|
(3,476
|
)
|
|
(909
|
)
|
|
—
|
|
|||||
Other
|
—
|
|
|
—
|
|
|
—
|
|
|
234
|
|
|
234
|
|
|||||
Total revenues and other
(1)
|
7,912
|
|
|
1,934
|
|
|
549
|
|
|
(675
|
)
|
|
9,720
|
|
|||||
Operating costs and expenses
(2)
|
3,456
|
|
|
998
|
|
|
743
|
|
|
(86
|
)
|
|
5,111
|
|
|||||
Net cash from settlement of commodity derivatives
|
—
|
|
|
—
|
|
|
—
|
|
|
(335
|
)
|
|
(335
|
)
|
|||||
Other (income) expense, net
(3)
|
—
|
|
|
—
|
|
|
—
|
|
|
127
|
|
|
127
|
|
|||||
Net income (loss) attributable to noncontrolling interests
|
—
|
|
|
(120
|
)
|
|
—
|
|
|
—
|
|
|
(120
|
)
|
|||||
Total expenses and other
|
3,456
|
|
|
878
|
|
|
743
|
|
|
(294
|
)
|
|
4,783
|
|
|||||
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
|||||
Adjusted EBITDAX
|
$
|
4,456
|
|
|
$
|
1,056
|
|
|
$
|
(195
|
)
|
|
$
|
(381
|
)
|
|
$
|
4,936
|
|
Net properties and equipment
|
$
|
25,742
|
|
|
$
|
5,876
|
|
|
$
|
—
|
|
|
$
|
2,133
|
|
|
$
|
33,751
|
|
Capital expenditures
|
$
|
5,029
|
|
|
$
|
770
|
|
|
$
|
—
|
|
|
$
|
89
|
|
|
$
|
5,888
|
|
Goodwill
|
$
|
4,945
|
|
|
$
|
450
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
5,395
|
|
2014
|
|
|
|
|
|
|
|
|
|
||||||||||
Sales revenues
|
$
|
8,603
|
|
|
$
|
484
|
|
|
$
|
7,288
|
|
|
$
|
—
|
|
|
$
|
16,375
|
|
Intersegment revenues
|
6,225
|
|
|
1,338
|
|
|
(6,771
|
)
|
|
(792
|
)
|
|
—
|
|
|||||
Other
|
—
|
|
|
—
|
|
|
—
|
|
|
204
|
|
|
204
|
|
|||||
Total revenues and other
(1)
|
14,828
|
|
|
1,822
|
|
|
517
|
|
|
(588
|
)
|
|
16,579
|
|
|||||
Operating costs and expenses
(2)
|
4,216
|
|
|
972
|
|
|
740
|
|
|
17
|
|
|
5,945
|
|
|||||
Net cash from settlement of commodity derivatives
|
—
|
|
|
—
|
|
|
—
|
|
|
(377
|
)
|
|
(377
|
)
|
|||||
Other (income) expense, net
(3)
|
—
|
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
(2
|
)
|
|||||
Net income (loss) attributable to noncontrolling interests
|
—
|
|
|
187
|
|
|
—
|
|
|
—
|
|
|
187
|
|
|||||
Total expenses and other
|
4,216
|
|
|
1,159
|
|
|
740
|
|
|
(362
|
)
|
|
5,753
|
|
|||||
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement
|
—
|
|
|
—
|
|
|
4
|
|
|
—
|
|
|
4
|
|
|||||
Adjusted EBITDAX
|
$
|
10,612
|
|
|
$
|
663
|
|
|
$
|
(219
|
)
|
|
$
|
(226
|
)
|
|
$
|
10,830
|
|
Net properties and equipment
|
$
|
32,717
|
|
|
$
|
6,697
|
|
|
$
|
—
|
|
|
$
|
2,175
|
|
|
$
|
41,589
|
|
Capital expenditures
|
$
|
7,934
|
|
|
$
|
1,149
|
|
|
$
|
—
|
|
|
$
|
173
|
|
|
$
|
9,256
|
|
Goodwill
|
$
|
5,123
|
|
|
$
|
453
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
5,576
|
|
(1)
|
Total revenues and other excludes gains (losses) on divestitures, net since these gains and losses are excluded from Adjusted EBITDAX.
|
(2)
|
Operating costs and expenses excludes exploration expense, DD&A, impairments, restructuring charges, and other operating expense since these expenses are excluded from Adjusted EBITDAX.
|
(3)
|
Other (income) expense, net excludes certain other nonoperating items since these items are excluded from Adjusted EBITDAX.
|
|
Years Ended December 31,
|
||||||||||
millions
|
2016
|
|
2015
|
|
2014
|
||||||
Sales Revenues
|
|
|
|
|
|
||||||
United States
|
$
|
7,049
|
|
|
$
|
7,819
|
|
|
$
|
13,083
|
|
Algeria
|
1,103
|
|
|
1,189
|
|
|
2,435
|
|
|||
Other International
|
295
|
|
|
478
|
|
|
857
|
|
|||
Total sales revenues
|
$
|
8,447
|
|
|
$
|
9,486
|
|
|
$
|
16,375
|
|
|
December 31,
|
||||||
millions
|
2016
|
|
2015
|
||||
Net Properties and Equipment
|
|
|
|
||||
United States
|
$
|
28,024
|
|
|
$
|
29,625
|
|
Algeria
|
1,117
|
|
|
1,271
|
|
||
Other International
|
3,027
|
|
|
2,855
|
|
||
Total net properties and equipment
|
$
|
32,168
|
|
|
$
|
33,751
|
|
|
|
Oil
per Bbl
|
|
Natural Gas per MMBtu
|
|
NGLs
per Bbl
|
||||||
December 31, 2016
|
|
$
|
42.75
|
|
|
$
|
2.48
|
|
|
$
|
19.74
|
|
December 31, 2015
|
|
$
|
50.28
|
|
|
$
|
2.59
|
|
|
$
|
19.47
|
|
December 31, 2014
|
|
$
|
94.99
|
|
|
$
|
4.35
|
|
|
$
|
45.25
|
|
|
Oil
(MMBbls)
|
|
Natural Gas
(Bcf)
|
||||||||||||||
|
United States
|
|
International
|
|
Total
|
|
United States
|
|
International
|
|
Total
|
||||||
Proved Reserves
|
|
|
|
|
|
|
|
|
|
|
|
||||||
December 31, 2013
|
592
|
|
|
259
|
|
|
851
|
|
|
9,205
|
|
|
—
|
|
|
9,205
|
|
Revisions of prior estimates
|
167
|
|
|
18
|
|
|
185
|
|
|
710
|
|
|
31
|
|
|
741
|
|
Extensions, discoveries, and other additions
|
25
|
|
|
—
|
|
|
25
|
|
|
196
|
|
|
—
|
|
|
196
|
|
Purchases in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Sales in place
|
(6
|
)
|
|
(17
|
)
|
|
(23
|
)
|
|
(492
|
)
|
|
—
|
|
|
(492
|
)
|
Production
|
(74
|
)
|
|
(35
|
)
|
|
(109
|
)
|
|
(951
|
)
|
|
—
|
|
|
(951
|
)
|
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
|
|
Proved Developed Reserves
|
|
|
|
|
|
|
|
|
|
|
|
||||||
December 31, 2013
|
347
|
|
|
202
|
|
|
549
|
|
|
7,120
|
|
|
—
|
|
|
7,120
|
|
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
|
|
Proved Undeveloped Reserves
|
|
|
|
|
|
|
|
|
|
|
|
||||||
December 31, 2013
|
245
|
|
|
57
|
|
|
302
|
|
|
2,085
|
|
|
—
|
|
|
2,085
|
|
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
|
|
|
NGLs
(MMBbls)
|
|
Total
(MMBOE)
|
||||||||||||||
|
United States
|
|
International
|
|
Total
|
|
United States
|
|
International
|
|
Total
|
||||||
Proved Reserves
|
|
|
|
|
|
|
|
|
|
|
|
||||||
December 31, 2013
|
395
|
|
|
12
|
|
|
407
|
|
|
2,521
|
|
|
271
|
|
|
2,792
|
|
Revisions of prior estimates
(1)
|
129
|
|
|
2
|
|
|
131
|
|
|
414
|
|
|
25
|
|
|
439
|
|
Extensions, discoveries, and other additions
|
5
|
|
|
—
|
|
|
5
|
|
|
63
|
|
|
—
|
|
|
63
|
|
Purchases in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Sales in place
|
(19
|
)
|
|
—
|
|
|
(19
|
)
|
|
(107
|
)
|
|
(17
|
)
|
|
(124
|
)
|
Production
|
(44
|
)
|
|
(1
|
)
|
|
(45
|
)
|
|
(276
|
)
|
|
(36
|
)
|
|
(312
|
)
|
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
|
|
Proved Developed Reserves
|
|
|
|
|
|
|
|
|
|
|
|
||||||
December 31, 2013
|
268
|
|
|
—
|
|
|
268
|
|
|
1,801
|
|
|
202
|
|
|
2,003
|
|
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
|
|
Proved Undeveloped Reserves
|
|
|
|
|
|
|
|
|
|
|
|
||||||
December 31, 2013
|
127
|
|
|
12
|
|
|
139
|
|
|
720
|
|
|
69
|
|
|
789
|
|
December 31, 2014
|
162
|
|
|
—
|
|
|
162
|
|
|
853
|
|
|
36
|
|
|
889
|
|
December 31, 2015
|
68
|
|
|
—
|
|
|
68
|
|
|
396
|
|
|
29
|
|
|
425
|
|
December 31, 2016
|
75
|
|
|
—
|
|
|
75
|
|
|
383
|
|
|
14
|
|
|
397
|
|
(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
69
MMBOE for
2016
,
89
MMBOE for
2015
, and
577
MMBOE for
2014
.
|
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 increase of 74 MMBOE in proved reserves. Upward revisions of 102 MMBOE are 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 are 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 due primarily 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 are 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 is 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 is 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.
|
MMBOE
|
December 31, 2014
|
|
Revisions due to changes in year-end prices (price impact to opening balance)
|
(1
|
)
|
Other revisions of prior estimates
|
|
|
Revisions due to performance
|
42
|
|
Revisions due to successful infill drilling
|
577
|
|
Revisions due to development plan updates
|
(179
|
)
|
Total other revisions of prior estimates
|
440
|
|
Revisions of prior estimates
|
439
|
|
•
|
Performance
The Company experienced an increase in proved reserves primarily due to improved well performance in the DJ basin as well as in certain shale and international assets.
|
•
|
Infill drilling activities
The Company added 577 MMBOE of proved reserves associated with infill drilling primarily in large onshore areas such as the DJ basin and the Eagleford and Haynesville shales.
|
•
|
Development plan updates
The majority of the revisions associated with updates to development plans occurred in the DJ basin due to the optimization of horizontal drilling locations and the discontinuation of vertical well workover plans.
|
millions
|
United States
|
|
International
|
|
Total
|
||||||
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
|
|
December 31, 2015
|
|
|
|
|
|
||||||
Capitalized
|
|
|
|
|
|
||||||
Unproved properties
|
$
|
2,742
|
|
|
$
|
739
|
|
|
$
|
3,481
|
|
Proved properties
|
50,275
|
|
|
5,472
|
|
|
55,747
|
|
|||
|
53,017
|
|
|
6,211
|
|
|
59,228
|
|
|||
Less accumulated DD&A
|
31,366
|
|
|
2,281
|
|
|
33,647
|
|
|||
Net capitalized costs
|
$
|
21,651
|
|
|
$
|
3,930
|
|
|
$
|
25,581
|
|
millions
|
United States
|
|
International
|
|
Total
|
||||||
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
|
|
Year Ended December 31, 2014
|
|
|
|
|
|
||||||
Property acquisitions
|
|
|
|
|
|
||||||
Unproved
|
$
|
264
|
|
|
$
|
19
|
|
|
$
|
283
|
|
Proved
|
3
|
|
|
—
|
|
|
3
|
|
|||
Exploration
|
1,095
|
|
|
616
|
|
|
1,711
|
|
|||
Development
|
6,158
|
|
|
557
|
|
|
6,715
|
|
|||
Total costs incurred
|
$
|
7,520
|
|
|
$
|
1,192
|
|
|
$
|
8,712
|
|
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 general and administrative expenses
|
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
|
)
|
millions
|
United States
|
|
International
|
|
Total
|
||||||
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 general and administrative expenses
|
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
|
)
|
Year Ended December 31, 2014
|
|
|
|
|
|
||||||
Net revenues from production
|
|
|
|
|
|
||||||
Third-party sales
|
$
|
7,425
|
|
|
$
|
1,518
|
|
|
$
|
8,943
|
|
Sales to consolidated affiliates
|
4,453
|
|
|
1,773
|
|
|
6,226
|
|
|||
Gains (losses) on property dispositions
|
(91
|
)
|
|
1,982
|
|
|
1,891
|
|
|||
|
11,787
|
|
|
5,273
|
|
|
17,060
|
|
|||
Production costs
|
|
|
|
|
|
||||||
Oil and gas operating
|
968
|
|
|
203
|
|
|
1,171
|
|
|||
Oil and gas transportation
|
1,084
|
|
|
33
|
|
|
1,117
|
|
|||
Production-related general and administrative expenses
|
394
|
|
|
32
|
|
|
426
|
|
|||
Production, property, and other taxes
|
652
|
|
|
535
|
|
|
1,187
|
|
|||
|
3,098
|
|
|
803
|
|
|
3,901
|
|
|||
Exploration expenses
|
1,218
|
|
|
421
|
|
|
1,639
|
|
|||
DD&A
|
3,783
|
|
|
398
|
|
|
4,181
|
|
|||
Impairments related to oil and gas properties
|
821
|
|
|
—
|
|
|
821
|
|
|||
Other operating expense
|
163
|
|
|
—
|
|
|
163
|
|
|||
|
2,704
|
|
|
3,651
|
|
|
6,355
|
|
|||
Income tax expense (benefit)
|
995
|
|
|
979
|
|
|
1,974
|
|
|||
Results of operations
|
$
|
1,709
|
|
|
$
|
2,672
|
|
|
$
|
4,381
|
|
millions
|
United States
|
|
International
|
|
Total
|
||||||
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
|
|
December 31, 2014
|
|
|
|
|
|
||||||
Future cash inflows
|
$
|
114,384
|
|
|
$
|
23,795
|
|
|
$
|
138,179
|
|
Future production costs
|
36,390
|
|
|
6,061
|
|
|
42,451
|
|
|||
Future development costs
|
14,794
|
|
|
1,356
|
|
|
16,150
|
|
|||
Future income tax expenses
|
21,813
|
|
|
6,968
|
|
|
28,781
|
|
|||
Future net cash flows
|
41,387
|
|
|
9,410
|
|
|
50,797
|
|
|||
10% annual discount for estimated timing of cash flows
|
17,239
|
|
|
2,898
|
|
|
20,137
|
|
|||
Standardized measure of discounted future net cash flows
|
$
|
24,148
|
|
|
$
|
6,512
|
|
|
$
|
30,660
|
|
millions
|
United States
|
|
International
|
|
Total
|
||||||
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
|
|
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
|
|
millions
|
United States
|
|
International
|
|
Total
|
||||||
2014
|
|
|
|
|
|
||||||
Balance at January 1
|
$
|
21,169
|
|
|
$
|
7,937
|
|
|
$
|
29,106
|
|
Sales and transfers of oil and gas produced, net of production costs
|
(8,780
|
)
|
|
(2,492
|
)
|
|
(11,272
|
)
|
|||
Net changes in prices and production costs
|
(3,981
|
)
|
|
(1,984
|
)
|
|
(5,965
|
)
|
|||
Changes in estimated future development costs
|
(4,180
|
)
|
|
(250
|
)
|
|
(4,430
|
)
|
|||
Extensions, discoveries, additions, and improved recovery, less related costs
|
963
|
|
|
—
|
|
|
963
|
|
|||
Development costs incurred during the period
|
2,591
|
|
|
279
|
|
|
2,870
|
|
|||
Revisions of previous quantity estimates
|
13,703
|
|
|
1,921
|
|
|
15,624
|
|
|||
Purchases of minerals in place
|
—
|
|
|
—
|
|
|
—
|
|
|||
Sales of minerals in place
|
(591
|
)
|
|
(696
|
)
|
|
(1,287
|
)
|
|||
Accretion of discount
|
3,221
|
|
|
1,341
|
|
|
4,562
|
|
|||
Net change in income taxes
|
(1,294
|
)
|
|
549
|
|
|
(745
|
)
|
|||
Other
|
1,327
|
|
|
(93
|
)
|
|
1,234
|
|
|||
Balance at December 31
|
$
|
24,148
|
|
|
$
|
6,512
|
|
|
$
|
30,660
|
|
millions except per-share amounts
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
||||||||
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
|
|
||||
|
|
|
|
|
|
|
|
||||||||
2015
|
|
|
|
|
|
|
|
||||||||
Sales revenues
|
$
|
2,585
|
|
|
$
|
2,637
|
|
|
$
|
2,230
|
|
|
$
|
2,034
|
|
Gains (losses) on divestitures and other, net
|
(264
|
)
|
|
(1
|
)
|
|
(542
|
)
|
|
19
|
|
||||
Impairments
|
2,783
|
|
|
30
|
|
|
758
|
|
|
1,504
|
|
||||
Operating income (loss)
|
(4,208
|
)
|
|
90
|
|
|
(2,549
|
)
|
|
(2,142
|
)
|
||||
Net income (loss)
|
(3,236
|
)
|
|
108
|
|
|
(2,160
|
)
|
|
(1,524
|
)
|
||||
Net income (loss) attributable to noncontrolling interests
|
32
|
|
|
47
|
|
|
75
|
|
|
(274
|
)
|
||||
Net income (loss) attributable to common stockholders
|
(3,268
|
)
|
|
61
|
|
|
(2,235
|
)
|
|
(1,250
|
)
|
||||
Earnings per share
|
|
|
|
|
|
|
|
||||||||
Net income (loss) attributable to common stockholders—basic
|
$
|
(6.45
|
)
|
|
$
|
0.12
|
|
|
$
|
(4.41
|
)
|
|
$
|
(2.45
|
)
|
Net income (loss) attributable to common stockholders—diluted
|
$
|
(6.45
|
)
|
|
$
|
0.12
|
|
|
$
|
(4.41
|
)
|
|
$
|
(2.45
|
)
|
Average number common shares outstanding—basic
|
507
|
|
|
508
|
|
|
508
|
|
|
508
|
|
||||
Average number common shares outstanding—diluted
|
507
|
|
|
509
|
|
|
508
|
|
|
508
|
|
(1)
|
The Consolidated Financial Statements of Anadarko Petroleum Corporation are listed on the Index to this Form 10-K, page 82.
|
(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)
|
|
Agreement and Plan of Merger dated as of June 22, 2006, among Anadarko Petroleum Corporation, APC Acquisition Sub, Inc. and Kerr-McGee Corporation, filed as Exhibit 2.2 to Form 8-K filed on June 26, 2006
|
|
3
|
(i)
|
|
Restated Certificate of Incorporation of Anadarko Petroleum Corporation, dated May 21, 2009, filed as Exhibit 3.3 to Form 8-K filed on May 22, 2009
|
|
|
(ii)
|
|
By-Laws of Anadarko Petroleum Corporation, amended and restated as of September 15, 2015, filed as Exhibit 3.1 to Form 8-K filed on September 21, 2015
|
|
4
|
(i)
|
|
Trustee Indenture, dated as of September 19, 2006, Anadarko Petroleum Corporation to The Bank of New York Trust Company, N.A., filed as Exhibit 4.1 to Form 8-K filed on September 19, 2006
|
|
|
(ii)
|
|
Third Supplemental Indenture, dated as of June 10, 2015, between Anadarko Petroleum Corporation and The Bank of New York Mellon Trust Company, N.A., filed as Exhibit 4.2 to Form 8-K filed on June 10, 2015
|
|
|
(iii)
|
|
Second Supplemental Indenture dated October 4, 2006, among Anadarko Petroleum Corporation, Kerr-McGee Corporation, and Citibank, N.A., filed as Exhibit 4.1 to Form 8-K filed on October 6, 2006
|
|
|
(iv)
|
|
Ninth Supplemental Indenture dated October 4, 2006, among Anadarko Petroleum Corporation, Kerr-McGee Corporation, and Citibank, N.A., filed as Exhibit 4.2 to Form 8-K filed on October 6, 2006
|
|
|
(v)
|
|
Officers’ Certificate of Anadarko Petroleum Corporation, dated March 2, 2009, establishing the 7.625% Senior Notes due 2014 and the 8.700% Senior Notes due 2019, filed as Exhibit 4.1 to Form 8-K filed on March 6, 2009
|
|
|
(vi)
|
|
Form of 8.700% Senior Notes due 2019, filed as Exhibit 4.3 to Form 8-K filed on March 6, 2009
|
|
|
(vii)
|
|
Officers’ Certificate of Anadarko Petroleum Corporation, dated June 9, 2009, establishing the 5.75% Senior Notes due 2014, the 6.95% Senior Notes due 2019 and the 7.95% Senior Notes due 2039, filed as Exhibit 4.1 to Form 8-K filed on June 12, 2009
|
|
|
(viii)
|
|
Form of 6.95% Senior Notes due 2019, filed as Exhibit 4.3 to Form 8-K filed on June 12, 2009
|
|
|
(ix)
|
|
Form of 7.95% Senior Notes due 2039, filed as Exhibit 4.4 to Form 8-K filed on June 12, 2009
|
|
|
(x)
|
|
Officers’ Certificate of Anadarko Petroleum Corporation dated March 9, 2010, establishing the 6.200% Senior Notes due 2040, filed as Exhibit 4.1 to Form 8-K filed on March 16, 2010
|
Exhibit
Number
|
|
Description
|
||
|
4
|
(xi)
|
|
Form of 6.200% Senior Notes due 2040, filed as Exhibit 4.2 to Form 8-K filed on March 16, 2010
|
|
|
(xii)
|
|
Officers’ Certificate of Anadarko Petroleum Corporation dated August 9, 2010, establishing the 6.375% Senior Notes due 2017, filed as Exhibit 4.1 to Form 8-K filed on August 12, 2010
|
|
|
(xiii)
|
|
Form of 6.375% Senior Notes due 2017, filed as Exhibit 4.2 to Form 8-K filed on August 12, 2010
|
|
|
(xiv)
|
|
Officers’ Certificate of Anadarko Petroleum Corporation dated July 7, 2014, establishing the 3.45% Senior Notes due 2024 and the 4.50% Senior Notes due 2044, filed as Exhibit 4.1 to Form 8-K filed on July 7, 2014
|
|
|
(xv)
|
|
Form of 3.45% Senior Notes due 2024, filed as Exhibit 4.2 to Form 8-K filed on July 7, 2014
|
|
|
(xvi)
|
|
Form of 4.50% Senior Notes due 2044, filed as Exhibit 4.3 to Form 8-K filed on July 7, 2014
|
|
|
(xvii)
|
|
Purchase Contract Agreement, dated June 10, 2015, between Anadarko Petroleum Corporation and The Bank of New York Mellon Trust Company, N.A., filed as Exhibit 4.1 to Form 8-K filed on June 10, 2015
|
|
|
(xviii)
|
|
Form of Unit (included in Exhibit 4.xvii)
|
|
|
(xix)
|
|
Form of Purchase Contract (included in Exhibit 4.xvii)
|
|
|
(xx)
|
|
Form of Amortizing Note (included in Exhibit 4.ii)
|
|
|
(xxi)
|
|
Officers’ Certificate of Anadarko Petroleum Corporation dated March 17, 2016, establishing the 4.85% Senior Notes due 2021 and the 5.55% Senior Notes due 2026, and the 6.60% Senior Notes due 2046, filed as Exhibit 4.1 to Form 8-K filed on March 17, 2016
|
|
|
(xxii)
|
|
Form of 4.85% Senior Notes due 2021, filed as Exhibit 4.2 to Form 8-K filed on March 17, 2016
|
|
|
(xxiii)
|
|
Form of 5.55% Senior Notes due 2026, filed as Exhibit 4.3 to Form 8-K filed on March 17, 2016
|
|
|
(xxiv)
|
|
Form of 6.60% Senior Notes due 2046, filed as Exhibit 4.4 to Form 8-K filed on March 17, 2016
|
†
|
10
|
(i)
|
|
1998 Director Stock Plan of Anadarko Petroleum Corporation, effective January 30, 1998, filed as Appendix A to DEF 14A filed on March 16, 1998
|
†
|
|
(ii)
|
|
Form of Anadarko Petroleum Corporation 1998 Director Stock Plan Stock Option Agreement, filed as Exhibit 10.1 to Form 8-K filed on November 17, 2005
|
†
|
|
(iii)
|
|
Anadarko Petroleum Corporation Amended and Restated 1999 Stock Incentive Plan, filed as Appendix A to DEF 14A filed on March 18, 2005
|
†
|
|
(iv)
|
|
Form of Anadarko Petroleum Corporation Executive 1999 Stock Incentive Plan Stock Option Agreement, filed as Exhibit 10.2 to Form 8-K filed on November 17, 2005
|
†
|
|
(v)
|
|
Form of Anadarko Petroleum Corporation Non-Executive 1999 Stock Incentive Plan Stock Option Agreement, filed as Exhibit 10.3 to Form 8-K filed on November 17, 2005
|
†
|
|
(vi)
|
|
Form of Stock Option Agreement—1999 Stock Incentive Plan (UK Nationals), filed as Exhibit 10.4 to Form 8-K filed on November 17, 2005
|
†
|
|
(vii)
|
|
Amendment to Stock Option Agreement Under the Anadarko Petroleum Corporation 1999 Stock Incentive Plan, filed as Exhibit 10.1 to Form 8-K filed on January 23, 2007
|
†
|
|
(viii)
|
|
Anadarko Petroleum Corporation 1999 Stock Incentive Plan (Amendment to Performance Unit Agreement), filed as Exhibit 10.3 to Form 8-K filed on November 13, 2007
|
†
|
|
(ix)
|
|
Form of Anadarko Petroleum Corporation 1999 Stock Incentive Plan Restricted Stock Agreement, filed as Exhibit 10(b)(xxiv) to Form 10-K for year ended December 31, 1999, filed on March 16, 2000
|
†
|
|
(x)
|
|
Form of Anadarko Petroleum Corporation 1999 Stock Incentive Plan Restricted Stock Unit Award Letter, filed as Exhibit 10.1 to Form 8-K filed on November 13, 2007
|
Exhibit
Number
|
|
Description
|
||
†
|
10
|
(xi)
|
|
The Approved UK Sub-Plan of the Anadarko Petroleum Corporation 1999 Stock Incentive Plan, filed as Exhibit 10(b)(xxiv) to Form 10-K for year ended December 31, 2003, filed on March 4, 2004
|
†
|
|
(xii)
|
|
Key Employee Change of Control Contract, filed as Exhibit 10(b)(xxii) to Form 10-K for year ended December 31, 1997, filed on March 18, 1998
|
†
|
|
(xiii)
|
|
First Amendment to Anadarko Petroleum Corporation Key Employee Change of Control Contract, filed as Exhibit 10(b) to Form 10-Q for quarter ended September 30, 2000, filed on November 13, 2000
|
†
|
|
(xiv)
|
|
Form of Amendment to Anadarko Petroleum Corporation Key Employee Change of Control Contract, filed as Exhibit 10(b)(ii) to Form 10-Q for quarter ended June 30, 2003, filed on August 11, 2003
|
†
|
|
(xv)
|
|
Form of Key Employee Change of Control Contract (2011), filed as Exhibit 10(i) to Form 10-Q for quarter ended June 30, 2011, filed on July 27, 2011
|
†
|
|
(xvi)
|
|
Form of Amendment to Anadarko Petroleum Corporation Key Employee Change of Control Contract (Applicable to Vice Presidents Other Than Executive Officers as of October 2013), filed as Exhibit 10(ii) to Form 10-Q for quarter ended March 31, 2015, filed on May 4, 2015
|
†*
|
|
(xvii)
|
|
Form of Anadarko Petroleum Corporation Key Employee Change of Control Contract for Executive Vice Presidents
|
†
|
|
(xviii)
|
|
Letter Agreement regarding Post-Retirement Benefits, dated February 16, 2004—Robert J. Allison, Jr., filed as Exhibit 10(b)(xxxiv) to Form 10-K for year ended December 31, 2003, filed on March 4, 2004
|
†
|
|
(xix)
|
|
Anadarko Petroleum Corporation Savings Restoration Plan (As Amended and Restated Effective January 1, 2007), filed as Exhibit 10(xxii) to Form 10-K for year ended December 31, 2009, filed on February 23, 2010
|
†
|
|
(xx)
|
|
First Amendment, dated July 1, 2010, to the Anadarko Petroleum Corporation Savings Restoration Plan (As Amended and Restated Effective January 1, 2007), filed as Exhibit 10(xviii) to Form 10-K for year ended December 31, 2014, filed on February 20, 2015
|
†
|
|
(xxi)
|
|
Second Amendment, dated November 30, 2011, to the Anadarko Petroleum Corporation Savings Restoration Plan (As Amended and Restated Effective January 1, 2007), filed as Exhibit 10(xix) to Form 10-K for year ended December 31, 2014, filed on February 20, 2015
|
†
|
|
(xxii)
|
|
Third Amendment, dated December 18, 2014, to the Anadarko Petroleum Corporation Savings Restoration Plan (As Amended and Restated Effective January 1, 2007), filed as Exhibit 10(xx) to Form 10-K for year ended December 31, 2014, filed on February 20, 2015
|
†
|
|
(xxiii)
|
|
Anadarko Retirement Restoration Plan (As Amended and Restated Effective as of November 7, 2007), filed as Exhibit 10.2 to Form 8-K filed on November 13, 2007
|
†
|
|
(xxiv)
|
|
First Amendment, dated November 30, 2011, to the Anadarko Retirement Restoration Plan (As Amended and Restated Effective January 1, 2007), filed as Exhibit 10(xxii) to Form 10-K for year ended December 31, 2014, filed on February 20, 2015
|
†
|
|
(xxv)
|
|
Anadarko Petroleum Corporation Estate Enhancement Program, filed as Exhibit 10(b)(xxxiv) to Form 10-K for year ended December 31, 1998, filed on March 15, 1999
|
†
|
|
(xxvi)
|
|
Estate Enhancement Program Agreement between Anadarko Petroleum Corporation and Eligible Executives, filed as Exhibit 10(b)(xxxv) to Form 10-K for year ended December 31, 1998, filed on March 15, 1999
|
†
|
|
(xxvii)
|
|
Estate Enhancement Program Agreements effective November 29, 2000, filed as Exhibit 10(b)(xxxxii) to Form 10-K for year ended December 31, 2000, filed on March 15, 2001
|
†
|
|
(xxviii)
|
|
Anadarko Petroleum Corporation Management Life Insurance Plan, restated November 1, 2002, filed as Exhibit 10(b)(xxxii) to Form 10-K for year ended December 31, 2002, filed on March 14, 2003
|
Exhibit
Number
|
|
Description
|
||
†
|
10
|
(xxix)
|
|
First Amendment to Anadarko Petroleum Corporation Management Life Insurance Plan, effective June 30, 2003, filed as Exhibit 10(b)(xliii) to Form 10-K for year ended December 31, 2003, filed on March 4, 2004
|
†
|
|
(xxx)
|
|
Second Amendment to Anadarko Petroleum Corporation Management Life Insurance Plan, effective January 1, 2008, filed as Exhibit 10(xxix) to Form 10-K for year ended December 31, 2009, filed on February 23, 2010
|
†
|
|
(xxxi)
|
|
Anadarko Petroleum Corporation Officer Severance Plan, filed as Exhibit 10(b)(iv) to Form 10-Q for quarter ended September 30, 2003, filed on November 12, 2003
|
†
|
|
(xxxii)
|
|
Form of Termination Agreement and Release of All Claims Under Officer Severance Plan, filed as Exhibit 10.1 to Form 8-K filed on August 24, 2016
|
†
|
|
(xxxiii)
|
|
Form of Director and Officer Indemnification Agreement, filed as Exhibit 10 to Form 8-K filed on September 3, 2004
|
†
|
|
(xxxiv)
|
|
Anadarko Petroleum Corporation 2008 Omnibus Incentive Compensation Plan, effective as of May 20, 2008, filed as Exhibit 10.1 to Form 8-K filed on May 27, 2008
|
†
|
|
(xxxv)
|
|
Form of Anadarko Petroleum Corporation 2008 Omnibus Incentive Compensation Plan Stock Option Award Agreement, filed as Exhibit 10.3 to Form 8-K filed on November 13, 2009
|
†
|
|
(xxxvi)
|
|
Form of Anadarko Petroleum Corporation 2008 Omnibus Incentive Compensation Plan Restricted Stock Unit Award Agreement, filed as Exhibit 10.1 to Form 8-K filed on November 13, 2009
|
†
|
|
(xxxvii)
|
|
Form of Anadarko Petroleum Corporation 2008 Omnibus Incentive Compensation Plan Performance Unit Award Agreement, filed as Exhibit 10.2 to Form 8-K filed on November 13, 2009
|
†
|
|
(xxxviii)
|
|
Anadarko Petroleum Corporation 2008 Director Compensation Plan, effective as of May 20, 2008, filed as Exhibit 10.2 to Form 8-K filed on May 27, 2008
|
†
|
|
(xxxix)
|
|
First Amendment to Anadarko Petroleum Corporation 2008 Director Compensation Plan, dated February 8, 2016, filed as Exhibit 10(xli) to Form 10-K for year ended December 31, 2015, filed on February 17, 2016
|
†
|
|
(xl)
|
|
Form of Award Letter for Anadarko Petroleum Corporation 2008 Director Compensation Plan, filed as Exhibit 10.3 to Form 8-K filed on May 27, 2008
|
†
|
|
(xli)
|
|
Form of Award Letter for Anadarko Petroleum Corporation 2008 Director Compensation Plan (2013), filed as Exhibit 10(i) to Form 10-Q for quarter ended June 30, 2013, filed on July 29, 2013
|
†
|
|
(xlii)
|
|
Form of Award Letter for Anadarko Petroleum Corporation 2008 Director Compensation Plan Annual Deferred Shares (2016), filed as Exhibit 10(iii) to Form 10-Q for quarter ended March 31, 2016, filed on May 2, 2016
|
†
|
|
(xliii)
|
|
Terms and Conditions of Elective Deferred Share Awards for Anadarko Petroleum Corporation 2008 Director Compensation Plan, filed as Exhibit 10(iv) to Form 10-Q for quarter ended March 31, 2016, filed on May 2, 2016
|
†
|
|
(xliv)
|
|
Anadarko Petroleum Corporation Deferred Compensation Plan (as amended and restated effective as of January 1, 2012), filed as Exhibit 10(i) to Form 10-Q for quarter ended June 30, 2014, filed on July 29, 2014
|
†
|
|
(xlv)
|
|
First Amendment, dated December 17, 2013, to the Anadarko Petroleum Corporation Deferred Compensation Plan (as amended and restated effective as of January 1, 2012), filed as Exhibit 10(ii) to Form 10-Q for quarter ended June 30, 2014, filed on July 29, 2014
|
|
|
(xlvi)
|
|
Operating Agreement, dated October 1, 2009, between BP Exploration & Production Inc., as Operator, and MOEX Offshore 2007 LLC, as Non-Operator, as ratified by that certain Ratification and Joinder of Operating Agreement, dated December 17, 2009, by and among BP Exploration & Production Inc., Anadarko Petroleum Corporation (as Non-Operator), Anadarko E&P Company LP (as predecessor in interest to Anadarko Petroleum Corporation), and MOEX Offshore 2007 LLC, together with material exhibits, filed as Exhibit 10 to Form 10-Q for quarter ended June 30, 2010, filed on August 3, 2010
|
Exhibit
Number
|
|
Description
|
||
|
10
|
(xlvii)
|
|
Confidential Settlement Agreement, Mutual Releases and Agreement to Indemnify, dated October 16, 2011, by and among BP Exploration & Production Inc., Anadarko Petroleum Corporation, Anadarko E&P Company LP, BP Corporation North America Inc. and BP p.l.c., filed as Exhibit 10(xlii) to Form 10-K for year ended December 31, 2011, filed on February 21, 2012 (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment)
|
†
|
|
(xlviii)
|
|
Severance Agreement between R. A. Walker and Anadarko Petroleum Corporation, dated February 16, 2012, filed as Exhibit 10.2 to Form 8-K filed on February 21, 2012
|
†
|
|
(xlix)
|
|
Time Sharing Agreement between R. A. Walker and Anadarko Petroleum Corporation, dated May 15, 2012, filed as Exhibit 10(ii) to Form 10-Q for quarter ended June 30, 2012, filed on August 8, 2012
|
†
|
|
(l)
|
|
First Amendment to Time Sharing Agreement between R. A. Walker and Anadarko Petroleum Corporation, dated June 2, 2015, filed as Exhibit 10(ii) to Form 10-Q for quarter ended June 30, 2015, filed on July 28, 2015
|
†
|
|
(li)
|
|
Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan, effective as of May 15, 2012, filed as Exhibit 10.1 to Form 8-K filed on May 15, 2012
|
†
|
|
(lii)
|
|
Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan, as Amended and Restated Effective as of May 10, 2016, filed as Exhibit 10.1 to Form 8-K filed on May 16, 2016
|
†
|
|
(liii)
|
|
Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Stock Option Award Agreement, filed as Exhibit 10.2 to Form 8-K filed on May 15, 2012
|
†
|
|
(liv)
|
|
Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Restricted Stock Unit Award Agreement, filed as Exhibit 10.3 to Form 8-K filed on May 15, 2012
|
†
|
|
(lv)
|
|
Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Performance Unit Award Agreement, filed as Exhibit 10.4 to Form 8-K filed on May 15, 2012
|
†
|
|
(lvi)
|
|
Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Restricted Stock Unit Award Agreement, filed as Exhibit 10.1 to Form 8-K filed on November 9, 2012
|
†
|
|
(lvii)
|
|
Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Performance Unit Award Agreement, filed as Exhibit 10.2 to Form 8-K filed on November 9, 2012
|
†
|
|
(lviii)
|
|
Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan Performance Unit Award Agreement (2014), filed as Exhibit 10.1 to Form 8-K filed on November 10, 2014
|
†
|
|
(lix)
|
|
Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan, as Amended and Restated Effective as of May 10, 2016, Stock Option Award Agreement, filed as Exhibit 10(i) to Form 10-Q for quarter ended September 30, 2016, filed on October 31, 2016
|
†
|
|
(lx)
|
|
Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan, as Amended and Restated Effective as of May 10, 2016, Restricted Stock Unit Award Agreement, filed as Exhibit 10(ii) to Form 10-Q for quarter ended September 30, 2016, filed on October 31, 2016
|
†
|
|
(lxi)
|
|
Form of Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan, as Amended and Restated Effective as of May 10, 2016, Performance Unit Award Agreement, filed as Exhibit 10(iii) to Form 10-Q for quarter ended September 30, 2016, filed on October 31, 2016
|
†
|
|
(lxii)
|
|
Form of U.K. Award Letter for Anadarko Petroleum Corporation 2008 Director Compensation Plan, filed as Exhibit 10.5 to Form 8-K filed on May 15, 2012
|
†
|
|
(lxiii)
|
|
Amended and Restated Performance Unit Award Agreement, effective November 5, 2012, for R. A. Walker, filed as Exhibit 10.3 to Form 8-K filed on November 9, 2012
|
Exhibit
Number
|
|
Description
|
||
|
10
|
(lxiv)
|
|
Settlement Agreement dated as of April 3, 2014, by and among (1) the Anadarko Litigation Trust, (2) the United States of America in its capacity as plaintiff-intervenor in the Tronox Adversary Proceeding and acting for and on behalf of certain U.S. government agencies and (3) Anadarko Petroleum Corporation, Kerr-McGee Corporation, and certain other subsidiaries, filed as Exhibit 10.1 to Form 8-K filed on April 3, 2014
|
|
|
(lxv)
|
|
Credit Agreement, dated as of June 17, 2014, among Anadarko Petroleum Corporation, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, Wells Fargo Bank, National Association, as Syndication Agent, Bank of America, N.A., Citibank, N.A., The Royal Bank of Scotland plc, and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Co-Documentation Agents, and the additional lenders party thereto, filed as Exhibit 10.1 to Form 8-K filed on June 23, 2014
|
|
|
(lxvi)
|
|
First Amendment to Credit Agreement, dated November 14, 2014, among Anadarko Petroleum Corporation, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto, filed as Exhibit 10.1 to Form 8-K filed on November 19, 2014
|
|
|
(lxvii)
|
|
Amendment and Maturity Extension Agreement, dated December 14, 2015, among Anadarko Petroleum Corporation, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto, filed as Exhibit 10.1 to Form 8-K filed on December 18, 2015
|
|
|
(lxviii)
|
|
Form of Commercial Paper Dealer Agreement for Commercial Paper Program, filed as Exhibit 10.1 to Form 8-K filed on January 21, 2015
|
†
|
|
(lxix)
|
|
Anadarko Petroleum Corporation Key Employee Change of Control Contract, dated June 1, 2015, for Christopher O. Champion, filed as Exhibit 10(i) to Form 10-Q for quarter ended June 30, 2015, filed on July 28, 2015
|
|
|
(lxx)
|
|
364-Day Revolving Credit Agreement, dated as of January 19, 2016, among Anadarko Petroleum Corporation, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, Wells Fargo Bank, National Association, as Syndication Agent, Bank of America, N.A., The Bank of Tokyo-Mitsubishi UFJ, Ltd., Citibank, N.A., and Mizuho Bank, Ltd., as Co-Documentation Agents, and the additional lenders party thereto, filed as Exhibit 10.1 to Form 8-K filed on January 25, 2016
|
|
|
(lxxi)
|
|
First Amendment to 364-Day Revolving Credit Agreement, dated January 13, 2017, among Anadarko Petroleum Corporation, JPMorgan Chase Bank, N.A., as administrative agent, and the additional lenders party thereto, filed as Exhibit 10.1 to Form 8-K filed on January 20, 2017
|
†*
|
|
(lxxii)
|
|
Retention Agreement, dated as of November 1, 2015, between Anadarko Petroleum Corporation and Mitchell W. Ingram
|
†*
|
|
(lxxiii)
|
|
First Amendment to Retention Agreement, dated December 13, 2016
|
*
|
12
|
|
|
Computation of Ratios of Earnings to Fixed Charges
|
*
|
21
|
|
|
List of Subsidiaries
|
*
|
23
|
(i)
|
|
Consent of KPMG LLP
|
*
|
23
|
(ii)
|
|
Consent of Miller and Lents, Ltd.
|
*
|
24
|
|
|
Power of Attorney
|
*
|
31
|
(i)
|
|
Rule 13a-14(a)/15d-14(a) Certification—Chief Executive Officer
|
*
|
31
|
(ii)
|
|
Rule 13a-14(a)/15d-14(a) Certification—Chief Financial Officer
|
**
|
32
|
|
|
Section 1350 Certifications
|
*
|
99
|
|
|
Report of Miller and Lents, Ltd.
|
*
|
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 17, 2017
|
By:
|
|
/s/ ROBERT G. GWIN
|
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Robert G. Gwin
Executive Vice President, Finance and Chief Financial Officer
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By:
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/s/ ROBERT G. GWIN
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Robert G. Gwin, Attorney-in-Fact
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ANADARKO PETROLEUM CORPORATION
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By:
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/s/ R. A. Walker
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Name:
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R. A. Walker
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Title:
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Chairman, President and Chief
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Executive Officer
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EXECUTIVE
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/s/ Mitch W. Ingram
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Mitchell W. Ingram
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ANADARKO PETROLEUM CORPORATION
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By:
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/s/ R. A. Walker
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Name:
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R. A. Walker
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Title:
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Chairman, President and Chief
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Executive Officer
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EXECUTIVE
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/s/ Mitch W. Ingram
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Mitchell W. Ingram
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(A)
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the sum of the amounts described in clauses (1), (2) and (3) of this Section 6(a)(i)(A) (which sum shall be hereinafter referred to as the “
Accrued Obligations
”):
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(B)
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an amount equal to the product of (1) 2.5 and (2) the sum of (x) the Executive’s Annual Base Salary in effect immediately prior to the Date of Termination and (y) the greater of (I) the average of the annual bonuses earned by the Executive for the two most recently completed fiscal years ending prior to the Date of Termination (in each case, including any bonus or portion thereof which has been earned but deferred) under the Company’s Annual Incentive Bonus Program or any comparable predecessor or successor plan and (II) the Executive’s target annual bonus for the year in which the Date of Termination occurs (which target annual bonus shall be deemed to be equal to the product of the amounts described in clauses (x), (y) and (z)(I) of
Section 6(a)(i)(A)(3)
); and
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(C)
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an amount equal to the total value of the Executive’s Account (as defined in the Company’s Savings Restoration Plan (the “
SRP
”)), with such amount being the higher of (1) the value of the Executive’s Account on the Executive’s Date of Termination or (2) the value of the Executive’s Account on the Change of Control Date, in each case with “value” determined under the applicable change of control provisions in the SRP, if any. The amount payable under this
Section 6(a)(i)(C)
shall represent the payment of the amount due to the Executive under the SRP, and shall not be duplicative thereof. Notwithstanding the above provisions of this
Section 6(a)(i)(C)
, the Company shall pay the lump sum cash payment as set forth herein above only if such payment would not be considered to be an impermissible acceleration of benefits under the SRP under Code Section 409A. In the event that the payment of the benefits payment in a lump sum would constitute an impermissible acceleration of benefits under the SRP under Code Section 409A, then the portion
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(D)
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an amount equal to the additional Company matching contributions which would have been made on the Executive’s behalf in the Company’s Employee Savings Plan (the “
ESP
”) (assuming continued participation on the same basis as immediately prior to the Change of Control Date), plus the additional amount of any benefit the Executive would have accrued under the SRP as a result of contribution limitations in the ESP, for the 36-month period beginning on the Date of Termination (with the Company’s matching contributions being determined pursuant to the applicable provisions of the ESP and the SRP and based upon the Executive’s compensation (including any amounts deferred pursuant to any deferred compensation program) in effect for the 12-month period immediately prior to the Change of Control Date); and
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(E)
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an amount equal to the sum of the present values, as of the Date of Termination, of (1) the accrued retirement benefit payable under the Company’s Retirement Restoration Plan (or, if the Executive participates in another plan that, in the sole determination of the Company, is intended to provide benefits similar to those under the Company’s Retirement Restoration Plan, such other plan) (each referred to herein as the “
RRP
”) and (2) the additional retirement benefits that the Executive would have accrued under the tax-qualified defined benefit plan of the Company or any Affiliate in which the Executive participates (the “
Retirement Plan
”) and the RRP if the Executive had continued employment until the expiration of the three-year period following the Date of Termination (assuming that the Executive’s compensation in each of the additional years is that required by
Section 4(b)(i) and Section 4(b)(ii)
hereof), with the present values being computed by discounting to the Date of Termination the accrued benefit and the additional retirement benefits payable as lump sums at an assumed benefit commencement date of the later of (i) the date the Executive attains age 55 and (ii) the date three years after the Date of Termination, at the rate of interest used for valuing lump-sum payments in excess of $25,000 for participants with retirement benefits commencing immediately under the Retirement Plan, as in effect as of the Change of Control Date with such amount to be fully offset and reduced by the amount of any additional benefit provided under the Retirement Plan or the RRP in connection with the Change of Control or the Executive’s termination of employment in
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EXECUTIVE
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By:
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Name:
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Date:
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ANADARKO PETROLEUM CORPORATION
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By:
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Name:
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Title:
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Date:
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Years Ended December 31,
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||||||||||||||||||
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(Unaudited)
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||||||||||||||||||
millions except ratio amounts
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2016
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2015
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2014
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2013
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2012
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||||||||||||
Income (loss) from continuing operations before income taxes
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$
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(3,829
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)
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$
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(9,689
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)
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$
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54
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$
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2,106
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$
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3,565
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Equity (income) adjustment
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(120
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)
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(86
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)
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(119
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)
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(64
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)
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(110
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)
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|||||||
Fixed charges
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1,337
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1,240
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1,245
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1,173
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1,209
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Amortization of capitalized interest
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82
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74
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61
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46
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17
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|||||||
Distributed income of equity investees
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141
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105
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121
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25
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33
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|||||||
Capitalized interest
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(132
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)
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(164
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)
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(201
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)
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(263
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)
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(221
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)
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Preference security dividend requirements of consolidated subsidiaries
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(105
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—
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—
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—
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—
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Non-controlling interest in pre-tax income of subsidiaries that have not incurred fixed charges
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(11
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)
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(21
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)
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(14
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)
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(11
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(10
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)
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Total Earnings
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$
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(2,637
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)
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$
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(8,541
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)
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$
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1,147
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$
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3,012
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$
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4,483
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Interest expense including capitalized interest
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1,043
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990
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974
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930
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954
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Interest expense included in other (income) expense
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49
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37
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36
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37
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42
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Estimated interest portion of rental expenditures
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140
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213
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235
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206
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213
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Preference security dividend requirements of consolidated subsidiaries
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105
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—
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—
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—
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—
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Total Fixed Charges
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$
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1,337
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$
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1,240
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$
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1,245
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$
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1,173
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$
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1,209
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Preferred Stock Dividends
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—
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—
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—
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—
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—
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Combined Fixed Charges and Preferred Stock Dividends
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$
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1,337
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$
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1,240
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$
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1,245
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$
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1,173
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$
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1,209
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Ratio of Earnings to Fixed Charges
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*
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*
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*
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2.57
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3.71
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Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends
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*
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*
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*
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2.57
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3.71
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*
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Anadarko’s earnings did not cover total fixed charges by $3,974 for 2016, $9,781 million for 2015, and $98 million for 2014.
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LIST OF SUBSIDIARIES
(1)
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At December 31, 2016
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Name of Subsidiary
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State, Province, or Country in Which Organized
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Anadarko Algeria Company, LLC
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Delaware
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Anadarko Brazil Investment I LLC
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Delaware
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Anadarko China Holdings 2 Company
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Cayman Islands
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Anadarko Colombia Company
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Cayman Islands
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Anadarko Consolidated Holdings LLC
(2)
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Delaware
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Anadarko Côte d'Ivoire Block 103 Company
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Cayman Islands
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Anadarko Côte d'Ivoire Block 528 Company
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Cayman Islands
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Anadarko Development Company
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Cayman Islands
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Anadarko Development Holding Limited
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Gibraltar
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Anadarko E&P Onshore LLC
(2)
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Delaware
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Anadarko Egypt Holdings Company
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Delaware
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Anadarko Energy Holding Limited
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Gibraltar
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Anadarko Energy Marketing, Inc.
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Delaware
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Anadarko Energy Services Company
(2)
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Delaware
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Anadarko Exploracao e Producao de Petroleo e Gas Natural Ltda.
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Brazil
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Anadarko Gathering Company LLC
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Delaware
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Anadarko Ghana Mahogany-1 Company
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Cayman Islands
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Anadarko Global Energy S.a.r.l.
(2)
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Luxembourg
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Anadarko Global Funding 1 Company
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Cayman Islands
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Anadarko Global Funding II Ltd.
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Bahama Islands
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Anadarko Holding Company
(2)
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Utah
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Anadarko International Development S.a.r.l.
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Luxembourg
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Anadarko Land Corp.
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Nebraska
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Anadarko Midkiff/Chaney Dell LLC
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Delaware
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Anadarko Moçambique Área 1, Limitada
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Mozambique
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Anadarko Offshore Holding Company, LLC
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Delaware
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Anadarko Realty, LLC
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Texas
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Anadarko Rockies LLC
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Delaware
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Anadarko Tunisia BEKS Company
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Cayman Islands
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Anadarko Uintah Midstream, LLC
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Delaware
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Anadarko US Offshore LLC
(2)
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Delaware
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Anadarko USH1 Corporation
(2)
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Delaware
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Anadarko Venezuela Company
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Cayman Islands
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Anadarko Venezuela LLC
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Delaware
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Anadarko Wattenberg Oil Complex LLC
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Delaware
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Anadarko WCTP Company
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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
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APC International Holdings LLC
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Delaware
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APC Midstream Holdings, LLC
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Delaware
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Bitter Creek Coal Company
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Utah
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Chipeta Processing LLC
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Delaware
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Delaware Basin JV Gathering LLC
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Delaware
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Delaware Basin Midstream, LLC
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Delaware
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Headwater II, LLC
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Delaware
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Kerr-McGee Corporation
(2)
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Delaware
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Kerr-McGee Energy Services Corporation
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Delaware
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Kerr-McGee Gathering LLC
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Colorado
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Kerr-McGee Oil and Gas Onshore LP
(2)
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Delaware
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Kerr-McGee Shared Services Company LLC
(2)
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Delaware
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Kerr-McGee Worldwide Corporation
(2)
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Delaware
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KM BM-C-Seven Ltd.
(2)
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Cayman Islands
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Mountain Gas Resouces LLC
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Delaware
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Rock Springs Royalty Company LLC
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Utah
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Springfield Pipeline LLC
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Texas
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Upland Industries Corporation
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Nebraska
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Venezuela US SRL
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Barbados
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Western Gas Partners, LP
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Delaware
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Western Gas Resources, Inc.
(2)
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Delaware
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Western Gas Resources-Westana, Inc.
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Delaware
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WGR Asset Holding Company LLC
(2)
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Delaware
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WGR Operating, LP
(2)
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Delaware
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(1)
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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)
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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
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Houston, Texas
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February 17, 2017
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Re:
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Securities and Exchange Commission
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Form 10-K of Anadarko Petroleum Corporation
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Very truly yours,
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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
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R. A. Walker
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Anthony R. Chase
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/s/ KEVIN P. CHILTON
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/s/ DAVID E. CONSTABLE
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Kevin P. Chilton
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David. E. Constable
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/s/ H. PAULETT EBERHART
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/s/ CLAIRE S. FARLEY
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H. Paulett Eberhart
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Claire S. Farley
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/s/ PETER J. FLUOR
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/s/ RICHARD L. GEORGE
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Peter J. Fluor
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Richard L. George
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/s/ JOSEPH W. GORDER
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/s/ JOHN R. GORDON
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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.
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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.
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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.
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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:
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a)
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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;
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b)
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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;
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c)
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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
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d)
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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
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5.
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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):
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a)
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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
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b)
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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
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R. A. Walker
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Chairman, President and Chief Executive Officer
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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.
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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.
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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.
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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:
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a)
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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;
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b)
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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;
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c)
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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
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d)
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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
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5.
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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):
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a)
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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
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b)
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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/ ROBERT G. GWIN
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Robert G. Gwin
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Executive Vice President, Finance and Chief Financial Officer
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(1)
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the Annual Report on Form 10-K of the Company for the period ended
December 31, 2016
, 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
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(2)
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the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
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February 17, 2017
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/s/ R. A. WALKER
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R. A. Walker
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Chairman, President and Chief Executive Officer
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February 17, 2017
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|
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/s/ ROBERT G. GWIN
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Robert G. Gwin
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Executive Vice President, Finance and Chief Financial Officer
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Re:
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Procedures and Methods Review of Anadarko Petroleum Corporation
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Proved Reserves and Future Net Cash Flows As of December 31, 2016
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Very truly yours,
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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
|