ý
|
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|
¨
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|
Delaware
|
|
76-0146568
|
(State or other jurisdiction of incorporation or organization)
|
|
(I.R.S. Employer Identification No.)
|
1201 Lake Robbins Drive, The Woodlands, Texas
|
|
77380-1046
|
(Address of principal executive offices)
|
|
(Zip Code)
|
Title of each class
|
|
Name of each exchange on which registered
|
Common Stock, par value $0.10 per share
|
|
New York Stock Exchange
|
7.50% Tangible Equity Units
|
|
New York Stock Exchange
|
Title of Class
|
|
Number of Shares Outstanding
|
Common Stock, par value $0.10 per share
|
|
508,438,647
|
|
|
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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||
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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
|
|
|
Item 15.
|
|
Oil and
Condensate
(MMBbls)
|
|
Natural Gas
(Bcf)
|
|
NGLs
(MMBbls)
|
|
Total
(MMBOE)
|
||||
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
|
|
|
|
|
|
|
|
|
|
||||
December 31, 2013
|
|
|
|
|
|
|
|
||||
Proved
|
|
|
|
|
|
|
|
||||
Developed
|
|
|
|
|
|
|
|
||||
United States
|
347
|
|
|
7,120
|
|
|
268
|
|
|
1,801
|
|
International
|
202
|
|
|
—
|
|
|
—
|
|
|
202
|
|
Undeveloped
|
|
|
|
|
|
|
|
||||
United States
|
245
|
|
|
2,085
|
|
|
127
|
|
|
720
|
|
International
|
57
|
|
|
—
|
|
|
12
|
|
|
69
|
|
Total proved
|
851
|
|
|
9,205
|
|
|
407
|
|
|
2,792
|
|
MMBOE
|
2015
|
|
2014
|
|
2013
|
|||
Proved Reserves
|
|
|
|
|
|
|||
January 1
|
2,858
|
|
|
2,792
|
|
|
2,560
|
|
Reserves additions and revisions
|
|
|
|
|
|
|||
Discoveries and extensions
|
29
|
|
|
63
|
|
|
145
|
|
Infill-drilling additions
(1)
|
89
|
|
|
577
|
|
|
410
|
|
Drilling-related reserves additions and revisions
|
118
|
|
|
640
|
|
|
555
|
|
Other non-price-related revisions
(1)
|
289
|
|
|
(137
|
)
|
|
(40
|
)
|
Net organic reserves additions
|
407
|
|
|
503
|
|
|
515
|
|
Acquisition of proved reserves in place
|
1
|
|
|
—
|
|
|
36
|
|
Price-related revisions
(1)
|
(624
|
)
|
|
(1
|
)
|
|
(23
|
)
|
Total reserves additions and revisions
|
(216
|
)
|
|
502
|
|
|
528
|
|
Sales in place
|
(279
|
)
|
|
(124
|
)
|
|
(12
|
)
|
Production
|
(306
|
)
|
|
(312
|
)
|
|
(284
|
)
|
December 31
|
2,057
|
|
|
2,858
|
|
|
2,792
|
|
Proved Developed Reserves
|
|
|
|
|
|
|||
January 1
|
1,969
|
|
|
2,003
|
|
|
1,883
|
|
December 31
|
1,632
|
|
|
1,969
|
|
|
2,003
|
|
(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 2015. Other non-price-related revisions are primarily a reflection of performance improvements coupled with the benefit of reduced year-end costs.
|
MMBOE
|
|
|
PUDs at January 1, 2015
|
889
|
|
Revisions of prior estimates
|
(199
|
)
|
Extensions, discoveries, and other additions
|
12
|
|
Conversions to developed
|
(236
|
)
|
Sales
|
(41
|
)
|
PUDs at December 31, 2015
|
425
|
|
|
Sales Volumes
|
|
Average Sales Prices
(1)
|
|
Average
Production
Costs
(2)
(Per BOE)
|
||||||||||||||||||||||
|
Oil and
Condensate
(MMBbls)
|
|
Natural
Gas
(Bcf)
|
|
NGLs
(MMBbls)
|
|
Barrels of
Oil
Equivalent
(MMBOE)
|
|
Oil and
Condensate
(Per Bbl)
|
|
Natural
Gas
(Per Mcf)
|
|
NGLs
(Per Bbl)
|
|
|||||||||||||
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Greater Natural Buttes
|
1
|
|
|
126
|
|
|
4
|
|
|
26
|
|
|
$
|
38.23
|
|
|
$
|
2.00
|
|
|
$
|
14.84
|
|
|
$
|
10.70
|
|
Wattenberg
|
35
|
|
|
176
|
|
|
16
|
|
|
81
|
|
|
44.88
|
|
|
2.31
|
|
|
15.65
|
|
|
7.64
|
|
||||
Other United States
|
49
|
|
|
550
|
|
|
25
|
|
|
165
|
|
|
45.19
|
|
|
2.45
|
|
|
18.33
|
|
|
8.51
|
|
||||
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Greater Natural Buttes
|
1
|
|
|
154
|
|
|
4
|
|
|
31
|
|
|
$
|
81.74
|
|
|
$
|
3.93
|
|
|
$
|
39.16
|
|
|
$
|
10.30
|
|
Wattenberg
|
27
|
|
|
125
|
|
|
13
|
|
|
62
|
|
|
87.76
|
|
|
4.19
|
|
|
36.46
|
|
|
7.55
|
|
||||
Other United States
|
46
|
|
|
666
|
|
|
26
|
|
|
182
|
|
|
88.29
|
|
|
4.08
|
|
|
34.29
|
|
|
9.07
|
|
||||
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
|
|
||||
2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Greater Natural Buttes
|
1
|
|
|
168
|
|
|
4
|
|
|
33
|
|
|
$
|
87.46
|
|
|
$
|
3.12
|
|
|
$
|
41.79
|
|
|
$
|
9.59
|
|
Wattenberg
|
16
|
|
|
102
|
|
|
6
|
|
|
40
|
|
|
94.27
|
|
|
3.75
|
|
|
41.75
|
|
|
7.92
|
|
||||
Other United States
|
41
|
|
|
698
|
|
|
23
|
|
|
179
|
|
|
98.38
|
|
|
3.56
|
|
|
36.14
|
|
|
8.64
|
|
||||
Total United States
|
58
|
|
|
968
|
|
|
33
|
|
|
252
|
|
|
97.02
|
|
|
3.50
|
|
|
37.97
|
|
|
8.65
|
|
||||
International
|
33
|
|
|
—
|
|
|
—
|
|
|
33
|
|
|
109.15
|
|
|
—
|
|
|
—
|
|
|
9.96
|
|
||||
Total
|
91
|
|
|
968
|
|
|
33
|
|
|
285
|
|
|
101.41
|
|
|
3.50
|
|
|
37.97
|
|
|
8.80
|
|
(1)
|
Excludes the impact of commodity derivatives.
|
(2)
|
Excludes ad valorem and severance taxes.
|
|
Developed
Lease
|
|
Undeveloped
Lease
|
|
Fee Mineral
|
|
Total
|
||||||||||||||||
thousands of acres
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||||
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Onshore
|
4,451
|
|
|
2,947
|
|
|
3,482
|
|
|
1,472
|
|
|
10,235
|
|
|
8,529
|
|
|
18,168
|
|
|
12,948
|
|
Offshore
|
270
|
|
|
132
|
|
|
1,362
|
|
|
866
|
|
|
—
|
|
|
—
|
|
|
1,632
|
|
|
998
|
|
Total United States
|
4,721
|
|
|
3,079
|
|
|
4,844
|
|
|
2,338
|
|
|
10,235
|
|
|
8,529
|
|
|
19,800
|
|
|
13,946
|
|
International
|
499
|
|
|
113
|
|
|
46,691
|
|
|
34,259
|
|
|
—
|
|
|
—
|
|
|
47,190
|
|
|
34,372
|
|
Total
|
5,220
|
|
|
3,192
|
|
|
51,535
|
|
|
36,597
|
|
|
10,235
|
|
|
8,529
|
|
|
66,990
|
|
|
48,318
|
|
|
Net Exploratory
|
|
Net Development
|
|
Total
|
|||||||||||||||
|
Productive
|
|
Dry Holes
|
|
Total
|
|
Productive
|
|
Dry Holes
|
|
Total
|
|
||||||||
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
|
|
2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
United States
|
62.9
|
|
|
1.4
|
|
|
64.3
|
|
|
879.3
|
|
|
3.3
|
|
|
882.6
|
|
|
946.9
|
|
International
|
0.2
|
|
|
3.5
|
|
|
3.7
|
|
|
5.4
|
|
|
—
|
|
|
5.4
|
|
|
9.1
|
|
Total
|
63.1
|
|
|
4.9
|
|
|
68.0
|
|
|
884.7
|
|
|
3.3
|
|
|
888.0
|
|
|
956.0
|
|
|
Wells in the process
of drilling or
in active completion
|
|
Wells suspended or
waiting on completion
(1)
|
||||||||
|
Exploration
|
|
Development
|
|
Exploration
|
|
Development
|
||||
United States
|
|
|
|
|
|
|
|
||||
Gross
|
2
|
|
|
24
|
|
|
63
|
|
|
848
|
|
Net
|
0.7
|
|
|
12.6
|
|
|
26.1
|
|
|
548.3
|
|
International
|
|
|
|
|
|
|
|
||||
Gross
|
—
|
|
|
—
|
|
|
62
|
|
|
29
|
|
Net
|
—
|
|
|
—
|
|
|
18.5
|
|
|
6.2
|
|
Total
|
|
|
|
|
|
|
|
||||
Gross
|
2
|
|
|
24
|
|
|
125
|
|
|
877
|
|
Net
|
0.7
|
|
|
12.6
|
|
|
44.6
|
|
|
554.5
|
|
(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.
|
|
Oil Wells
(1)
|
|
Gas Wells
(1)
|
||
United States
|
|
|
|
||
Gross
|
3,898
|
|
|
20,518
|
|
Net
|
2,489.4
|
|
|
14,765.5
|
|
International
|
|
|
|
||
Gross
|
195
|
|
|
7
|
|
Net
|
34.5
|
|
|
1.7
|
|
Total
|
|
|
|
||
Gross
|
4,093
|
|
|
20,525
|
|
Net
|
2,523.9
|
|
|
14,767.2
|
|
(1)
|
Includes wells containing multiple completions as follows:
|
Gross
|
217
|
|
|
2,703
|
|
Net
|
189.2
|
|
|
2,290.0
|
|
Area
|
|
Asset Type
|
|
Miles of
Gathering
Pipelines
|
|
Total
Horsepower
|
|
2015
Average Net
Throughput
(MMcf/d)
|
|||
Rocky Mountains
|
|
Gathering, processing, and treating
|
|
11,100
|
|
|
779,400
|
|
|
3,200
|
|
Southern and Appalachia
|
|
Gathering, processing, and treating
|
|
6,600
|
|
|
724,000
|
|
|
2,400
|
|
Total
|
|
|
|
17,700
|
|
|
1,503,400
|
|
|
5,600
|
|
•
|
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 Environmental Protection Agency has relied upon as authority for adopting climate change regulatory initiatives
|
•
|
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 controlling 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,
2016
|
|
Position
|
R. A. Walker
|
|
58
|
|
Chairman, President and Chief Executive Officer
|
Robert P. Daniels
|
|
57
|
|
Executive Vice President, International and Deepwater Exploration
|
Robert G. Gwin
|
|
52
|
|
Executive Vice President, Finance and Chief Financial Officer
|
Darrell E. Hollek
|
|
58
|
|
Executive Vice President, U.S. Onshore Exploration and Production
|
Mitchell W. Ingram
|
|
53
|
|
Executive Vice President, Global LNG
|
James J. Kleckner
|
|
58
|
|
Executive Vice President, International and Deepwater Operations
|
Robert K. Reeves
|
|
58
|
|
Executive Vice President, Law and Chief Administrative Officer
|
Christopher O. Champion
|
|
46
|
|
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 natural-gas liquids (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; environmental risks; and liability under federal, state, foreign, and local environmental laws and regulations
|
•
|
the ability of BP Exploration & Production Inc. (BP) to meet its indemnification obligations to the Company for Deepwater Horizon events, including, among other things, damage claims arising under the Oil Pollution Act of 1990 (OPA), claims for natural resource damages (NRD) and associated damage-assessment costs, and any claims arising under the Operating Agreement (OA) for the Macondo well, as well as the ability of BP Corporation North America Inc. (BPCNA) and BP p.l.c. to satisfy their guarantees of such indemnification obligations
|
•
|
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
|
•
|
disruptions in international oil, NGLs, and condensate 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, condensate, liquefied natural gas, or NGLs
|
•
|
the ability of the members of the Organization of the Petroleum Exporting Countries (OPEC) and other producing nations to agree to and maintain production levels
|
•
|
the worldwide military and political environment, civil and political unrest 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
|
•
|
the proximity to, and capacity of, natural-gas pipelines and other transportation facilities
|
•
|
general economic conditions worldwide
|
•
|
adversely affecting our financial condition, liquidity, ability to finance planned capital expenditures, and results of operations
|
•
|
reducing the amount of oil, natural gas, and NGLs that we can produce economically
|
•
|
causing us to delay or postpone some of our capital projects
|
•
|
reducing our revenues, operating income, or cash flows
|
•
|
reducing the amounts of our estimated proved oil, natural-gas, and NGLs reserves
|
•
|
reducing 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
|
•
|
reducing the standardized measure of discounted future net cash flows relating to oil, natural-gas, and NGLs reserves
|
•
|
limiting our access to, or increasing the cost of, sources of capital such as equity and long-term debt
|
•
|
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
|
•
|
Proposed Outer Continental Shelf Well Control Rule
. In April 2015, the Bureau of Safety and Environmental Enforcement (BSEE) issued a notice of proposed rulemaking entitled Oil and Sulfur Operations on the Outer Continental Shelf - Blowout Preventer Systems and Well Control that focuses on well blowout preventer systems and well control with respect to operations on the Outer Continental Shelf. The proposed rule requires, among other things, incorporation of the latest industry standards establishing minimum baseline standards for the design, manufacture, repair, and maintenance of blowout preventers as well as more controls over the maintenance and repair of blowout preventers. This rulemaking is expected to be finalized in 2016.
|
•
|
Ground-Level Ozone Standards.
In October 2015, the U.S. Environmental Protection Agency (EPA) issued a final 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 final rule became effective in December 2015. Certain areas of the country in compliance with the ground-level ozone NAAQS standard may be reclassified as non-attainment and such reclassification 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 final rule could, among other things, require installation or 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 August 2015, the EPA proposed rules that will establish emission standards for methane from certain new and modified oil and natural-gas production and natural-gas processing and transmission facilities as part of the Obama Administration’s efforts to reduce methane emissions from the oil and natural-gas sector by up to 45 percent from 2012 levels by 2025. The EPA’s proposed rule package includes standards to address emissions of methane from equipment and processes across the source category, including 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. The EPA is expected to finalize these rules in 2016.
|
•
|
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 greenhouse gases (GHGs). These efforts have included consideration of cap-and-trade programs, carbon taxes, and GHG reporting and tracking programs. 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. On an international level, the United States is one of almost 200 nations that, in December 2015, agreed to an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets.
|
•
|
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
|
•
|
historical production from an area compared with production from similar producing areas
|
•
|
assumed effects of regulation by governmental agencies and court rulings
|
•
|
assumptions concerning future oil and natural-gas 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
|
•
|
oilfield service costs and availability
|
•
|
compliance with environmental 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
|
•
|
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 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
|
•
|
shortages or delays in the delivery of equipment
|
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
|
||||||||
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
|
|
2014
|
|
|
|
|
|
|
|
||||||||
Market Price
|
|
|
|
|
|
|
|
||||||||
High
|
$
|
86.86
|
|
|
$
|
112.06
|
|
|
$
|
113.51
|
|
|
$
|
102.68
|
|
Low
|
$
|
77.80
|
|
|
$
|
84.54
|
|
|
$
|
100.40
|
|
|
$
|
71.00
|
|
Dividends
|
$
|
0.18
|
|
|
$
|
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
|
|
7,046,098
|
|
|
$
|
71.86
|
|
|
16,378,707
|
|
Equity compensation plans not approved by security holders
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total
|
|
7,046,098
|
|
|
$
|
71.86
|
|
|
16,378,707
|
|
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, 2015
|
|
186,340
|
|
|
$
|
70.32
|
|
|
—
|
|
|
|
||
November 1-30, 2015
|
|
63,867
|
|
|
$
|
69.09
|
|
|
—
|
|
|
|
||
December 1-31, 2015
|
|
1,903
|
|
|
$
|
56.61
|
|
|
—
|
|
|
|
||
Total
|
|
252,110
|
|
|
$
|
69.90
|
|
|
—
|
|
|
$
|
—
|
|
(1)
|
During the fourth quarter of
2015
, all purchased shares related to stock received by the Company for the payment of withholding taxes due on employee stock plan share issuances.
|
Fiscal Year Ended December 31
|
2010
|
|
2011
|
|
2012
|
|
2013
|
|
2014
|
|
2015
|
||||||||||||
Anadarko Petroleum Corporation
|
$
|
100.00
|
|
|
$
|
100.70
|
|
|
$
|
98.53
|
|
|
$
|
105.81
|
|
|
$
|
111.25
|
|
|
$
|
66.53
|
|
S&P 500
|
100.00
|
|
|
102.11
|
|
|
118.45
|
|
|
156.82
|
|
|
178.29
|
|
|
180.75
|
|
||||||
Peer Group
|
100.00
|
|
|
105.57
|
|
|
107.65
|
|
|
135.30
|
|
|
124.85
|
|
|
95.82
|
|
|
Summary Financial Information
(1)
|
||||||||||||||||||
millions except per-share amounts
|
2015
|
|
2014
|
|
2013
|
|
2012
|
|
2011
|
||||||||||
Sales Revenues
|
$
|
9,486
|
|
|
$
|
16,375
|
|
|
$
|
14,867
|
|
|
$
|
13,307
|
|
|
$
|
13,882
|
|
Gains (Losses) on Divestitures and Other, net
|
(788
|
)
|
|
2,095
|
|
|
(286
|
)
|
|
104
|
|
|
85
|
|
|||||
Total Revenues and Other
|
8,698
|
|
|
18,470
|
|
|
14,581
|
|
|
13,411
|
|
|
13,967
|
|
|||||
Other Operating (Income) Expense
|
|
|
|
|
|
|
|
|
|
||||||||||
Algeria Exceptional Profits Tax Settlement
|
—
|
|
|
—
|
|
|
33
|
|
|
(1,797
|
)
|
|
—
|
|
|||||
Deepwater Horizon Settlement and Related Costs
|
74
|
|
|
97
|
|
|
15
|
|
|
18
|
|
|
3,930
|
|
|||||
Operating Income (Loss)
|
(8,809
|
)
|
|
5,403
|
|
|
3,333
|
|
|
3,727
|
|
|
(1,870
|
)
|
|||||
Tronox-related Contingent Loss
|
5
|
|
|
4,360
|
|
|
850
|
|
|
(250
|
)
|
|
250
|
|
|||||
Income (Loss)
|
(6,812
|
)
|
|
(1,563
|
)
|
|
941
|
|
|
2,445
|
|
|
(2,568
|
)
|
|||||
Net Income (Loss) Attributable to Common Stockholders
|
(6,692
|
)
|
|
(1,750
|
)
|
|
801
|
|
|
2,391
|
|
|
(2,649
|
)
|
|||||
Per Common Share (amounts attributable to common stockholders)
|
|
|
|
|
|
|
|
|
|
||||||||||
Net Income (Loss)—Basic
|
$
|
(13.18
|
)
|
|
$
|
(3.47
|
)
|
|
$
|
1.58
|
|
|
$
|
4.76
|
|
|
$
|
(5.32
|
)
|
Net Income (Loss)—Diluted
|
$
|
(13.18
|
)
|
|
$
|
(3.47
|
)
|
|
$
|
1.58
|
|
|
$
|
4.74
|
|
|
$
|
(5.32
|
)
|
Dividends
|
$
|
1.08
|
|
|
$
|
0.99
|
|
|
$
|
0.54
|
|
|
$
|
0.36
|
|
|
$
|
0.36
|
|
Average Number of Common Shares Outstanding—Basic
|
508
|
|
|
506
|
|
|
502
|
|
|
500
|
|
|
498
|
|
|||||
Average Number of Common Shares Outstanding—Diluted
|
508
|
|
|
506
|
|
|
505
|
|
|
502
|
|
|
498
|
|
|||||
Cash Provided by (Used in) Operating Activities
|
(1,877
|
)
|
|
8,466
|
|
|
8,888
|
|
|
8,339
|
|
|
2,505
|
|
|||||
Capital Expenditures
|
$
|
5,888
|
|
|
$
|
9,256
|
|
|
$
|
8,523
|
|
|
$
|
7,311
|
|
|
$
|
6,553
|
|
Current Portion of Long-term Debt
|
$
|
33
|
|
|
$
|
—
|
|
|
$
|
500
|
|
|
$
|
—
|
|
|
$
|
170
|
|
Long-term Debt
(2)
|
15,718
|
|
|
15,092
|
|
|
13,065
|
|
|
13,269
|
|
|
15,060
|
|
|||||
Total Debt
|
$
|
15,751
|
|
|
$
|
15,092
|
|
|
$
|
13,565
|
|
|
$
|
13,269
|
|
|
$
|
15,230
|
|
Total Stockholders’ Equity
|
12,819
|
|
|
19,725
|
|
|
21,857
|
|
|
20,629
|
|
|
18,105
|
|
|||||
Total Assets
(3)
|
$
|
46,414
|
|
|
$
|
60,967
|
|
|
$
|
55,421
|
|
|
$
|
52,261
|
|
|
$
|
51,641
|
|
Annual Sales Volumes
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil and Condensate (MMBbls)
|
116
|
|
|
106
|
|
|
91
|
|
|
86
|
|
|
79
|
|
|||||
Natural Gas (Bcf)
|
852
|
|
|
945
|
|
|
968
|
|
|
913
|
|
|
852
|
|
|||||
Natural Gas Liquids (MMBbls)
|
47
|
|
|
44
|
|
|
33
|
|
|
30
|
|
|
27
|
|
|||||
Total (MMBOE)
(4)
|
305
|
|
|
308
|
|
|
285
|
|
|
268
|
|
|
248
|
|
|||||
Average Daily Sales Volumes
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil and Condensate (MBbls/d)
|
317
|
|
|
292
|
|
|
248
|
|
|
233
|
|
|
217
|
|
|||||
Natural Gas (MMcf/d)
|
2,334
|
|
|
2,589
|
|
|
2,652
|
|
|
2,495
|
|
|
2,334
|
|
|||||
Natural Gas Liquids (MBbls/d)
|
130
|
|
|
119
|
|
|
91
|
|
|
83
|
|
|
74
|
|
|||||
Total (MBOE/d)
|
836
|
|
|
843
|
|
|
781
|
|
|
732
|
|
|
680
|
|
|||||
Proved Reserves
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil and Condensate Reserves (MMBbls)
|
713
|
|
|
929
|
|
|
851
|
|
|
767
|
|
|
771
|
|
|||||
Natural-gas Reserves (Tcf)
|
6.0
|
|
|
8.7
|
|
|
9.2
|
|
|
8.3
|
|
|
8.4
|
|
|||||
Natural-gas Liquids Reserves (MMBbls)
|
340
|
|
|
479
|
|
|
407
|
|
|
405
|
|
|
374
|
|
|||||
Total Proved Reserves (MMBOE)
|
2,057
|
|
|
2,858
|
|
|
2,792
|
|
|
2,560
|
|
|
2,539
|
|
|||||
Number of Employees
|
5,800
|
|
|
6,100
|
|
|
5,700
|
|
|
5,200
|
|
|
4,800
|
|
(1)
|
Consolidated for Anadarko and its subsidiaries. Certain amounts for prior years have been reclassified to conform to the current presentation.
|
(2)
|
Includes Western Gas Partners, LP debt of $
2.7 billion
at December 31, 2015, $
2.4 billion
at December 31, 2014, $1.4 billion at December 31, 2013, $1.2 billion at December 31, 2012, and $494 million at December 31, 2011.
|
(3)
|
As a result of adopting Accounting Standards Update 2015-17,
Balance Sheet Classification of Deferred Taxes
, the Company reclassified other current assets of $722 million in 2014, $360 million in 2013, $328 million in 2012, and $138 million in 2011, to deferred income taxes. See
Note 1—Summary of Significant Accounting Policies
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
(4)
|
Natural gas is converted to equivalent barrels at the rate of 6,000 cubic feet of gas per barrel.
|
Table of Measures
|
|
|
|
|
Bcf—Billion cubic feet
|
|
MMcf/d—Million cubic feet per day
|
|
Tcf—Trillion cubic feet
|
MMBbls—Million barrels
|
|
MBbls/d—Thousand barrels per day
|
|
|
MMBOE—Million barrels of oil equivalent
|
|
MBOE/d—Thousand barrels of oil equivalent per day
|
|
|
•
|
explore in high-potential, proven basins
|
•
|
identify and commercialize resources
|
•
|
employ a global business development approach
|
•
|
ensure financial discipline and flexibility
|
•
|
Anadarko’s sales volumes averaged
836
thousand barrels of oil equivalent per day (MBOE/d), which was relatively flat compared to
2014
and includes a 37 MBOE/d decrease related to divestitures.
|
•
|
The Company’s overall sales-volume product mix increased to 53% liquids in
2015
compared to 49% in
2014
.
|
•
|
Anadarko’s higher-margin liquids sales volumes were
447
thousand barrels per day (MBbls/d), representing a
9%
increase
over
2014
. This increase included a 14 MBbls/d decrease in sales volumes related to divestitures, including certain enhanced oil recovery (EOR) assets in the Rocky Mountains Region (Rockies) in 2015 and the Company’s Chinese subsidiary in 2014.
|
•
|
The Company closed several asset monetizations, totaling
$1.4 billion
, including the divestiture of certain coalbed methane properties and related midstream assets in the Rockies, certain EOR assets in the Rockies, and certain oil and gas properties and related midstream assets in East Texas.
|
•
|
Anadarko paid $5.2 billion related to a settlement agreement resolving all claims asserted in the Tronox Adversary Proceeding. See
Note 15—Contingencies
—Tronox Litigation
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
•
|
After previously finding that Anadarko, as a nonoperating investor in the Macondo well, was not culpable with respect to the Deepwater Horizon events, the Louisiana District Court found Anadarko liable for civil penalties under the Clean Water Act as a working-interest owner in the Macondo well and entered a judgment of
$159.5 million
in December 2015. See
Note 15—Contingencies
—Deepwater Horizon Events
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
•
|
The Rockies sales volumes averaged
367
MBOE/d, representing a
2%
, or 6 MBOE/d,
increase
over
2014
, primarily from a 32%, or 54 MBOE/d, sales volume increase in the Wattenberg field, partially offset by lower sales volumes due to the April 2015 sale of certain EOR assets and the September 2015 sale of certain coalbed methane properties.
|
•
|
The Southern and Appalachia Region sales volumes averaged
284
MBOE/d, representing a
5%
decrease
from
2014
, primarily due to lower natural-gas sales volumes in the Marcellus shale due to voluntary curtailments and third-party infrastructure downtime, and the sale of certain U.S. onshore oil and gas properties and related midstream assets in East Texas, partially offset by higher sales volumes in the Eagleford shale.
|
•
|
Gulf of Mexico sales volumes averaged
85
MBOE/d, representing a
2%
increase
over
2014
, primarily due to the commencement of oil production from the Lucius development in January 2015, partially offset by a natural-gas production decline at Independence Hub (IHUB).
|
•
|
The Company participated in the successful drilling of the nonoperated Yeti exploration well (37.5% working interest) in Walker Ridge Block 160, with the well successfully sidetracked to test the down-dip limits of the field.
|
•
|
Anadarko’s Heidelberg development project was completed and achieved first oil in January 2016.
|
•
|
International sales volumes averaged
91
MBOE/d, which was relatively flat compared to
2014
.
|
•
|
The Kronos-1 deepwater prospect offshore Colombia encountered 130 to 230 net feet of natural-gas pay in the upper objective and encountered non-commercial hydrocarbons in a deeper objective.
|
•
|
The Tweneboa/Enyenra/Ntomme (TEN) project in Ghana was more than 80% complete at year end
2015
, with first oil expected in the third quarter of 2016.
|
•
|
Anadarko wrote off suspended exploratory costs in 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.
|
•
|
Anadarko’s net loss attributable to common stockholders for
2015
totaled $
6.7 billion
, including impairments of
$5.1 billion
primarily related to certain U.S. onshore and Gulf of Mexico properties, impairments of exploration assets of $1.9 billion primarily associated with impairments of unproved properties and the write-off of suspended exploratory well costs in Brazil, and losses on divestitures of $1.0 billion.
|
•
|
The Company’s net cash used in operating activities was
$1.9 billion
in
2015
, which included the $5.2 billion Tronox settlement payment. The Company ended
2015
with
$939 million
of cash on hand.
|
•
|
The Company initiated a commercial paper program, which allows the issuance of a maximum of $3.0 billion of unsecured commercial paper notes.
|
•
|
In December 2015, Anadarko extended the maturity of its Five-Year Facility to January 2021, and in January 2016, Anadarko replaced its 364-Day Facility with a new $2.0 billion 364-day senior unsecured revolving credit facility that will mature in January 2017.
|
•
|
WES, a publicly traded consolidated subsidiary, completed a public offering of $500 million aggregate principal amount of 3.950% Senior Notes due 2025.
|
•
|
Anadarko issued 9.2 million 7.50% tangible equity units (TEUs) at a stated amount of $50.00 per unit and raised net proceeds of $445 million.
|
•
|
Anadarko completed a public secondary offering of 2.3 million common units in Western Gas Equity Partners, LP (WGP), a publicly traded consolidated subsidiary that owns partnership interests in WES, and raised net proceeds of $130 million.
|
millions except per-share amounts
|
2015
|
|
2014
|
|
2013
|
||||||
Oil and condensate, natural-gas, and NGLs sales
|
$
|
8,260
|
|
|
$
|
15,169
|
|
|
$
|
13,828
|
|
Gathering, processing, and marketing sales
|
1,226
|
|
|
1,206
|
|
|
1,039
|
|
|||
Gains (losses) on divestitures and other, net
|
(788
|
)
|
|
2,095
|
|
|
(286
|
)
|
|||
Revenues and other
|
8,698
|
|
|
18,470
|
|
|
14,581
|
|
|||
Costs and expenses
|
17,507
|
|
|
13,067
|
|
|
11,248
|
|
|||
Other (income) expense
|
880
|
|
|
5,349
|
|
|
1,227
|
|
|||
Income tax expense (benefit)
|
(2,877
|
)
|
|
1,617
|
|
|
1,165
|
|
|||
Net income (loss) attributable to common stockholders
|
$
|
(6,692
|
)
|
|
$
|
(1,750
|
)
|
|
$
|
801
|
|
Net income (loss) per common share attributable to common stockholders—diluted
|
$
|
(13.18
|
)
|
|
$
|
(3.47
|
)
|
|
$
|
1.58
|
|
Average number of common shares outstanding—diluted
|
508
|
|
|
506
|
|
|
505
|
|
millions
|
Oil and
Condensate
|
|
Natural
Gas
|
|
NGLs
|
|
Total
|
||||||||
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
|
)%
|
||||
|
|
|
|
|
|
|
|
||||||||
2013 sales revenues
|
$
|
9,178
|
|
|
$
|
3,388
|
|
|
$
|
1,262
|
|
|
$
|
13,828
|
|
Changes associated with prices
|
(1,046
|
)
|
|
540
|
|
|
(86
|
)
|
|
(592
|
)
|
||||
Changes associated with sales volumes
|
1,616
|
|
|
(79
|
)
|
|
396
|
|
|
1,933
|
|
||||
2014 sales revenues
|
$
|
9,748
|
|
|
$
|
3,849
|
|
|
$
|
1,572
|
|
|
$
|
15,169
|
|
Increase/(decrease) vs. 2013
|
6
|
%
|
|
14
|
%
|
|
25
|
%
|
|
10
|
%
|
|
2015
|
|
Inc/(Dec)
vs. 2014 |
|
2014
|
|
Inc/(Dec)
vs. 2013 |
|
2013
|
|||||
Barrels of Oil Equivalent
|
|
|
|
|
|
|
|
|
|
|||||
(MMBOE except percentages)
|
|
|
|
|
|
|
|
|
|
|||||
United States
|
272
|
|
|
(1
|
)%
|
|
275
|
|
|
9
|
%
|
|
252
|
|
International
|
33
|
|
|
(1
|
)
|
|
33
|
|
|
2
|
|
|
33
|
|
Total barrels of oil equivalent
|
305
|
|
|
(1
|
)
|
|
308
|
|
|
8
|
|
|
285
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Barrels of Oil Equivalent per Day
|
|
|
|
|
|
|
|
|
|
|||||
(MBOE/d except percentages)
|
|
|
|
|
|
|
|
|
|
|||||
United States
|
745
|
|
|
(1
|
)%
|
|
751
|
|
|
9
|
%
|
|
691
|
|
International
|
91
|
|
|
(1
|
)
|
|
92
|
|
|
2
|
|
|
90
|
|
Total barrels of oil equivalent per day
|
836
|
|
|
(1
|
)
|
|
843
|
|
|
8
|
|
|
781
|
|
|
2015
|
|
Inc/(Dec)
vs. 2014 |
|
2014
|
|
Inc/(Dec)
vs. 2013 |
|
2013
|
||||||||
United States
|
|
|
|
|
|
|
|
|
|
||||||||
Sales volumes—MMBbls
|
85
|
|
|
14
|
%
|
|
74
|
|
|
28
|
%
|
|
58
|
|
|||
MBbls/d
|
232
|
|
|
14
|
|
|
203
|
|
|
28
|
|
|
158
|
|
|||
Price per barrel
|
$
|
45.00
|
|
|
(49
|
)
|
|
$
|
87.99
|
|
|
(9
|
)
|
|
$
|
97.02
|
|
International
|
|
|
|
|
|
|
|
|
|
||||||||
Sales volumes—MMBbls
|
31
|
|
|
(4
|
)%
|
|
32
|
|
|
(1
|
)%
|
|
33
|
|
|||
MBbls/d
|
85
|
|
|
(4
|
)
|
|
89
|
|
|
(1
|
)
|
|
90
|
|
|||
Price per barrel
|
$
|
51.68
|
|
|
(48
|
)
|
|
$
|
99.79
|
|
|
(9
|
)
|
|
$
|
109.15
|
|
Total
|
|
|
|
|
|
|
|
|
|
||||||||
Sales volumes—MMBbls
|
116
|
|
|
9
|
%
|
|
106
|
|
|
18
|
%
|
|
91
|
|
|||
MBbls/d
|
317
|
|
|
9
|
|
|
292
|
|
|
18
|
|
|
248
|
|
|||
Price per barrel
|
$
|
46.79
|
|
|
(49
|
)
|
|
$
|
91.58
|
|
|
(10
|
)
|
|
$
|
101.41
|
|
Oil and condensate sales revenues (millions)
|
$
|
5,420
|
|
|
(44
|
)
|
|
$
|
9,748
|
|
|
6
|
|
|
$
|
9,178
|
|
•
|
Sales volumes in the Rockies
increased
by
11
MBbls/d primarily in the Wattenberg field due to continued horizontal drilling, partially offset by lower sales volumes due to the sale of certain EOR assets in April 2015.
|
•
|
Sales volumes in the Southern and Appalachia Region
increased
by
10
MBbls/d primarily in the Eagleford shale as a result of continued horizontal drilling and in the Delaware basin due to wells brought online as a result of additional infrastructure and continued drilling.
|
•
|
Sales volumes in the Gulf of Mexico
increased
by
8
MBbls/d primarily from the Lucius development achieving first oil in January 2015, partially offset by a natural production decline at Marco Polo.
|
•
|
International sales volumes
decreased
by
4
MBbls/d primarily due to the timing of liftings in Algeria and the sale of the Company’s Chinese subsidiary in August 2014, partially offset by higher sales volumes due to the timing of liftings in Ghana.
|
•
|
Sales volumes in the Rockies increased by 33 MBbls/d primarily in the Wattenberg field due to increased horizontal drilling.
|
•
|
Sales volumes in the Southern and Appalachia Region increased by 15 MBbls/d, primarily as a result of increased horizontal drilling and 2013 infrastructure expansion in the Eagleford shale and increased horizontal drilling in the Delaware basin.
|
•
|
International sales volumes decreased by 1 MBbls/d primarily due to lower sales volumes in China as a result of maintenance downtime and the sale of the Company’s Chinese subsidiary and the timing of liftings in Ghana, partially offset by higher sales volumes in Algeria from additional facilities and wells brought online at El Merk.
|
•
|
Sales volumes in the Gulf of Mexico decreased by 1 MBbls/d primarily due to natural production declines.
|
|
2015
|
|
Inc/(Dec)
vs. 2014 |
|
2014
|
|
Inc/(Dec)
vs. 2013 |
|
2013
|
||||||||
United States
|
|
|
|
|
|
|
|
|
|
||||||||
Sales volumes—Bcf
|
852
|
|
|
(10
|
)%
|
|
945
|
|
|
(2
|
)%
|
|
968
|
|
|||
MMcf/d
|
2,334
|
|
|
(10
|
)
|
|
2,589
|
|
|
(2
|
)
|
|
2,652
|
|
|||
Price per Mcf
|
$
|
2.36
|
|
|
(42
|
)
|
|
$
|
4.07
|
|
|
16
|
|
|
$
|
3.50
|
|
Natural-gas sales revenues (millions)
|
$
|
2,007
|
|
|
(48
|
)
|
|
$
|
3,849
|
|
|
14
|
|
|
$
|
3,388
|
|
•
|
Sales volumes in the Southern and Appalachia Region
decreased
by
145
MMcf/d primarily due to voluntary curtailments and third-party infrastructure downtime in the Marcellus shale and the July 2015 sale of certain U.S. onshore properties and related midstream assets in East Texas. These decreases were partially offset by higher sales volumes as a result of continued horizontal drilling in the Eagleford shale.
|
•
|
Sales volumes in the Rockies
decreased
by
66
MMcf/d primarily due to voluntary curtailments at Greater Natural Buttes, a natural production decline at Powder River basin, and the September 2015 sale of certain coalbed methane properties, partially offset by higher sales volumes in the Wattenberg field as a result of continued horizontal drilling.
|
•
|
Sales volumes in the Gulf of Mexico
decreased
by
44
MMcf/d primarily due to a natural production decline at IHUB, partially offset by the Lucius development achieving first production in January 2015.
|
•
|
Sales volumes in the Rockies decreased by 90 MMcf/d primarily due to the January 2014 sale of the Company’s Pinedale/Jonah assets and natural production declines in the Powder River basin and Greater Natural Buttes. These decreases were partially offset by higher sales volumes in the Wattenberg field due to increased horizontal drilling.
|
•
|
Sales volumes in the Gulf of Mexico decreased by 67 MMcf/d primarily due to a natural production decline at IHUB.
|
•
|
Sales volumes in the Southern and Appalachia Region increased by 94 MMcf/d primarily due to infrastructure expansions that allowed the Company to bring wells online in the Marcellus and Eagleford shales as well as continued horizontal drilling in the liquids-rich East Texas/North Louisiana horizontal development.
|
|
2015
|
|
Inc/(Dec)
vs. 2014 |
|
2014
|
|
Inc/(Dec)
vs. 2013 |
|
2013
|
||||||||
United States
|
|
|
|
|
|
|
|
|
|
||||||||
Sales volumes—MMBbls
|
45
|
|
|
6
|
%
|
|
43
|
|
|
28
|
%
|
|
33
|
|
|||
MBbls/d
|
124
|
|
|
6
|
|
|
116
|
|
|
28
|
|
|
91
|
|
|||
Price per barrel
|
$
|
17.03
|
|
|
(52
|
)
|
|
$
|
35.48
|
|
|
(7
|
)
|
|
$
|
37.97
|
|
International
|
|
|
|
|
|
|
|
|
|
||||||||
Sales volumes—MMBbls
|
2
|
|
|
91
|
%
|
|
1
|
|
|
NM
|
|
|
—
|
|
|||
MBbls/d
|
6
|
|
|
91
|
|
|
3
|
|
|
NM
|
|
|
—
|
|
|||
Price per barrel
|
$
|
29.85
|
|
|
(47
|
)
|
|
$
|
56.16
|
|
|
NM
|
|
|
$
|
—
|
|
Total
|
|
|
|
|
|
|
|
|
|
||||||||
Sales volumes—MMBbls
|
47
|
|
|
8
|
%
|
|
44
|
|
|
31
|
%
|
|
33
|
|
|||
MBbls/d
|
130
|
|
|
8
|
|
|
119
|
|
|
31
|
|
|
91
|
|
|||
Price per barrel
|
$
|
17.61
|
|
|
(51
|
)
|
|
$
|
36.01
|
|
|
(5
|
)
|
|
$
|
37.97
|
|
Natural-gas liquids sales revenues (millions)
|
$
|
833
|
|
|
(47
|
)
|
|
$
|
1,572
|
|
|
25
|
|
|
$
|
1,262
|
|
•
|
Sales volumes in the Rockies increased by
6
MBbls/d primarily in the Wattenberg field due to continued horizontal drilling and the Lancaster plant coming online in April 2014, partially offset by ethane rejection.
|
•
|
International sales volumes increased by 3 MBbls/d as volumes increased in Algeria since the commencement of sales at the Company’s El Merk facility during 2014.
|
•
|
Sales volumes in the Rockies increased by 16 MBbls/d primarily in the Wattenberg field due to increased horizontal drilling and the Lancaster plant coming online in April 2014.
|
•
|
Sales volumes in the Southern and Appalachia Region increased by 10 MBbls/d primarily as a result of increased horizontal drilling and 2013 infrastructure expansion in the Eagleford shale.
|
•
|
International sales volumes increased by 3 MBbls/d due to the commencement of sales at the Company’s El Merk facility in Algeria in 2014.
|
millions except percentages
|
2015
|
|
Inc/(Dec)
vs. 2014 |
|
2014
|
|
Inc/(Dec)
vs. 2013 |
|
2013
|
||||||||
Gathering, processing, and marketing sales
|
$
|
1,226
|
|
|
2
|
%
|
|
$
|
1,206
|
|
|
16
|
%
|
|
$
|
1,039
|
|
Gathering, processing, and marketing expense
|
1,054
|
|
|
2
|
|
|
1,030
|
|
|
19
|
|
|
869
|
|
|||
Total gathering, processing, and marketing, net
|
$
|
172
|
|
|
(2
|
)
|
|
$
|
176
|
|
|
4
|
|
|
$
|
170
|
|
millions except percentages
|
2015
|
|
Inc/(Dec)
vs. 2014 |
|
2014
|
|
Inc/(Dec)
vs. 2013 |
|
2013
|
||||||||
Gains (losses) on divestitures
|
$
|
(1,022
|
)
|
|
(154
|
)%
|
|
$
|
1,891
|
|
|
NM
|
|
|
$
|
(470
|
)
|
Other
|
234
|
|
|
15
|
|
|
204
|
|
|
11
|
%
|
|
184
|
|
|||
Total gains (losses) on divestitures and other, net
|
$
|
(788
|
)
|
|
(138
|
)
|
|
$
|
2,095
|
|
|
NM
|
|
|
$
|
(286
|
)
|
•
|
The Company recognized a loss of
$538 million
associated with the divestiture of certain coalbed methane properties and related midstream assets in the Rockies for net proceeds of
$154 million
after closing adjustments.
|
•
|
The Company recognized a loss of
$350 million
associated with the divestiture of certain EOR assets in the Rockies, with a sales price of $703 million, for net proceeds of
$675 million
after closing adjustments.
|
•
|
The Company recognized a loss of
$110 million
associated with the divestiture of certain oil and gas properties and related midstream assets in East Texas, with a sales price of
$440 million
, for net proceeds of
$425 million
after closing adjustments.
|
•
|
The Company recognized income of $130 million related to the settlement of a royalty lawsuit associated with a property in the Gulf of Mexico.
|
•
|
The Company recognized a gain of $1.5 billion related to its divestiture of a 10% working interest in Offshore Area 1 in Mozambique for net proceeds of $2.64 billion.
|
•
|
The Company recognized a gain of $510 million associated with the divestiture of its Chinese subsidiary for net proceeds of $1.075 billion.
|
•
|
The Company recognized a gain of $237 million associated with the divestiture of its interest in the nonoperated Vito deepwater development, along with several surrounding exploration blocks in the Gulf of Mexico, for net proceeds of $500 million.
|
•
|
During the fourth quarter of 2014, Anadarko considered certain EOR assets in the Rockies to be held for sale and recognized a $456 million loss. At December 31, 2014, these assets were no longer considered held for sale as the volatility in the current commodity-price environment reduced the probability that these assets would be sold within the next year.
|
•
|
The Company recognized losses on assets held for sale of $704 million, primarily associated with the Pinedale/Jonah assets in Wyoming, which were sold in January 2014 for net proceeds of $581 million.
|
•
|
The Company divested its interest in a soda ash joint venture for net proceeds of $310 million and recognized a gain of $140 million while retaining its royalty interest in soda ash mined by the joint venture from the Company’s Land Grant. Additional consideration may also be received based on future revenue of the joint venture.
|
•
|
The Company recognized gains on divestitures of $94 million for certain U.S. oil and gas properties.
|
|
2015
|
|
Inc/(Dec)
vs. 2014 |
|
2014
|
|
Inc/(Dec)
vs. 2013 |
|
2013
|
||||||||
Oil and gas operating (millions)
|
$
|
1,014
|
|
|
(13
|
)%
|
|
$
|
1,171
|
|
|
7
|
%
|
|
$
|
1,092
|
|
Oil and gas operating—per BOE
|
3.32
|
|
|
(13
|
)
|
|
3.81
|
|
|
(1
|
)
|
|
3.83
|
|
|||
Oil and gas transportation (millions)
|
1,117
|
|
|
—
|
|
|
1,116
|
|
|
14
|
|
|
981
|
|
|||
Oil and gas transportation—per BOE
|
3.66
|
|
|
1
|
|
|
3.63
|
|
|
6
|
|
|
3.44
|
|
millions
|
2015
|
|
2014
|
|
2013
|
||||||
Exploration Expense
|
|
|
|
|
|
||||||
Dry hole expense
|
$
|
1,052
|
|
|
$
|
762
|
|
|
$
|
556
|
|
Impairments of unproved properties
|
1,215
|
|
|
483
|
|
|
308
|
|
|||
Geological and geophysical expense
|
168
|
|
|
168
|
|
|
208
|
|
|||
Exploration overhead and other
|
209
|
|
|
226
|
|
|
257
|
|
|||
Total exploration expense
|
$
|
2,644
|
|
|
$
|
1,639
|
|
|
$
|
1,329
|
|
•
|
The Company wrote off 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 recognized $306 million due to unsuccessful drilling activities expensed in 2015 primarily in Colombia and the Gulf of Mexico.
|
•
|
Anadarko recognized $762 million due to unsuccessful drilling activities expensed in 2014 associated with wells in the Gulf of Mexico, the Rockies, and Mozambique.
|
•
|
In 2015, 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.
|
•
|
Also in 2015, the Company recognized a $109 million impairment of unproved Utica properties resulting from an assignment of mineral interests in settlement of a legal matter.
|
•
|
In 2014, 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.
|
•
|
Also in 2014, 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.
|
•
|
The Company recognized $762 million due to unsuccessful drilling activities expensed in 2014 associated with wells in the Gulf of Mexico, the Rockies, and Mozambique.
|
•
|
The Company recognized $556 million due to unsuccessful drilling activities expensed in 2013 associated with wells in Kenya, Sierra Leone, and Côte d’Ivoire.
|
•
|
In 2014, the Company recognized impairments of $390 million in the Gulf of Mexico, Sierra Leone, and certain U.S. onshore oil and gas properties discussed above.
|
•
|
In 2013, the Company recognized impairments of $89 million in China, $53 million in Brazil, and $53 million for a U.S. onshore property as a result of changes in the Company’s drilling plans.
|
millions except percentages
|
2015
|
|
Inc/(Dec)
vs. 2014 |
|
2014
|
|
Inc/(Dec)
vs. 2013 |
|
2013
|
||||||||
General and administrative
|
$
|
1,176
|
|
|
(11
|
)%
|
|
$
|
1,316
|
|
|
21
|
%
|
|
$
|
1,090
|
|
Depreciation, depletion, and amortization
|
4,603
|
|
|
1
|
|
|
4,550
|
|
|
16
|
|
|
3,927
|
|
|||
Other taxes
|
553
|
|
|
(56
|
)
|
|
1,244
|
|
|
16
|
|
|
1,077
|
|
|||
Impairments
|
5,075
|
|
|
NM
|
|
|
836
|
|
|
5
|
|
|
794
|
|
|||
Other operating expense
|
271
|
|
|
64
|
|
|
165
|
|
|
85
|
|
|
89
|
|
•
|
U.S. severance taxes decreased by $272 million, Algerian exceptional profits taxes decreased by $238 million, and ad valorem taxes decreased by $155 million. These decreases were primarily due to lower commodity prices.
|
•
|
Chinese windfall profits tax decreased by $24 million as a result of the sale of the Company’s Chinese subsidiary in August 2014.
|
•
|
Algerian exceptional profits taxes increased by $128 million attributable to higher oil sales volumes and the commencement of NGLs sales in 2014.
|
•
|
U.S. onshore ad valorem taxes increased by $85 million attributable to increased activity related to U.S. onshore properties.
|
•
|
Chinese windfall profits tax decreased by $47 million resulting from maintenance downtime in the first half of 2014 and the sale of the Company’s Chinese subsidiary in August 2014.
|
•
|
The Company recognized impairments of $3.0 billion related to the Company’s Greater Natural Buttes oil and gas properties and $482 million for related midstream properties in the Rockies, $687 million for other U.S. onshore oil and gas properties primarily in the Southern and Appalachia Region, $557 million for other midstream properties primarily in the Rockies, and $349 million for oil and gas properties in the Gulf of Mexico, all due to lower forecasted commodity prices.
|
•
|
The Company recognized impairments of $545 million related to certain U.S. onshore oil and gas properties and $276 million related to certain oil and gas properties in the Gulf of Mexico that were impaired primarily due to lower forecasted commodity prices.
|
•
|
The Company recognized impairments of $562 million due to a reduction in estimated future net cash flows and downward revisions of reserves for certain Gulf of Mexico properties resulting from changes to the Company’s development plans.
|
•
|
The Company recognized impairments of $142 million for certain U.S. onshore oil and gas properties and $49 million for related midstream assets due to downward revisions of reserves resulting from changes to the Company’s development plans.
|
•
|
The Company recognized impairments of $30 million for certain midstream properties due to a reduction in estimated future cash flows.
|
millions
|
2015
|
|
2014
|
|
2013
|
||||||
Interest Expense
|
|
|
|
|
|
||||||
Current debt, long-term debt, and other
|
$
|
989
|
|
|
$
|
973
|
|
|
$
|
949
|
|
Capitalized interest
|
(164
|
)
|
|
(201
|
)
|
|
(263
|
)
|
|||
Total interest expense
|
$
|
825
|
|
|
$
|
772
|
|
|
$
|
686
|
|
•
|
Interest expense on debt increased by $16 million primarily due to higher debt outstanding during 2015, partially offset by decreased debt amortization costs for the $5.0 billion senior secured revolving credit facility ($5.0 billion Facility) that was replaced in January 2015.
|
•
|
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.
|
•
|
Interest expense increased $13 million due to increased long-term debt outstanding during 2014.
|
•
|
Capitalized interest decreased by $62 million primarily due to lower construction-in-progress balances for the Mozambique liquefied natural gas project and the completion of certain U.S. pipeline projects in late 2013 and early 2014.
|
millions
|
2015
|
|
2014
|
|
2013
|
||||||
(Gains) Losses on Derivatives, net
|
|
|
|
|
|
||||||
(Gains) losses on commodity derivatives, net
|
$
|
(367
|
)
|
|
$
|
(589
|
)
|
|
$
|
141
|
|
(Gains) losses on interest-rate and other derivatives, net
|
268
|
|
|
786
|
|
|
(539
|
)
|
|||
Total (gains) losses on derivatives, net
|
$
|
(99
|
)
|
|
$
|
197
|
|
|
$
|
(398
|
)
|
millions
|
2015
|
|
2014
|
|
2013
|
||||||
Other (Income) Expense, net
|
|
|
|
|
|
||||||
Interest income
|
$
|
(13
|
)
|
|
$
|
(26
|
)
|
|
$
|
(19
|
)
|
Other
|
162
|
|
|
46
|
|
|
108
|
|
|||
Total other (income) expense, net
|
$
|
149
|
|
|
$
|
20
|
|
|
$
|
89
|
|
•
|
Losses associated with certain equity investments increased by $61 million as a result of lower commodity prices.
|
•
|
Unfavorable changes in foreign currency gains/losses of $35 million were primarily associated with foreign currency held in escrow pending final determination of the Company’s Brazilian tax liability attributable to the 2008 divestiture of the Peregrino field offshore Brazil.
|
•
|
Environmental reserve accruals associated with properties previously acquired by Anadarko increased by $22 million.
|
•
|
Interest income from short-term investments decreased by $13 million.
|
•
|
In 2013, as a result of a Chapter 11 bankruptcy declaration by a third party, the U.S. Department of the Interior ordered Anadarko to perform the decommissioning of a production facility and related wells, which were previously sold to the third party. The Company accrued costs of $117 million during 2013 to decommission the production facility and related wells and recognized a $22 million increase in the estimated decommissioning costs in 2014. Anadarko has completed the decommissioning of the facility and expects to complete the remaining decommissioning of the wells in 2016.
|
•
|
As a result of a prior acquisition, the Company recognized a restoration liability of $50 million in 2013 with respect to a landfill located in California for which the Company was notified that it is a potentially responsible party.
|
•
|
The Company reversed the $56 million tax indemnification liability associated with the 2006 sale of the Company’s Canadian subsidiary in 2013. The indemnity was reversed as a result of certain changes to Canadian tax laws.
|
millions
|
2015
|
|
2014
|
|
2013
|
||||||
Tronox-related contingent loss
|
$
|
5
|
|
|
$
|
4,360
|
|
|
$
|
850
|
|
millions except percentages
|
2015
|
|
2014
|
|
2013
|
||||||
Income tax expense (benefit)
|
$
|
(2,877
|
)
|
|
$
|
1,617
|
|
|
$
|
1,165
|
|
Income (loss) before income taxes
|
(9,689
|
)
|
|
54
|
|
|
2,106
|
|
|||
Effective tax rate
|
30
|
%
|
|
2,994
|
%
|
|
55
|
%
|
•
|
tax impact from foreign operations
|
•
|
non-deductible Algerian exceptional profits tax for Algerian income tax purposes
|
•
|
net changes in uncertain tax positions
|
•
|
dispositions of non-deductible goodwill
|
•
|
net changes in uncertain tax positions related to the settlement agreement associated with the Tronox Adversary Proceeding
|
•
|
net changes in other uncertain tax positions
|
•
|
non-deductible Algerian exceptional profits tax for Algerian income tax purposes
|
•
|
tax impact from foreign operations
|
•
|
tax impact from foreign operations
|
•
|
non-deductible Algerian exceptional profits tax for Algerian income tax purposes
|
•
|
deferred tax adjustments
|
millions except percentages
|
2015
|
|
2014
|
|
2013
|
||||||
Net income (loss) attributable to noncontrolling interests
|
$
|
(120
|
)
|
|
$
|
187
|
|
|
$
|
140
|
|
Public ownership in WES, limited partnership interest
|
55.1
|
%
|
|
55.0
|
%
|
|
56.4
|
%
|
|||
Public ownership in WGP, limited partnership interest
|
12.7
|
%
|
|
11.7
|
%
|
|
9.0
|
%
|
millions except percentages
|
2015
|
|
2014
|
|
2013
|
||||||
Net cash provided by (used in) operating activities
|
$
|
(1,877
|
)
|
|
$
|
8,466
|
|
|
$
|
8,888
|
|
Net cash provided by (used in) investing activities
|
(4,771
|
)
|
|
(6,472
|
)
|
|
(8,216
|
)
|
|||
Net cash provided by (used in) financing activities
|
220
|
|
|
1,675
|
|
|
623
|
|
|||
Total debt
|
15,751
|
|
|
15,092
|
|
|
13,565
|
|
|||
Total equity
|
15,457
|
|
|
22,318
|
|
|
23,650
|
|
|||
Debt to total capitalization ratio
|
50.5
|
%
|
|
40.3
|
%
|
|
36.5
|
%
|
millions
|
2015
|
|
2014
|
|
2013
|
||||||
Cash Flows from Investing Activities
|
|
|
|
|
|
||||||
Additions to properties and equipment and dry holes
|
$
|
6,067
|
|
|
$
|
9,508
|
|
|
$
|
7,721
|
|
Adjustments for capital expenditures
|
|
|
|
|
|
||||||
Changes in capital accruals
|
(226
|
)
|
|
(237
|
)
|
|
246
|
|
|||
Corporate acquisitions
|
—
|
|
|
—
|
|
|
475
|
|
|||
Other
|
47
|
|
|
(15
|
)
|
|
81
|
|
|||
Total capital expenditures
(1)
|
$
|
5,888
|
|
|
$
|
9,256
|
|
|
$
|
8,523
|
|
(1)
|
Includes WES capital expenditures of
$525 million
in
2015
, $696 million in
2014
, and $792 million in
2013
.
|
millions
|
2015
|
|
2014
|
|
2013
|
|
Description
|
||||||
Issuances
|
$
|
500
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
WES 3.950% Senior Notes due 2025
|
|
—
|
|
|
625
|
|
|
—
|
|
|
3.450% Senior Notes due 2024
|
|||
|
—
|
|
|
625
|
|
|
—
|
|
|
4.500% Senior Notes due 2044
|
|||
|
—
|
|
|
100
|
|
|
250
|
|
|
WES 2.600% Senior Notes due 2018
|
|||
|
—
|
|
|
400
|
|
|
—
|
|
|
WES 5.450% Senior Notes due 2044
|
|||
Repayments
|
—
|
|
|
(500
|
)
|
|
—
|
|
|
7.625% Senior Notes due 2014
|
|||
|
—
|
|
|
(275
|
)
|
|
—
|
|
|
5.750% Senior Notes due 2014
|
millions
|
2015
|
|
2014
|
|
2013
|
|
Description
|
||||||
Borrowings
|
$
|
1,800
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
364-Day Facility
|
|
1,500
|
|
|
—
|
|
|
—
|
|
|
$5.0 billion Facility
|
|||
|
400
|
|
|
1,160
|
|
|
710
|
|
|
WES RCF
|
|||
Repayments
|
(1,800
|
)
|
|
—
|
|
|
—
|
|
|
364-Day Facility
|
|||
|
(1,500
|
)
|
|
—
|
|
|
—
|
|
|
$5.0 billion Facility
|
|||
|
(610
|
)
|
|
(650
|
)
|
|
(710
|
)
|
|
WES RCF
|
|
Obligations by Period
(1)
|
||||||||||||||||||
millions
|
2016
|
|
2017-2018
|
|
2019-2020
|
|
2021 and beyond
|
|
Total
|
||||||||||
Total debt
|
|
|
|
|
|
|
|
|
|
||||||||||
Principal—total borrowings at face value
(2)
|
$
|
2,033
|
|
|
$
|
2,516
|
|
|
$
|
1,200
|
|
|
$
|
11,563
|
|
|
$
|
17,312
|
|
Principal—capital lease obligation
|
—
|
|
|
—
|
|
|
1
|
|
|
19
|
|
|
20
|
|
|||||
Investee entities’ debt
(3)
|
—
|
|
|
—
|
|
|
—
|
|
|
2,853
|
|
|
2,853
|
|
|||||
Interest on borrowings
|
932
|
|
|
1,500
|
|
|
1,161
|
|
|
7,460
|
|
|
11,053
|
|
|||||
Interest on capital lease obligations
|
2
|
|
|
3
|
|
|
4
|
|
|
13
|
|
|
22
|
|
|||||
Investee entities’ interest
(3)
|
50
|
|
|
144
|
|
|
173
|
|
|
2,351
|
|
|
2,718
|
|
|||||
Operating leases
|
|
|
|
|
|
|
|
|
|
||||||||||
Drilling rig commitments
|
739
|
|
|
834
|
|
|
215
|
|
|
—
|
|
|
1,788
|
|
|||||
Production platforms
|
21
|
|
|
43
|
|
|
50
|
|
|
23
|
|
|
137
|
|
|||||
Other
|
46
|
|
|
79
|
|
|
49
|
|
|
18
|
|
|
192
|
|
|||||
Oil and gas activities
|
741
|
|
|
886
|
|
|
276
|
|
|
314
|
|
|
2,217
|
|
|||||
Asset retirement obligations
|
309
|
|
|
128
|
|
|
304
|
|
|
1,318
|
|
|
2,059
|
|
|||||
Midstream and marketing activities
|
1,114
|
|
|
2,137
|
|
|
1,996
|
|
|
2,612
|
|
|
7,859
|
|
|||||
Derivative liabilities
(4)
|
54
|
|
|
419
|
|
|
513
|
|
|
500
|
|
|
1,486
|
|
|||||
Uncertain tax positions, interest, and penalties
(5)
|
418
|
|
|
65
|
|
|
—
|
|
|
1,307
|
|
|
1,790
|
|
|||||
Environmental liabilities
|
24
|
|
|
25
|
|
|
32
|
|
|
64
|
|
|
145
|
|
|||||
Other
|
—
|
|
|
116
|
|
|
—
|
|
|
—
|
|
|
116
|
|
|||||
Total
|
$
|
6,483
|
|
|
$
|
8,895
|
|
|
$
|
5,974
|
|
|
$
|
30,415
|
|
|
$
|
51,767
|
|
(1)
|
This table does not include litigation-related contingent liabilities or the Company’s pension and postretirement benefit obligations. See
Note 15—Contingencies
and
Note 16—Pension Plans, Other Postretirement Benefits, and Defined-Contribution Plans
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
(2)
|
Includes the fully accreted principal amount of the Zero Coupons of approximately $2.4 billion as coming due after
2020
. 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
$839 million
in October
2016
(the next potential put date).
|
(3)
|
Anadarko has legal right of setoff and intends to net-settle its obligations under each of the notes payable to the investees with the distributable value of its interest in the corresponding investee. Accordingly, the investments and the obligations are presented net on the Company’s Consolidated Balance Sheets in other long-term liabilities—other for all periods presented. These notes payable provide for a variable rate of interest, reset quarterly. Therefore, future interest payments presented in the table above are estimated using the forward LIBOR rate curve. Further, the above table does not reflect the preferred return that Anadarko receives on its investment in these entities, which is also LIBOR-based, but with a lower margin than the margin on the associated notes payable. See
Note 8—Equity-Method Investments
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
(4)
|
Represents Anadarko’s gross derivative liability after taking into account the impacts of netting margin and collateral balances deposited with counterparties. See
Note 9—Derivative Instruments
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
(5)
|
See
Note 12—Income Taxes
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
|
•
|
changes in commodity prices
|
•
|
changes 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
|
•
|
changes 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, 2016
|
/s/ KPMG LLP
|
|
Houston, Texas
|
February 17, 2016
|
/s/ KPMG LLP
|
|
Houston, Texas
|
February 17, 2016
|
|
Years Ended December 31,
|
||||||||||
millions except per-share amounts
|
2015
|
|
2014
|
|
2013
|
||||||
Revenues and Other
|
|
|
|
|
|
||||||
Oil and condensate sales
|
$
|
5,420
|
|
|
$
|
9,748
|
|
|
$
|
9,178
|
|
Natural-gas sales
|
2,007
|
|
|
3,849
|
|
|
3,388
|
|
|||
Natural-gas liquids sales
|
833
|
|
|
1,572
|
|
|
1,262
|
|
|||
Gathering, processing, and marketing sales
|
1,226
|
|
|
1,206
|
|
|
1,039
|
|
|||
Gains (losses) on divestitures and other, net
|
(788
|
)
|
|
2,095
|
|
|
(286
|
)
|
|||
Total
|
8,698
|
|
|
18,470
|
|
|
14,581
|
|
|||
Costs and Expenses
|
|
|
|
|
|
||||||
Oil and gas operating
|
1,014
|
|
|
1,171
|
|
|
1,092
|
|
|||
Oil and gas transportation
|
1,117
|
|
|
1,116
|
|
|
981
|
|
|||
Exploration
|
2,644
|
|
|
1,639
|
|
|
1,329
|
|
|||
Gathering, processing, and marketing
|
1,054
|
|
|
1,030
|
|
|
869
|
|
|||
General and administrative
|
1,176
|
|
|
1,316
|
|
|
1,090
|
|
|||
Depreciation, depletion, and amortization
|
4,603
|
|
|
4,550
|
|
|
3,927
|
|
|||
Other taxes
|
553
|
|
|
1,244
|
|
|
1,077
|
|
|||
Impairments
|
5,075
|
|
|
836
|
|
|
794
|
|
|||
Other operating expense
|
271
|
|
|
165
|
|
|
89
|
|
|||
Total
|
17,507
|
|
|
13,067
|
|
|
11,248
|
|
|||
Operating Income (Loss)
|
(8,809
|
)
|
|
5,403
|
|
|
3,333
|
|
|||
Other (Income) Expense
|
|
|
|
|
|
||||||
Interest expense
|
825
|
|
|
772
|
|
|
686
|
|
|||
(Gains) losses on derivatives, net
|
(99
|
)
|
|
197
|
|
|
(398
|
)
|
|||
Other (income) expense, net
|
149
|
|
|
20
|
|
|
89
|
|
|||
Tronox-related contingent loss
|
5
|
|
|
4,360
|
|
|
850
|
|
|||
Total
|
880
|
|
|
5,349
|
|
|
1,227
|
|
|||
Income (Loss) Before Income Taxes
|
(9,689
|
)
|
|
54
|
|
|
2,106
|
|
|||
Income tax expense (benefit)
|
(2,877
|
)
|
|
1,617
|
|
|
1,165
|
|
|||
Net Income (Loss)
|
(6,812
|
)
|
|
(1,563
|
)
|
|
941
|
|
|||
Net income (loss) attributable to noncontrolling interests
|
(120
|
)
|
|
187
|
|
|
140
|
|
|||
Net Income (Loss) Attributable to Common Stockholders
|
$
|
(6,692
|
)
|
|
$
|
(1,750
|
)
|
|
$
|
801
|
|
|
|
|
|
|
|
||||||
Per Common Share
|
|
|
|
|
|
||||||
Net income (loss) attributable to common stockholders—basic
|
$
|
(13.18
|
)
|
|
$
|
(3.47
|
)
|
|
$
|
1.58
|
|
Net income (loss) attributable to common stockholders—diluted
|
$
|
(13.18
|
)
|
|
$
|
(3.47
|
)
|
|
$
|
1.58
|
|
Average Number of Common Shares Outstanding—Basic
|
508
|
|
|
506
|
|
|
502
|
|
|||
Average Number of Common Shares Outstanding—Diluted
|
508
|
|
|
506
|
|
|
505
|
|
|||
Dividends (per Common Share)
|
$
|
1.08
|
|
|
$
|
0.99
|
|
|
$
|
0.54
|
|
|
Years Ended December 31,
|
||||||||||
millions
|
2015
|
|
2014
|
|
2013
|
||||||
Net Income (Loss)
|
$
|
(6,812
|
)
|
|
$
|
(1,563
|
)
|
|
$
|
941
|
|
Other Comprehensive Income (Loss)
|
|
|
|
|
|
||||||
Adjustments for derivative instruments
|
|
|
|
|
|
||||||
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net
|
10
|
|
|
9
|
|
|
11
|
|
|||
Income taxes on reclassification of previously deferred derivative losses to (gains) losses on derivatives, net
|
(4
|
)
|
|
(3
|
)
|
|
(4
|
)
|
|||
Total adjustments for derivative instruments, net of taxes
|
6
|
|
|
6
|
|
|
7
|
|
|||
Adjustments for pension and other postretirement plans
|
|
|
|
|
|
||||||
Net gain (loss) incurred during period
|
49
|
|
|
(405
|
)
|
|
416
|
|
|||
Income taxes on net gain (loss) incurred during period
|
(18
|
)
|
|
149
|
|
|
(152
|
)
|
|||
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
|
63
|
|
|
27
|
|
|
132
|
|
|||
Income taxes on amortization of net actuarial (gain) loss to general and administrative expense
|
(20
|
)
|
|
(9
|
)
|
|
(49
|
)
|
|||
Amortization of net prior service (credit) cost to general and administrative expense
|
(4
|
)
|
|
—
|
|
|
1
|
|
|||
Income taxes on amortization of net prior service (credit) cost to general and administrative expense
|
2
|
|
|
—
|
|
|
—
|
|
|||
Total adjustments for pension and other postretirement plans, net of taxes
|
128
|
|
|
(238
|
)
|
|
348
|
|
|||
Total
|
134
|
|
|
(232
|
)
|
|
355
|
|
|||
Comprehensive Income (Loss)
|
(6,678
|
)
|
|
(1,795
|
)
|
|
1,296
|
|
|||
Comprehensive income (loss) attributable to noncontrolling interests
|
(120
|
)
|
|
187
|
|
|
140
|
|
|||
Comprehensive Income (Loss) Attributable to Common Stockholders
|
$
|
(6,558
|
)
|
|
$
|
(1,982
|
)
|
|
$
|
1,156
|
|
|
December 31,
|
||||||
millions
|
2015
|
|
2014
|
||||
ASSETS
|
|
|
|
||||
Current Assets
|
|
|
|
||||
Cash and cash equivalents
|
$
|
939
|
|
|
$
|
7,369
|
|
Accounts receivable (net of allowance of $11 million and $7 million)
|
|
|
|
||||
Customers
|
652
|
|
|
1,118
|
|
||
Others
|
1,817
|
|
|
1,409
|
|
||
Other current assets
|
574
|
|
|
603
|
|
||
Total
|
3,982
|
|
|
10,499
|
|
||
Properties and Equipment
|
|
|
|
||||
Cost
|
70,683
|
|
|
75,107
|
|
||
Less accumulated depreciation, depletion, and amortization
|
36,932
|
|
|
33,518
|
|
||
Net properties and equipment
|
33,751
|
|
|
41,589
|
|
||
Other Assets
|
2,350
|
|
|
2,310
|
|
||
Goodwill and Other Intangible Assets
|
6,331
|
|
|
6,569
|
|
||
Total Assets
|
$
|
46,414
|
|
|
$
|
60,967
|
|
|
|
|
|
||||
LIABILITIES AND EQUITY
|
|
|
|
||||
Current Liabilities
|
|
|
|
||||
Accounts payable
|
$
|
2,850
|
|
|
$
|
3,683
|
|
Current asset retirement obligations
|
309
|
|
|
257
|
|
||
Interest payable
|
247
|
|
|
247
|
|
||
Other taxes payable
|
318
|
|
|
332
|
|
||
Accrued expenses
|
424
|
|
|
505
|
|
||
Short-term debt
|
33
|
|
|
—
|
|
||
Tronox-related contingent liability
|
—
|
|
|
5,210
|
|
||
Total
|
4,181
|
|
|
10,234
|
|
||
Long-term Debt
|
15,718
|
|
|
15,092
|
|
||
Other Long-term Liabilities
|
|
|
|
||||
Deferred income taxes
|
5,400
|
|
|
8,527
|
|
||
Asset retirement obligations
|
1,750
|
|
|
1,796
|
|
||
Other
|
3,908
|
|
|
3,000
|
|
||
Total
|
11,058
|
|
|
13,323
|
|
||
|
|
|
|
||||
Equity
|
|
|
|
||||
Stockholders’ equity
|
|
|
|
||||
Common stock, par value $0.10 per share
(1.0 billion shares authorized, 528.3 million and 525.9 million shares issued) |
52
|
|
|
52
|
|
||
Paid-in capital
|
9,265
|
|
|
9,005
|
|
||
Retained earnings
|
4,880
|
|
|
12,125
|
|
||
Treasury stock (20.0 million and 19.3 million shares)
|
(995
|
)
|
|
(940
|
)
|
||
Accumulated other comprehensive income (loss)
|
(383
|
)
|
|
(517
|
)
|
||
Total Stockholders’ Equity
|
12,819
|
|
|
19,725
|
|
||
Noncontrolling interests
|
2,638
|
|
|
2,593
|
|
||
Total Equity
|
15,457
|
|
|
22,318
|
|
||
Total Liabilities and Equity
|
$
|
46,414
|
|
|
$
|
60,967
|
|
|
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, 2012
|
$
|
51
|
|
|
$
|
8,230
|
|
|
$
|
13,829
|
|
|
$
|
(841
|
)
|
|
$
|
(640
|
)
|
|
$
|
1,253
|
|
|
$
|
21,882
|
|
Net income (loss)
|
—
|
|
|
—
|
|
|
801
|
|
|
—
|
|
|
—
|
|
|
140
|
|
|
941
|
|
|||||||
Common stock issued
|
1
|
|
|
292
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
293
|
|
|||||||
Dividends—common stock
|
—
|
|
|
—
|
|
|
(274
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(274
|
)
|
|||||||
Repurchase of common stock
|
—
|
|
|
—
|
|
|
—
|
|
|
(54
|
)
|
|
—
|
|
|
—
|
|
|
(54
|
)
|
|||||||
Subsidiary equity transactions
|
—
|
|
|
107
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
554
|
|
|
661
|
|
|||||||
Distributions to noncontrolling interest owners
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(156
|
)
|
|
(156
|
)
|
|||||||
Contributions from noncontrolling interest owners
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
2
|
|
|||||||
Reclassification of previously deferred derivative losses to (gains) losses on derivatives, net
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7
|
|
|
—
|
|
|
7
|
|
|||||||
Adjustments for pension and other postretirement plans
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
348
|
|
|
—
|
|
|
348
|
|
|||||||
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
|
|
|
Years Ended December 31,
|
||||||||||
millions
|
2015
|
|
2014
|
|
2013
|
||||||
Cash Flows from Operating Activities
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
(6,812
|
)
|
|
$
|
(1,563
|
)
|
|
$
|
941
|
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities
|
|
|
|
|
|
||||||
Depreciation, depletion, and amortization
|
4,603
|
|
|
4,550
|
|
|
3,927
|
|
|||
Deferred income taxes
|
(3,152
|
)
|
|
(105
|
)
|
|
90
|
|
|||
Dry hole expense and impairments of unproved properties
|
2,267
|
|
|
1,245
|
|
|
864
|
|
|||
Impairments
|
5,075
|
|
|
836
|
|
|
794
|
|
|||
(Gains) losses on divestitures, net
|
1,022
|
|
|
(1,891
|
)
|
|
470
|
|
|||
Total (gains) losses on derivatives, net
|
(100
|
)
|
|
207
|
|
|
(392
|
)
|
|||
Operating portion of net cash received (paid) in settlement of derivative instruments
|
335
|
|
|
371
|
|
|
85
|
|
|||
Other
|
320
|
|
|
327
|
|
|
246
|
|
|||
Changes in assets and liabilities
|
|
|
|
|
|
||||||
Tronox-related contingent liability
|
(5,210
|
)
|
|
4,360
|
|
|
850
|
|
|||
(Increase) decrease in accounts receivable
|
(2
|
)
|
|
103
|
|
|
719
|
|
|||
Increase (decrease) in accounts payable and accrued expenses
|
(995
|
)
|
|
97
|
|
|
148
|
|
|||
Other items, net
|
772
|
|
|
(71
|
)
|
|
146
|
|
|||
Net cash provided by (used in) operating activities
|
(1,877
|
)
|
|
8,466
|
|
|
8,888
|
|
|||
Cash Flows from Investing Activities
|
|
|
|
|
|
||||||
Additions to properties and equipment and dry hole costs
|
(6,067
|
)
|
|
(9,508
|
)
|
|
(7,721
|
)
|
|||
Acquisition of businesses
|
(3
|
)
|
|
(1,527
|
)
|
|
(473
|
)
|
|||
Divestitures of properties and equipment and other assets
|
1,415
|
|
|
4,968
|
|
|
567
|
|
|||
Other, net
|
(116
|
)
|
|
(405
|
)
|
|
(589
|
)
|
|||
Net cash provided by (used in) investing activities
|
(4,771
|
)
|
|
(6,472
|
)
|
|
(8,216
|
)
|
|||
Cash Flows from Financing Activities
|
|
|
|
|
|
||||||
Borrowings, net of issuance costs
|
4,632
|
|
|
2,879
|
|
|
958
|
|
|||
Repayments of debt
|
(4,033
|
)
|
|
(1,425
|
)
|
|
(710
|
)
|
|||
Financing portion of net cash paid in settlement of derivative instruments
|
(35
|
)
|
|
(222
|
)
|
|
—
|
|
|||
Increase (decrease) in outstanding checks
|
(23
|
)
|
|
62
|
|
|
(13
|
)
|
|||
Dividends paid
|
(553
|
)
|
|
(505
|
)
|
|
(274
|
)
|
|||
Repurchase of common stock
|
(55
|
)
|
|
(45
|
)
|
|
(54
|
)
|
|||
Issuance of common stock, including tax benefit on share-based compensation awards
|
34
|
|
|
121
|
|
|
146
|
|
|||
Sale of subsidiary units
|
187
|
|
|
1,026
|
|
|
724
|
|
|||
Issuance of tangible equity units — equity component
|
348
|
|
|
—
|
|
|
—
|
|
|||
Distributions to noncontrolling interest owners
|
(282
|
)
|
|
(216
|
)
|
|
(156
|
)
|
|||
Contributions from noncontrolling interest owners
|
—
|
|
|
—
|
|
|
2
|
|
|||
Net cash provided by (used in) financing activities
|
220
|
|
|
1,675
|
|
|
623
|
|
|||
Effect of Exchange Rate Changes on Cash
|
(2
|
)
|
|
2
|
|
|
(68
|
)
|
|||
Net Increase (Decrease) in Cash and Cash Equivalents
|
(6,430
|
)
|
|
3,671
|
|
|
1,227
|
|
|||
Cash and Cash Equivalents at Beginning of Period
|
7,369
|
|
|
3,698
|
|
|
2,471
|
|
|||
Cash and Cash Equivalents at End of Period
|
$
|
939
|
|
|
$
|
7,369
|
|
|
$
|
3,698
|
|
millions
|
2015
|
|
2014
|
||||
Oil
|
$
|
116
|
|
|
$
|
133
|
|
Natural gas
|
36
|
|
|
27
|
|
||
NGLs
|
64
|
|
|
83
|
|
||
Total inventories
|
$
|
216
|
|
|
$
|
243
|
|
millions
|
|
|
||
Current assets
|
|
$
|
63
|
|
Properties and equipment
|
|
467
|
|
|
Other intangible assets
|
|
811
|
|
|
Accounts payable
|
|
(19
|
)
|
|
Accrued expenses
|
|
(38
|
)
|
|
Deferred income taxes
|
|
(1
|
)
|
|
Asset retirement obligations
|
|
(9
|
)
|
|
Goodwill
|
|
283
|
|
|
Total assets acquired and liabilities assumed
|
|
$
|
1,557
|
|
millions
|
2015
|
|
2014
|
|
2013
|
||||||
Proceeds received
|
$
|
1,415
|
|
|
$
|
4,968
|
|
|
$
|
567
|
|
Gains (losses) on divestitures, net
|
(1,022
|
)
|
|
1,891
|
|
|
(470
|
)
|
•
|
The Company sold certain coalbed methane properties and related midstream assets in the Rocky Mountains Region (Rockies) for net proceeds of
$154 million
, after closing adjustments, and recognized a loss of
$538 million
. These assets were included in the oil and gas exploration and production and midstream reporting segments.
|
•
|
The Company sold certain U.S. onshore oil and gas properties and related midstream assets in East Texas, with a sales price of
$440 million
, for net proceeds of
$425 million
after closing adjustments, and recognized a loss of
$110 million
. These assets were included in the oil and gas exploration and production and midstream reporting segments.
|
•
|
The Company sold certain enhanced oil recovery (EOR) assets in the Rockies, with a sales price of
$703 million
, for net proceeds of
$675 million
after closing adjustments, and recognized a loss of
$350 million
. These assets were included in the oil and gas exploration and production reporting segment.
|
•
|
The Company sold a
10%
working interest in Offshore Area 1 in Mozambique for
$2.64 billion
and recognized a gain of
$1.5 billion
.
|
•
|
The Company sold its Chinese subsidiary for
$1.075 billion
and recognized a gain of
$510 million
.
|
•
|
The Company sold its interest in the nonoperated Vito deepwater development, along with several surrounding exploration blocks in the Gulf of Mexico for
$500 million
, and recognized a gain of
$237 million
.
|
•
|
The Company sold its interest in the Pinedale/Jonah assets in Wyoming for
$581 million
.
|
•
|
During the fourth quarter of 2014, Anadarko considered certain EOR assets in the Rockies to be held for sale and recognized losses of
$456 million
. These assets were remeasured to their fair value using a market approach and Level 2 fair-value measurement. Volatility in the then-current commodity-price environment had reduced the probability that the assets would be sold within one year and the assets were therefore no longer considered held for sale at
December 31, 2014
.
|
•
|
The Company sold its interests in a soda ash joint venture and certain U.S. onshore and Indonesian oil and gas properties and recognized net gains of
$234 million
, primarily related to the Company’s divestiture of its interests in the soda ash joint venture and certain U.S. oil and gas properties included in the oil and gas exploration and production reporting segment.
|
•
|
The Company recognized losses of
$704 million
primarily related to its Pinedale/Jonah assets included in the oil and gas exploration and production reporting segment considered to be held for sale at December 31, 2013. The sale of these assets closed in 2014 as discussed above.
|
millions
|
2015
|
|
2014
|
||||
Oil and gas exploration and production
(1)
|
$
|
59,389
|
|
|
$
|
63,674
|
|
Midstream
|
8,458
|
|
|
8,647
|
|
||
Other
|
2,836
|
|
|
2,786
|
|
||
Gross properties and equipment
|
$
|
70,683
|
|
|
$
|
75,107
|
|
Less accumulated depreciation, depletion, and amortization
|
36,932
|
|
|
33,518
|
|
||
Net properties and equipment
|
$
|
33,751
|
|
|
$
|
41,589
|
|
(1)
|
Includes costs associated with unproved properties of
$3.5 billion
at
December 31, 2015
, and
$5.1 billion
at
December 31, 2014
.
|
|
2015
|
|
2014
|
|
2013
|
||||||||||||||||||
millions
|
Impairment
|
|
Fair Value
(1)
|
|
Impairment
|
|
Fair Value
(1)
|
|
Impairment
|
|
Fair Value
(1)
|
||||||||||||
Oil and gas exploration and production
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Long-lived assets held for use
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
U.S. onshore properties
|
$
|
3,684
|
|
|
$
|
1,253
|
|
|
$
|
545
|
|
|
$
|
552
|
|
|
$
|
142
|
|
|
$
|
271
|
|
Gulf of Mexico properties
|
349
|
|
|
65
|
|
|
276
|
|
|
223
|
|
|
562
|
|
|
242
|
|
||||||
Cost-method investment
(2)
|
3
|
|
|
32
|
|
|
3
|
|
|
32
|
|
|
11
|
|
|
32
|
|
||||||
Midstream
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Long-lived assets held for use
|
1,039
|
|
|
212
|
|
|
12
|
|
|
—
|
|
|
79
|
|
|
36
|
|
||||||
Total impairments
|
$
|
5,075
|
|
|
$
|
1,562
|
|
|
$
|
836
|
|
|
$
|
807
|
|
|
$
|
794
|
|
|
$
|
581
|
|
(1)
|
Measured as of the impairment date using the income approach and Level 3 inputs.
|
(2)
|
Represents the after-tax net investment.
|
millions
|
2015
|
|
2014
|
|
2013
|
||||||
Balance at January 1
|
$
|
1,522
|
|
|
$
|
2,232
|
|
|
$
|
2,062
|
|
Additions pending the determination of proved reserves
|
461
|
|
|
421
|
|
|
848
|
|
|||
Divestitures and other
(1)
|
(33
|
)
|
|
(913
|
)
|
|
(48
|
)
|
|||
Reclassifications to proved properties
|
(104
|
)
|
|
(100
|
)
|
|
(507
|
)
|
|||
Charges to exploration expense
(2)
|
(722
|
)
|
|
(118
|
)
|
|
(123
|
)
|
|||
Balance at December 31
|
$
|
1,124
|
|
|
$
|
1,522
|
|
|
$
|
2,232
|
|
(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. Given the current oil-price environment and other considerations, the Company does not expect to have substantive exploration and development activities in Brazil in the foreseeable future.
|
millions except projects
|
Number of Projects
|
|
Total
|
|
2014
|
|
2013
|
|
2012 and
prior
|
||||||||
United States—Onshore
|
18
|
|
$
|
55
|
|
|
$
|
34
|
|
|
$
|
11
|
|
|
$
|
10
|
|
United States—Offshore
|
4
|
|
314
|
|
|
77
|
|
|
80
|
|
|
157
|
|
||||
International
|
7
|
|
303
|
|
|
119
|
|
|
3
|
|
|
181
|
|
||||
|
29
|
|
$
|
672
|
|
|
$
|
230
|
|
|
$
|
94
|
|
|
$
|
348
|
|
millions
|
Gross Carrying
Amount
|
|
Accumulated
Amortization
|
|
Net Carrying
Amount
|
|
Amortization
Expense
|
||||||||
December 31, 2015
|
|
|
|
|
|
|
|
||||||||
Offshore platform leases
|
$
|
33
|
|
|
$
|
(31
|
)
|
|
$
|
2
|
|
|
$
|
2
|
|
Customer contracts
|
980
|
|
|
(46
|
)
|
|
934
|
|
|
31
|
|
||||
|
$
|
1,013
|
|
|
$
|
(77
|
)
|
|
$
|
936
|
|
|
$
|
33
|
|
December 31, 2014
|
|
|
|
|
|
|
|
||||||||
Offshore platform leases
|
$
|
33
|
|
|
$
|
(29
|
)
|
|
$
|
4
|
|
|
$
|
—
|
|
Customer contracts
|
1,004
|
|
|
(15
|
)
|
|
989
|
|
|
6
|
|
||||
|
$
|
1,037
|
|
|
$
|
(44
|
)
|
|
$
|
993
|
|
|
$
|
6
|
|
|
|
2016 Settlement
|
||
Oil
|
|
|
||
Three-Way Collars (MBbls/d)
|
|
83
|
|
|
Average price per barrel
|
|
|
||
Ceiling sold price (call)
|
|
$
|
63.82
|
|
Floor purchased price (put)
|
|
$
|
54.46
|
|
Floor sold price (put)
|
|
$
|
42.77
|
|
Natural Gas
|
|
|
||
Fixed-Price Contracts (thousand MMBtu/d)
|
|
38
|
|
|
Average price per MMBtu
|
|
$
|
2.53
|
|
NGLs
|
|
|
||
Fixed-Price Contracts (MBbls/d)
|
|
4
|
|
|
Average price per barrel
|
|
$
|
13.07
|
|
millions except percentages
|
|
|
|
Mandatory
|
|
Weighted-Average
|
|||
Notional Principal Amount
|
|
Reference Period
|
|
Termination Date
|
|
Interest Rate
|
|||
$
|
50
|
|
|
|
September 2016 – 2026
|
|
September 2016
|
|
5.910%
|
$
|
50
|
|
|
|
September 2016 – 2046
|
|
September 2016
|
|
6.290%
|
$
|
250
|
|
|
|
September 2016 – 2046
|
|
September 2018
|
|
6.310%
|
$
|
300
|
|
|
|
September 2016 – 2046
|
|
September 2020
|
|
6.509%
|
$
|
250
|
|
|
|
September 2016 – 2046
|
|
September 2021
|
|
6.724%
|
$
|
200
|
|
|
|
September 2017 – 2047
|
|
September 2018
|
|
6.049%
|
$
|
300
|
|
|
|
September 2017 – 2047
|
|
September 2020
|
|
6.569%
|
$
|
500
|
|
|
|
September 2017 – 2047
|
|
September 2021
|
|
6.654%
|
millions
|
|
Gross
Derivative Assets
|
|
Gross
Derivative Liabilities
|
||||||||||||
Balance Sheet Classification
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
||||||||
Commodity derivatives
|
|
|
|
|
|
|
|
|
||||||||
Other current assets
|
|
$
|
462
|
|
|
$
|
421
|
|
|
$
|
(177
|
)
|
|
$
|
(118
|
)
|
Other assets
|
|
8
|
|
|
1
|
|
|
—
|
|
|
—
|
|
||||
Accrued expenses
|
|
—
|
|
|
71
|
|
|
(3
|
)
|
|
(114
|
)
|
||||
Other liabilities
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6
|
)
|
||||
|
|
470
|
|
|
493
|
|
|
(180
|
)
|
|
(238
|
)
|
||||
Interest-rate derivatives
|
|
|
|
|
|
|
|
|
||||||||
Other current assets
|
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Other assets
|
|
54
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Accrued expenses
|
|
—
|
|
|
—
|
|
|
(54
|
)
|
|
—
|
|
||||
Other liabilities
|
|
—
|
|
|
—
|
|
|
(1,488
|
)
|
|
(1,217
|
)
|
||||
|
|
56
|
|
|
—
|
|
|
(1,542
|
)
|
|
(1,217
|
)
|
||||
Total derivatives
|
|
$
|
526
|
|
|
$
|
493
|
|
|
$
|
(1,722
|
)
|
|
$
|
(1,455
|
)
|
millions
|
|
|
|
|
|
|
||||||
Classification of (Gain) Loss Recognized
|
|
2015
|
|
2014
|
|
2013
|
||||||
Commodity derivatives
|
|
|
|
|
|
|
||||||
Gathering, processing, and marketing sales
(1)
|
|
$
|
(1
|
)
|
|
$
|
10
|
|
|
$
|
6
|
|
(Gains) losses on derivatives, net
|
|
(367
|
)
|
|
(589
|
)
|
|
141
|
|
|||
Interest-rate derivatives
|
|
|
|
|
|
|
||||||
(Gains) losses on derivatives, net
|
|
268
|
|
|
786
|
|
|
(539
|
)
|
|||
Total (gains) losses on derivatives, net
|
|
$
|
(100
|
)
|
|
$
|
207
|
|
|
$
|
(392
|
)
|
(1)
|
Represents the effect of Marketing and Trading Derivative Activities.
|
millions
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Netting
(1)
|
|
Collateral
|
|
Total
|
||||||||||||
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
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
December 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Assets
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity derivatives
|
$
|
—
|
|
|
$
|
493
|
|
|
$
|
—
|
|
|
$
|
(189
|
)
|
|
$
|
(13
|
)
|
|
$
|
291
|
|
Total derivative assets
|
$
|
—
|
|
|
$
|
493
|
|
|
$
|
—
|
|
|
$
|
(189
|
)
|
|
$
|
(13
|
)
|
|
$
|
291
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity derivatives
|
$
|
—
|
|
|
$
|
(238
|
)
|
|
$
|
—
|
|
|
$
|
189
|
|
|
$
|
—
|
|
|
$
|
(49
|
)
|
Interest-rate derivatives
|
—
|
|
|
(1,217
|
)
|
|
—
|
|
|
—
|
|
|
23
|
|
|
(1,194
|
)
|
||||||
Total derivative liabilities
|
$
|
—
|
|
|
$
|
(1,455
|
)
|
|
$
|
—
|
|
|
$
|
189
|
|
|
$
|
23
|
|
|
$
|
(1,243
|
)
|
(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
|
||
Applicable Market Value of WGP Common Units
(1)
|
|
WGP Common Units
|
|
APC Shares (if elected)
(1)
|
Exceeds $69.8422 (Threshold Appreciation Price)
|
|
0.7159 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 $58.20 (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
|
|
0.8591 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.
|
|
December 31,
|
||||||
millions
|
2015
|
|
2014
|
||||
Commercial paper
|
$
|
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
|
|
||
Tangible equity units - senior amortizing notes due 2018
|
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
|
|
|
—
|
|
||
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 revolving credit facility
|
300
|
|
|
510
|
|
||
Total borrowings at face value
|
$
|
17,312
|
|
|
$
|
16,687
|
|
Net unamortized discounts and premiums
(1)
|
(1,581
|
)
|
|
(1,616
|
)
|
||
Total borrowings
|
$
|
15,731
|
|
|
$
|
15,071
|
|
Capital lease obligation
|
20
|
|
|
21
|
|
||
Less current portion of long-term debt
|
33
|
|
|
—
|
|
||
Total long-term debt
(2)
|
$
|
15,718
|
|
|
$
|
15,092
|
|
(1)
|
Unamortized discounts and premiums are amortized over the term of the related debt.
|
(2)
|
The total long-term debt balance for WES was
$2.7 billion
at
December 31, 2015
, and
$2.4 billion
at
December 31, 2014
.
|
millions
|
Carrying
Value
|
|
Description
|
||
Balance at December 31, 2013
|
$
|
13,557
|
|
|
|
Issuances
|
101
|
|
|
WES 2.600% Senior Notes due 2018
|
|
|
394
|
|
|
WES 5.450% Senior Notes due 2044
|
|
|
624
|
|
|
3.450% Senior Notes due 2024
|
|
|
621
|
|
|
4.500% Senior Notes due 2044
|
|
Borrowings
|
1,160
|
|
|
WES revolving credit facility
|
|
Repayments
|
(500
|
)
|
|
7.625% Senior Notes due 2014
|
|
|
(275
|
)
|
|
5.750% Senior Notes due 2014
|
|
|
(650
|
)
|
|
WES revolving credit facility
|
|
Other, net
|
39
|
|
|
Amortization of debt discounts and premiums
|
|
Balance at December 31, 2014
|
$
|
15,071
|
|
|
|
Issuances
|
494
|
|
|
WES 3.950% Senior Notes due 2025
|
|
|
101
|
|
|
Tangible equity units - senior amortizing notes
|
|
Borrowings
|
1,500
|
|
|
$5.0 billion revolving credit facility
|
|
|
1,800
|
|
|
364-Day Facility
|
|
|
400
|
|
|
WES revolving credit facility
|
|
|
250
|
|
|
Commercial paper notes, net
(1)
|
|
Repayments
|
(1,500
|
)
|
|
$5.0 billion revolving credit facility
|
|
|
(1,800
|
)
|
|
364-Day Facility
|
|
|
(610
|
)
|
|
WES revolving credit facility
|
|
|
(16
|
)
|
|
Tangible equity units - senior amortizing notes
|
|
Other, net
|
41
|
|
|
Amortization of debt discounts and premiums
|
|
Balance at December 31, 2015
|
$
|
15,731
|
|
|
|
(1)
|
Includes repayments of
$(106) million
related to commercial paper notes with maturities greater than 90 days.
|
millions
|
Principal
Amount of
Debt Maturities
|
||
2016
|
$
|
2,033
|
|
2017
|
2,034
|
|
|
2018
|
482
|
|
|
2019
|
1,200
|
|
|
2020
|
—
|
|
millions
|
2015
|
|
2014
|
|
2013
|
||||||
Debt and other
|
$
|
989
|
|
|
$
|
973
|
|
|
$
|
949
|
|
Capitalized interest
|
(164
|
)
|
|
(201
|
)
|
|
(263
|
)
|
|||
Total interest expense
|
$
|
825
|
|
|
$
|
772
|
|
|
$
|
686
|
|
millions
|
2015
|
|
2014
|
|
2013
|
||||||
Current
|
|
|
|
|
|
||||||
Federal
|
$
|
(177
|
)
|
|
$
|
188
|
|
|
$
|
113
|
|
State
|
(18
|
)
|
|
2
|
|
|
42
|
|
|||
Foreign
|
495
|
|
|
1,574
|
|
|
873
|
|
|||
|
300
|
|
|
1,764
|
|
|
1,028
|
|
|||
Deferred
|
|
|
|
|
|
||||||
Federal
|
(2,929
|
)
|
|
(389
|
)
|
|
94
|
|
|||
State
|
(145
|
)
|
|
27
|
|
|
(9
|
)
|
|||
Foreign
|
(103
|
)
|
|
215
|
|
|
52
|
|
|||
|
(3,177
|
)
|
|
(147
|
)
|
|
137
|
|
|||
Total income tax expense (benefit)
|
$
|
(2,877
|
)
|
|
$
|
1,617
|
|
|
$
|
1,165
|
|
millions except percentages
|
2015
|
|
2014
|
|
2013
|
||||||
Income (loss) before income taxes
|
|
|
|
|
|
||||||
Domestic
|
$
|
(9,155
|
)
|
|
$
|
(3,564
|
)
|
|
$
|
428
|
|
Foreign
|
(534
|
)
|
|
3,618
|
|
|
1,678
|
|
|||
Total
|
$
|
(9,689
|
)
|
|
$
|
54
|
|
|
$
|
2,106
|
|
U.S. federal statutory tax rate
|
35
|
%
|
|
35
|
%
|
|
35
|
%
|
|||
Tax computed at the U.S. federal statutory rate
|
$
|
(3,391
|
)
|
|
$
|
19
|
|
|
$
|
737
|
|
Adjustments resulting from
|
|
|
|
|
|
||||||
State income taxes (net of federal income tax benefit)
|
(81
|
)
|
|
(11
|
)
|
|
23
|
|
|||
Tax impact from foreign operations
|
299
|
|
|
62
|
|
|
204
|
|
|||
Non-deductible Algerian exceptional profits tax
|
102
|
|
|
193
|
|
|
144
|
|
|||
Net changes in uncertain tax positions
|
54
|
|
|
1,427
|
|
|
(29
|
)
|
|||
Deferred tax adjustments
|
10
|
|
|
15
|
|
|
76
|
|
|||
Non-deductible Tronox-related contingent loss
|
—
|
|
|
(36
|
)
|
|
36
|
|
|||
(Income) loss attributable to noncontrolling interests
|
42
|
|
|
(66
|
)
|
|
(48
|
)
|
|||
Non-deductible Deepwater Horizon costs
|
26
|
|
|
32
|
|
|
—
|
|
|||
Federal manufacturing deduction
|
—
|
|
|
(27
|
)
|
|
—
|
|
|||
Dispositions of non-deductible goodwill
|
62
|
|
|
21
|
|
|
—
|
|
|||
Other, net
|
—
|
|
|
(12
|
)
|
|
22
|
|
|||
Total income tax expense (benefit)
|
$
|
(2,877
|
)
|
|
$
|
1,617
|
|
|
$
|
1,165
|
|
Effective tax rate
|
30
|
%
|
|
2,994
|
%
|
|
55
|
%
|
millions
|
2015
|
|
2014
|
||||
Federal
|
$
|
(4,721
|
)
|
|
$
|
(7,649
|
)
|
State, net of federal
|
(248
|
)
|
|
(341
|
)
|
||
Foreign
|
(431
|
)
|
|
(537
|
)
|
||
Total deferred taxes
|
$
|
(5,400
|
)
|
|
$
|
(8,527
|
)
|
millions
|
2015
|
|
2014
|
||||
Deferred tax liabilities
|
|
|
|
||||
Oil and gas exploration and development operations
|
$
|
(5,643
|
)
|
|
$
|
(8,418
|
)
|
Midstream and other depreciable properties
|
(1,049
|
)
|
|
(1,611
|
)
|
||
Mineral operations
|
(492
|
)
|
|
(412
|
)
|
||
Other
|
(470
|
)
|
|
(351
|
)
|
||
Gross long-term deferred tax liabilities
|
(7,654
|
)
|
|
(10,792
|
)
|
||
Deferred tax assets
|
|
|
|
||||
Foreign and state net operating loss carryforwards
|
586
|
|
|
558
|
|
||
U.S. foreign tax credit carryforwards
|
1,254
|
|
|
166
|
|
||
Compensation and benefit plans
|
615
|
|
|
701
|
|
||
Mark to market on derivatives
|
441
|
|
|
354
|
|
||
Settlement agreement related to the Tronox Adversary Proceeding
|
—
|
|
|
590
|
|
||
Other
|
761
|
|
|
760
|
|
||
Gross long-term deferred tax assets
|
3,657
|
|
|
3,129
|
|
||
Valuation allowances on deferred tax assets not expected to be realized
|
(1,403
|
)
|
|
(864
|
)
|
||
Net long-term deferred tax assets
|
2,254
|
|
|
2,265
|
|
||
Total deferred taxes
|
$
|
(5,400
|
)
|
|
$
|
(8,527
|
)
|
millions
|
2015
|
|
2014
|
|
2013
|
||||||
Balance at January 1
|
$
|
(864
|
)
|
|
$
|
(818
|
)
|
|
$
|
(922
|
)
|
Changes due to U.S. foreign tax credits
|
(384
|
)
|
|
11
|
|
|
58
|
|
|||
Changes due to foreign and state net operating loss carryforwards
|
10
|
|
|
64
|
|
|
(57
|
)
|
|||
Changes due to foreign capitalized costs
|
(165
|
)
|
|
(121
|
)
|
|
103
|
|
|||
Balance at December 31
|
$
|
(1,403
|
)
|
|
$
|
(864
|
)
|
|
$
|
(818
|
)
|
millions
|
Domestic
|
|
Foreign
|
|
Expiration
|
||||
Net operating loss—foreign
|
$
|
—
|
|
|
$
|
1,264
|
|
|
2016 - Indefinite
|
Net operating loss—state
|
$
|
4,762
|
|
|
$
|
—
|
|
|
2016-2035
|
Foreign tax credits
|
$
|
1,254
|
|
|
$
|
—
|
|
|
2023-2026
|
Texas margins tax credit
|
$
|
33
|
|
|
$
|
—
|
|
|
2026
|
millions
|
|
|
|
|
||||
Balance Sheet Classification
|
|
2015
|
|
2014
|
||||
Income taxes receivable
|
|
|
|
|
||||
Accounts receivable—other
|
|
$
|
1,046
|
|
|
$
|
93
|
|
Other assets
|
|
61
|
|
|
35
|
|
||
|
|
1,107
|
|
|
128
|
|
||
Income taxes (payable)
|
|
|
|
|
||||
Accrued expense
|
|
(9
|
)
|
|
(152
|
)
|
||
Total net income taxes receivable (payable)
|
|
$
|
1,098
|
|
|
$
|
(24
|
)
|
|
Assets (Liabilities)
|
||||||||||
millions
|
2015
|
|
2014
|
|
2013
|
||||||
Balance at January 1
|
$
|
(1,687
|
)
|
|
$
|
(147
|
)
|
|
$
|
(46
|
)
|
Increases related to prior-year tax positions
|
(99
|
)
|
|
(11
|
)
|
|
(54
|
)
|
|||
Decreases related to prior-year tax positions
|
89
|
|
|
39
|
|
|
3
|
|
|||
Increases related to current-year tax positions
|
(263
|
)
|
|
(1,568
|
)
|
|
(72
|
)
|
|||
Settlements
|
180
|
|
|
—
|
|
|
5
|
|
|||
Lapse of statute of limitations
|
—
|
|
|
—
|
|
|
17
|
|
|||
Balance at December 31
|
$
|
(1,780
|
)
|
|
$
|
(1,687
|
)
|
|
$
|
(147
|
)
|
|
Tax Years
|
United States
|
2008-2015
|
Algeria
|
2012-2015
|
Ghana
|
2006-2015
|
millions
|
2015
|
|
2014
|
||||
Carrying amount of asset retirement obligations at January 1
|
$
|
2,053
|
|
|
$
|
2,022
|
|
Liabilities incurred
|
104
|
|
|
119
|
|
||
Property dispositions
|
(108
|
)
|
|
(70
|
)
|
||
Liabilities settled
|
(298
|
)
|
|
(443
|
)
|
||
Accretion expense
|
102
|
|
|
93
|
|
||
Revisions in estimated liabilities
|
206
|
|
|
332
|
|
||
Carrying amount of asset retirement obligations at December 31
|
$
|
2,059
|
|
|
$
|
2,053
|
|
millions
|
|
||
2016
|
$
|
806
|
|
2017
|
604
|
|
|
2018
|
352
|
|
|
2019
|
228
|
|
|
2020
|
86
|
|
|
Later years
|
41
|
|
|
Total future minimum lease payments
|
$
|
2,117
|
|
|
Pension Benefits
|
|
Other Benefits
|
||||||||||||
millions
|
2015
|
|
2014
|
|
2015
|
|
2014
|
||||||||
Change in benefit obligation
|
|
|
|
|
|
|
|
||||||||
Benefit obligation at beginning of year
|
$
|
2,528
|
|
|
$
|
2,158
|
|
|
$
|
373
|
|
|
$
|
294
|
|
Service cost
|
118
|
|
|
99
|
|
|
9
|
|
|
7
|
|
||||
Interest cost
|
101
|
|
|
99
|
|
|
15
|
|
|
15
|
|
||||
Plan amendments
|
—
|
|
|
—
|
|
|
(89
|
)
|
|
—
|
|
||||
Actuarial (gain) loss
|
(115
|
)
|
|
337
|
|
|
(27
|
)
|
|
72
|
|
||||
Participant contributions
|
—
|
|
|
1
|
|
|
5
|
|
|
4
|
|
||||
Benefit payments
|
(194
|
)
|
|
(159
|
)
|
|
(20
|
)
|
|
(19
|
)
|
||||
Foreign-currency exchange-rate changes
|
(7
|
)
|
|
(7
|
)
|
|
—
|
|
|
—
|
|
||||
Benefit obligation at end of year
(1)
|
$
|
2,431
|
|
|
$
|
2,528
|
|
|
$
|
266
|
|
|
$
|
373
|
|
Change in plan assets
|
|
|
|
|
|
|
|
||||||||
Fair value of plan assets at beginning of year
|
$
|
1,818
|
|
|
$
|
1,754
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Actual return on plan assets
|
16
|
|
|
111
|
|
|
—
|
|
|
—
|
|
||||
Employer contributions
|
43
|
|
|
121
|
|
|
15
|
|
|
15
|
|
||||
Participant contributions
|
—
|
|
|
1
|
|
|
5
|
|
|
4
|
|
||||
Benefit payments
|
(194
|
)
|
|
(159
|
)
|
|
(20
|
)
|
|
(19
|
)
|
||||
Foreign-currency exchange-rate changes
|
(9
|
)
|
|
(10
|
)
|
|
—
|
|
|
—
|
|
||||
Fair value of plan assets at end of year
|
$
|
1,674
|
|
|
$
|
1,818
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
||||||||
Funded status of the plans at end of year
|
$
|
(757
|
)
|
|
$
|
(710
|
)
|
|
$
|
(266
|
)
|
|
$
|
(373
|
)
|
|
|
|
|
|
|
|
|
||||||||
Total recognized amounts in the balance sheet consist of
|
|
|
|
|
|
|
|
||||||||
Other assets
|
$
|
41
|
|
|
$
|
41
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Accrued expenses
|
(24
|
)
|
|
(24
|
)
|
|
(16
|
)
|
|
(15
|
)
|
||||
Other long-term liabilities—other
|
(774
|
)
|
|
(727
|
)
|
|
(250
|
)
|
|
(358
|
)
|
||||
Total
|
$
|
(757
|
)
|
|
$
|
(710
|
)
|
|
$
|
(266
|
)
|
|
$
|
(373
|
)
|
|
|
|
|
|
|
|
|
||||||||
Total recognized amounts in accumulated other comprehensive income consist of
|
|
|
|
|
|
|
|
||||||||
Prior service cost (credit)
|
$
|
(1
|
)
|
|
$
|
(1
|
)
|
|
$
|
(84
|
)
|
|
$
|
2
|
|
Net actuarial (gain) loss
|
655
|
|
|
740
|
|
|
(25
|
)
|
|
1
|
|
||||
Total
|
$
|
654
|
|
|
$
|
739
|
|
|
$
|
(109
|
)
|
|
$
|
3
|
|
(1)
|
The accumulated benefit obligation for all defined-benefit pension plans was
$2.1 billion
at both
December 31, 2015
and
December 31, 2014
.
|
millions
|
2015
|
|
2014
|
||||
Projected benefit obligation
|
$
|
2,309
|
|
|
$
|
2,403
|
|
Accumulated benefit obligation
|
1,954
|
|
|
2,024
|
|
||
Fair value of plan assets
|
1,511
|
|
|
1,652
|
|
|
Pension Benefits
|
|
Other Benefits
|
||||||||||||||||||||
millions
|
2015
|
|
2014
|
|
2013
|
|
2015
|
|
2014
|
|
2013
|
||||||||||||
Components of net periodic benefit cost
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Service cost
|
$
|
118
|
|
|
$
|
99
|
|
|
$
|
85
|
|
|
$
|
9
|
|
|
$
|
7
|
|
|
$
|
9
|
|
Interest cost
|
101
|
|
|
99
|
|
|
78
|
|
|
15
|
|
|
15
|
|
|
14
|
|
||||||
Expected return on plan assets
|
(109
|
)
|
|
(106
|
)
|
|
(91
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Amortization of net actuarial loss (gain)
|
52
|
|
|
34
|
|
|
118
|
|
|
—
|
|
|
(7
|
)
|
|
—
|
|
||||||
Amortization of net prior service cost (credit)
|
—
|
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
|
—
|
|
|
1
|
|
||||||
Settlement loss
|
11
|
|
|
—
|
|
|
14
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Net periodic benefit cost
|
$
|
173
|
|
|
$
|
126
|
|
|
$
|
204
|
|
|
$
|
20
|
|
|
$
|
15
|
|
|
$
|
24
|
|
Amounts recognized in other comprehensive income (expense)
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net actuarial gain (loss)
|
$
|
22
|
|
|
$
|
(333
|
)
|
|
$
|
342
|
|
|
$
|
27
|
|
|
$
|
(72
|
)
|
|
$
|
74
|
|
Amortization of net actuarial (gain) loss
|
52
|
|
|
34
|
|
|
118
|
|
|
—
|
|
|
(7
|
)
|
|
—
|
|
||||||
Net prior service (cost) credit
|
—
|
|
|
—
|
|
|
—
|
|
|
89
|
|
|
—
|
|
|
—
|
|
||||||
Amortization of net prior service cost (credit)
|
—
|
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
|
—
|
|
|
1
|
|
||||||
Settlement loss
|
11
|
|
|
—
|
|
|
14
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total amounts recognized in other comprehensive income (expense)
|
$
|
85
|
|
|
$
|
(299
|
)
|
|
$
|
474
|
|
|
$
|
112
|
|
|
$
|
(79
|
)
|
|
$
|
75
|
|
|
Pension Benefits
|
|
Other Benefits
|
||||||||||||||
|
2015
|
|
2014
|
|
2013
|
|
2015
|
|
2014
|
|
2013
|
||||||
Benefit obligation assumptions
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Discount rate
|
4.50
|
%
|
|
4.00
|
%
|
|
4.75
|
%
|
|
5.00
|
%
|
|
4.25
|
%
|
|
5.25
|
%
|
Rates of increase in compensation levels
|
5.25
|
%
|
|
5.25
|
%
|
|
5.00
|
%
|
|
5.50
|
%
|
|
5.25
|
%
|
|
5.25
|
%
|
Net periodic benefit cost assumptions
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Discount rate
|
4.00
|
%
|
|
4.75
|
%
|
|
3.50
|
%
|
|
4.25
|
%
|
|
5.25
|
%
|
|
4.00
|
%
|
Long-term rate of return on plan assets
|
6.75
|
%
|
|
6.75
|
%
|
|
7.00
|
%
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
Rates of increase in compensation levels
|
5.25
|
%
|
|
5.00
|
%
|
|
4.50
|
%
|
|
5.25
|
%
|
|
5.25
|
%
|
|
4.50
|
%
|
millions
|
|
|
|
|
|
|
|
||||||||
December 31, 2015
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
Investments
|
|
|
|
|
|
|
|
||||||||
Cash and cash equivalents
|
$
|
5
|
|
|
$
|
54
|
|
|
$
|
—
|
|
|
$
|
59
|
|
Fixed income
|
|
|
|
|
|
|
|
||||||||
Mortgage-backed securities
|
—
|
|
|
36
|
|
|
—
|
|
|
36
|
|
||||
U.S. government securities
|
—
|
|
|
53
|
|
|
—
|
|
|
53
|
|
||||
Other fixed-income securities
(1)
|
46
|
|
|
236
|
|
|
—
|
|
|
282
|
|
||||
Equity securities
|
|
|
|
|
|
|
|
||||||||
Domestic
|
330
|
|
|
80
|
|
|
—
|
|
|
410
|
|
||||
International
|
130
|
|
|
289
|
|
|
—
|
|
|
419
|
|
||||
Other
|
|
|
|
|
|
|
|
||||||||
Real estate
|
—
|
|
|
57
|
|
|
104
|
|
|
161
|
|
||||
Private equity
|
—
|
|
|
—
|
|
|
92
|
|
|
92
|
|
||||
Hedge funds and other alternative strategies
|
7
|
|
|
—
|
|
|
127
|
|
|
134
|
|
||||
Other
|
—
|
|
|
30
|
|
|
—
|
|
|
30
|
|
||||
Total investments
(2)
|
$
|
518
|
|
|
$
|
835
|
|
|
$
|
323
|
|
|
$
|
1,676
|
|
Liabilities
|
|
|
|
|
|
|
|
||||||||
Hedge funds and other alternative strategies
|
$
|
(3
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(3
|
)
|
Total liabilities
|
$
|
(3
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(3
|
)
|
|
|
|
|
|
|
|
|
||||||||
December 31, 2014
|
|
|
|
|
|
|
|
||||||||
Investments
|
|
|
|
|
|
|
|
||||||||
Cash and cash equivalents
|
$
|
3
|
|
|
$
|
53
|
|
|
$
|
—
|
|
|
$
|
56
|
|
Fixed income
|
|
|
|
|
|
|
|
||||||||
Mortgage-backed securities
|
—
|
|
|
51
|
|
|
—
|
|
|
51
|
|
||||
U.S. government securities
|
—
|
|
|
56
|
|
|
—
|
|
|
56
|
|
||||
Other fixed-income securities
(1)
|
48
|
|
|
212
|
|
|
—
|
|
|
260
|
|
||||
Equity securities
|
|
|
|
|
|
|
|
||||||||
Domestic
|
446
|
|
|
130
|
|
|
—
|
|
|
576
|
|
||||
International
|
124
|
|
|
299
|
|
|
—
|
|
|
423
|
|
||||
Other
|
|
|
|
|
|
|
|
||||||||
Real estate
|
—
|
|
|
56
|
|
|
94
|
|
|
150
|
|
||||
Private equity
|
—
|
|
|
—
|
|
|
84
|
|
|
84
|
|
||||
Hedge funds and other alternative strategies
|
9
|
|
|
—
|
|
|
126
|
|
|
135
|
|
||||
Other
|
—
|
|
|
30
|
|
|
—
|
|
|
30
|
|
||||
Total investments
(2)
|
$
|
630
|
|
|
$
|
887
|
|
|
$
|
304
|
|
|
$
|
1,821
|
|
Liabilities
|
|
|
|
|
|
|
|
||||||||
Hedge funds and other alternative strategies
|
$
|
(3
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(3
|
)
|
Total liabilities
|
$
|
(3
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(3
|
)
|
(1)
|
Amounts include investments in diversified fixed-income collective investment funds with exposure to mortgage-backed securities, government-issued securities, corporate debt, and other fixed-income securities.
|
(2)
|
Amount excludes receivables and payables, primarily related to Level 1 investments.
|
millions
|
Hedge Funds
and Other
Alternative
Strategies
|
|
Private
Equity
|
|
Real Estate
|
|
Total
|
||||||||
Balance at January 1, 2014
|
$
|
79
|
|
|
$
|
72
|
|
|
$
|
86
|
|
|
$
|
237
|
|
Acquisitions (dispositions), net
|
42
|
|
|
—
|
|
|
2
|
|
|
44
|
|
||||
Actual return on plan assets
|
|
|
|
|
|
|
|
||||||||
Relating to assets sold during the reporting period
|
2
|
|
|
5
|
|
|
—
|
|
|
7
|
|
||||
Relating to assets still held at the reporting date
|
3
|
|
|
7
|
|
|
6
|
|
|
16
|
|
||||
Balance at December 31, 2014
|
$
|
126
|
|
|
$
|
84
|
|
|
$
|
94
|
|
|
$
|
304
|
|
Acquisitions (dispositions), net
|
1
|
|
|
(4
|
)
|
|
2
|
|
|
(1
|
)
|
||||
Actual return on plan assets
|
|
|
|
|
|
|
|
||||||||
Relating to assets sold during the reporting period
|
—
|
|
|
11
|
|
|
—
|
|
|
11
|
|
||||
Relating to assets still held at the reporting date
|
—
|
|
|
1
|
|
|
8
|
|
|
9
|
|
||||
Balance at December 31, 2015
|
$
|
127
|
|
|
$
|
92
|
|
|
$
|
104
|
|
|
$
|
323
|
|
millions
|
Expected 2016
|
|
2015
|
||||
Funded pension plans
|
$
|
5
|
|
|
$
|
4
|
|
Unfunded pension plans
|
25
|
|
|
39
|
|
||
Unfunded other postretirement plans
|
16
|
|
|
15
|
|
||
Total
|
$
|
46
|
|
|
$
|
58
|
|
millions
|
Pension
Benefit
Payments
|
|
Other
Benefit
Payments
|
||||
2016
|
$
|
171
|
|
|
$
|
16
|
|
2017
|
197
|
|
|
17
|
|
||
2018
|
194
|
|
|
17
|
|
||
2019
|
214
|
|
|
17
|
|
||
2020
|
209
|
|
|
18
|
|
||
2021-2025
|
1,199
|
|
|
92
|
|
millions
|
2015
|
|
2014
|
|
2013
|
|||
Shares of common stock issued
|
|
|
|
|
|
|||
Shares at January 1
|
526
|
|
|
523
|
|
|
519
|
|
Exercise of stock options
|
1
|
|
|
2
|
|
|
2
|
|
Issuance of restricted stock
|
1
|
|
|
1
|
|
|
2
|
|
Shares at December 31
|
528
|
|
|
526
|
|
|
523
|
|
Shares of common stock held in treasury
|
|
|
|
|
|
|||
Shares at January 1
|
19
|
|
|
19
|
|
|
18
|
|
Shares received for restricted stock vested and options exercised
|
1
|
|
|
—
|
|
|
1
|
|
Shares at December 31
|
20
|
|
|
19
|
|
|
19
|
|
Shares of common stock outstanding at December 31
|
508
|
|
|
507
|
|
|
504
|
|
millions except per-share amounts
|
2015
|
|
2014
|
|
2013
|
||||||
Net income (loss)
|
|
|
|
|
|
||||||
Net income (loss) attributable to common stockholders
|
$
|
(6,692
|
)
|
|
$
|
(1,750
|
)
|
|
$
|
801
|
|
Less distributions on participating securities
|
3
|
|
|
4
|
|
|
2
|
|
|||
Less undistributed income allocated to participating securities
|
—
|
|
|
—
|
|
|
4
|
|
|||
Basic
|
$
|
(6,695
|
)
|
|
$
|
(1,754
|
)
|
|
$
|
795
|
|
Diluted
|
$
|
(6,695
|
)
|
|
$
|
(1,754
|
)
|
|
$
|
795
|
|
Shares
|
|
|
|
|
|
||||||
Average number of common shares outstanding—basic
|
508
|
|
|
506
|
|
|
502
|
|
|||
Dilutive effect of stock options
|
—
|
|
|
—
|
|
|
3
|
|
|||
Average number of common shares outstanding—diluted
|
508
|
|
|
506
|
|
|
505
|
|
|||
Excluded due to anti-dilutive effect
|
11
|
|
|
11
|
|
|
4
|
|
|||
Net income (loss) per common share
|
|
|
|
|
|
||||||
Basic
|
$
|
(13.18
|
)
|
|
$
|
(3.47
|
)
|
|
$
|
1.58
|
|
Diluted
|
$
|
(13.18
|
)
|
|
$
|
(3.47
|
)
|
|
$
|
1.58
|
|
millions
|
Interest-rate
Derivatives
Previously
Subject to Hedge
Accounting
|
|
Pension and Other Postretirement
Plans
|
|
Total
|
||||||
Balance at December 31, 2012
|
$
|
(61
|
)
|
|
$
|
(579
|
)
|
|
$
|
(640
|
)
|
Other comprehensive income (loss), before reclassifications
|
—
|
|
|
264
|
|
|
264
|
|
|||
Reclassifications to Consolidated Statement of Income
|
7
|
|
|
84
|
|
|
91
|
|
|||
Net other comprehensive income (loss)
|
7
|
|
|
348
|
|
|
355
|
|
|||
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
|
)
|
millions
|
2015
|
|
2014
|
|
2013
|
||||||
Restricted stock
|
$
|
157
|
|
|
$
|
144
|
|
|
$
|
122
|
|
Stock options
|
19
|
|
|
21
|
|
|
27
|
|
|||
Other equity-classified awards
|
1
|
|
|
1
|
|
|
1
|
|
|||
Value creation plan
|
(4
|
)
|
|
136
|
|
|
—
|
|
|||
Performance-based unit awards
|
(1
|
)
|
|
23
|
|
|
4
|
|
|||
Other liability-classified awards
|
—
|
|
|
—
|
|
|
1
|
|
|||
Pretax compensation expense
|
$
|
172
|
|
|
$
|
325
|
|
|
$
|
155
|
|
Income tax benefit
|
$
|
64
|
|
|
$
|
120
|
|
|
$
|
57
|
|
|
Shares
(millions)
|
|
Weighted-Average
Grant-Date
Fair Value
(per share)
|
|||
Non-vested at January 1, 2015
|
3.60
|
|
|
$
|
85.31
|
|
Granted
|
2.35
|
|
|
$
|
79.40
|
|
Vested
|
(1.76
|
)
|
|
$
|
84.18
|
|
Forfeited
|
(0.21
|
)
|
|
$
|
84.34
|
|
Non-vested at December 31, 2015
|
3.98
|
|
|
$
|
82.39
|
|
•
|
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.
|
|
2015
|
|
2014
|
|
2013
|
|||||||||
Weighted-average grant-date fair value
|
$
|
18.18
|
|
|
$
|
23.55
|
|
|
$
|
26.27
|
|
|||
Assumptions
|
|
|
|
|
|
|
|
|
||||||
Expected option life—years
|
4.9
|
|
|
4.9
|
|
|
4.8
|
|
||||||
Volatility
|
32.4
|
%
|
|
29.9
|
%
|
|
33.9
|
%
|
||||||
Risk-free interest rate
|
1.4
|
%
|
|
1.6
|
%
|
|
1.3
|
%
|
||||||
Dividend yield
|
1.4
|
%
|
|
1.1
|
%
|
|
0.8
|
%
|
|
Shares
(millions)
|
|
Weighted-
Average
Exercise
Price
(per share)
|
|
Weighted-
Average
Remaining
Contractual
Term
(years)
|
|
Aggregate
Intrinsic
Value
(millions)
|
|||||
Outstanding at January 1, 2015
|
6.79
|
|
|
$
|
69.96
|
|
|
|
|
|
||
Granted
|
1.16
|
|
|
$
|
69.37
|
|
|
|
|
|
||
Exercised
(1)
|
(0.66
|
)
|
|
$
|
42.37
|
|
|
|
|
|
||
Forfeited or expired
|
(0.24
|
)
|
|
$
|
87.08
|
|
|
|
|
|
||
Outstanding at December 31, 2015
|
7.05
|
|
|
$
|
71.86
|
|
|
3.40
|
|
$
|
13.9
|
|
Vested or expected to vest at December 31, 2015
|
6.98
|
|
|
$
|
71.77
|
|
|
3.37
|
|
$
|
13.9
|
|
Exercisable at December 31, 2015
|
5.07
|
|
|
$
|
69.08
|
|
|
2.28
|
|
$
|
13.9
|
|
(1)
|
The total intrinsic value of stock options exercised was
$23 million
during
2015
,
$88 million
during
2014
, and
$80 million
during
2013
, based on the difference between the market price at the exercise date and the exercise price.
|
millions
|
2015
|
|
2014
|
|
2013
|
||||||
Cash paid (received)
|
|
|
|
|
|
||||||
Interest, net of amounts capitalized
(1)
|
$
|
2,019
|
|
|
$
|
689
|
|
|
$
|
627
|
|
Income taxes, net of refunds
|
26
|
|
|
956
|
|
|
169
|
|
|||
Non-cash investing activities
|
|
|
|
|
|
||||||
Fair value of properties and equipment from non-cash transactions
|
$
|
178
|
|
|
$
|
18
|
|
|
$
|
62
|
|
Asset retirement cost additions
|
273
|
|
|
348
|
|
|
297
|
|
|||
Accruals of property, plant, and equipment
|
754
|
|
|
1,177
|
|
|
1,446
|
|
|||
Net liabilities assumed (divested) in acquisitions and divestitures
|
(114
|
)
|
|
(92
|
)
|
|
(80
|
)
|
|||
Property insurance receivable
|
49
|
|
|
—
|
|
|
—
|
|
|||
Non-cash investing and financing activities
|
|
|
|
|
|
||||||
Capital lease obligation
|
$
|
—
|
|
|
$
|
13
|
|
|
$
|
8
|
|
Floating production, storage, and offloading vessel construction period obligation
|
59
|
|
|
128
|
|
|
17
|
|
millions
|
2015
|
|
2014
|
|
2013
|
||||||
Income (loss) before income taxes
|
$
|
(9,689
|
)
|
|
$
|
54
|
|
|
$
|
2,106
|
|
(Gains) losses on divestitures, net
|
1,022
|
|
|
(1,891
|
)
|
|
470
|
|
|||
Exploration expense
|
2,644
|
|
|
1,639
|
|
|
1,329
|
|
|||
DD&A
|
4,603
|
|
|
4,550
|
|
|
3,927
|
|
|||
Impairments
|
5,075
|
|
|
836
|
|
|
794
|
|
|||
Interest expense
|
825
|
|
|
772
|
|
|
686
|
|
|||
Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives
|
235
|
|
|
578
|
|
|
(307
|
)
|
|||
Other operating expense
|
74
|
|
|
97
|
|
|
48
|
|
|||
Tronox-related contingent loss
|
5
|
|
|
4,360
|
|
|
850
|
|
|||
Certain other nonoperating items
|
22
|
|
|
22
|
|
|
110
|
|
|||
Less net income (loss) attributable to noncontrolling interests
|
(120
|
)
|
|
187
|
|
|
140
|
|
|||
Consolidated Adjusted EBITDAX
|
$
|
4,936
|
|
|
$
|
10,830
|
|
|
$
|
9,873
|
|
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
|
|
(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, 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
|
||||||||||
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
|
|
2013
|
|
|
|
|
|
|
|
|
|
||||||||||
Sales revenues
|
$
|
7,090
|
|
|
$
|
387
|
|
|
$
|
7,390
|
|
|
$
|
—
|
|
|
$
|
14,867
|
|
Intersegment revenues
|
6,405
|
|
|
1,105
|
|
|
(6,859
|
)
|
|
(651
|
)
|
|
—
|
|
|||||
Other
|
—
|
|
|
—
|
|
|
—
|
|
|
184
|
|
|
184
|
|
|||||
Total revenues and other
(1)
|
13,495
|
|
|
1,492
|
|
|
531
|
|
|
(467
|
)
|
|
15,051
|
|
|||||
Operating costs and expenses
(2)
|
3,635
|
|
|
843
|
|
|
652
|
|
|
20
|
|
|
5,150
|
|
|||||
Net cash from settlement of commodity derivatives
|
—
|
|
|
—
|
|
|
—
|
|
|
(95
|
)
|
|
(95
|
)
|
|||||
Other (income) expense, net
(3)
|
—
|
|
|
—
|
|
|
—
|
|
|
(21
|
)
|
|
(21
|
)
|
|||||
Net income (loss) attributable to noncontrolling interests
|
—
|
|
|
140
|
|
|
—
|
|
|
—
|
|
|
140
|
|
|||||
Total expenses and other
|
3,635
|
|
|
983
|
|
|
652
|
|
|
(96
|
)
|
|
5,174
|
|
|||||
Total (gains) losses on derivatives, net included in marketing revenue, less net cash from settlement
|
—
|
|
|
—
|
|
|
(4
|
)
|
|
—
|
|
|
(4
|
)
|
|||||
Adjusted EBITDAX
|
$
|
9,860
|
|
|
$
|
509
|
|
|
$
|
(125
|
)
|
|
$
|
(371
|
)
|
|
$
|
9,873
|
|
Net properties and equipment
|
$
|
33,409
|
|
|
$
|
5,408
|
|
|
$
|
9
|
|
|
$
|
2,103
|
|
|
$
|
40,929
|
|
Capital expenditures
|
$
|
7,008
|
|
|
$
|
1,248
|
|
|
$
|
—
|
|
|
$
|
267
|
|
|
$
|
8,523
|
|
Goodwill
|
$
|
5,317
|
|
|
$
|
175
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
5,492
|
|
(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, 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
|
2015
|
|
2014
|
|
2013
|
||||||
Sales Revenues
|
|
|
|
|
|
||||||
United States
|
$
|
7,819
|
|
|
$
|
13,083
|
|
|
$
|
11,290
|
|
Algeria
|
1,189
|
|
|
2,435
|
|
|
2,184
|
|
|||
Other International
|
478
|
|
|
857
|
|
|
1,393
|
|
|||
Total sales revenues
|
$
|
9,486
|
|
|
$
|
16,375
|
|
|
$
|
14,867
|
|
|
December 31,
|
||||||
millions
|
2015
|
|
2014
|
||||
Net Properties and Equipment
|
|
|
|
||||
United States
|
$
|
29,625
|
|
|
$
|
37,186
|
|
Algeria
|
1,271
|
|
|
1,431
|
|
||
Other International
|
2,855
|
|
|
2,972
|
|
||
Total net properties and equipment
|
$
|
33,751
|
|
|
$
|
41,589
|
|
|
|
Oil and Condensate per Bbl
|
|
Natural Gas per MMBtu
|
|
NGLs
per Bbl
(1)
|
||||||
December 31, 2015
|
|
$
|
50.28
|
|
|
$
|
2.59
|
|
|
$
|
19.47
|
|
December 31, 2014
|
|
$
|
94.99
|
|
|
$
|
4.35
|
|
|
$
|
45.25
|
|
December 31, 2013
|
|
$
|
96.78
|
|
|
$
|
3.67
|
|
|
N/A
|
|
(1)
|
The benchmark price for NGLs was previously the same as that for oil, but was converted to a NGLs-specific price beginning in 2014.
|
|
Oil and Condensate
(MMBbls)
|
|
Natural Gas
(Bcf)
|
||||||||||||||
|
United States
|
|
International
|
|
Total
|
|
United States
|
|
International
|
|
Total
|
||||||
Proved Reserves
|
|
|
|
|
|
|
|
|
|
|
|
||||||
December 31, 2012
|
511
|
|
|
256
|
|
|
767
|
|
|
8,329
|
|
|
—
|
|
|
8,329
|
|
Revisions of prior estimates
|
96
|
|
|
21
|
|
|
117
|
|
|
1,276
|
|
|
—
|
|
|
1,276
|
|
Extensions, discoveries, and other additions
|
52
|
|
|
14
|
|
|
66
|
|
|
416
|
|
|
—
|
|
|
416
|
|
Purchases in place
|
1
|
|
|
—
|
|
|
1
|
|
|
153
|
|
|
—
|
|
|
153
|
|
Sales in place
|
(10
|
)
|
|
—
|
|
|
(10
|
)
|
|
(4
|
)
|
|
—
|
|
|
(4
|
)
|
Production
|
(58
|
)
|
|
(32
|
)
|
|
(90
|
)
|
|
(965
|
)
|
|
—
|
|
|
(965
|
)
|
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
|
|
Proved Developed Reserves
|
|
|
|
|
|
|
|
|
|
|
|
||||||
December 31, 2012
|
318
|
|
|
208
|
|
|
526
|
|
|
6,445
|
|
|
—
|
|
|
6,445
|
|
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
|
|
Proved Undeveloped Reserves
|
|
|
|
|
|
|
|
|
|
|
|
||||||
December 31, 2012
|
193
|
|
|
48
|
|
|
241
|
|
|
1,884
|
|
|
—
|
|
|
1,884
|
|
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
|
|
|
NGLs
(MMBbls)
|
|
Total
(MMBOE)
|
||||||||||||||
|
United States
|
|
International
|
|
Total
|
|
United States
|
|
International
|
|
Total
|
||||||
Proved Reserves
|
|
|
|
|
|
|
|
|
|
|
|
||||||
December 31, 2012
|
393
|
|
|
12
|
|
|
405
|
|
|
2,292
|
|
|
268
|
|
|
2,560
|
|
Revisions of prior estimates
(1)
|
17
|
|
|
—
|
|
|
17
|
|
|
326
|
|
|
21
|
|
|
347
|
|
Extensions, discoveries, and other additions
|
10
|
|
|
—
|
|
|
10
|
|
|
131
|
|
|
14
|
|
|
145
|
|
Purchases in place
|
9
|
|
|
—
|
|
|
9
|
|
|
36
|
|
|
—
|
|
|
36
|
|
Sales in place
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
|
(12
|
)
|
|
—
|
|
|
(12
|
)
|
Production
|
(33
|
)
|
|
—
|
|
|
(33
|
)
|
|
(252
|
)
|
|
(32
|
)
|
|
(284
|
)
|
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
|
|
Proved Developed Reserves
|
|
|
|
|
|
|
|
|
|
|
|
||||||
December 31, 2012
|
283
|
|
|
—
|
|
|
283
|
|
|
1,675
|
|
|
208
|
|
|
1,883
|
|
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
|
|
Proved Undeveloped Reserves
|
|
|
|
|
|
|
|
|
|
|
|
||||||
December 31, 2012
|
110
|
|
|
12
|
|
|
122
|
|
|
617
|
|
|
60
|
|
|
677
|
|
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
|
|
(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
89
MMBOE for
2015
,
577
MMBOE for
2014
, and
410
MMBOE for
2013
.
|
•
|
Revisions of prior estimates
Prior estimates of proved reserves were revised downward by
246
MMBOE. Negative revisions of
624
MMBOE were due to the decline in commodity prices and include a reduction to NGLs reserves of 43 MMBOE associated with price-induced ethane rejection. The negative price-related revisions were partially offset by a net increase of
378
MMBOE driven by increases from improved economics associated with performance improvements coupled with reduced year-end costs, increases from successful infill drilling mainly in the Wattenberg area of the Rocky Mountains Region (Rockies), and decreases primarily associated with updates to development plans to align with the current economic environment.
|
•
|
Extensions and discoveries
Proved reserves increased by
29
MMBOE through the extension of proved acreage, primarily as a result of successful drilling in the Wolfcamp shale play in the Southern and Appalachia Region. Although shale plays represented only
20%
of the Company’s total proved reserves at
December 31, 2015
, growth in the shale plays contributed almost all of the total extensions and discoveries.
|
•
|
Sales in place
Proved developed reserves decreased by
238
MMBOE primarily associated with the divestiture of a portion of the Company’s East Texas assets in the Southern and Appalachia Region and enhanced oil recovery and coalbed methane assets in the Rockies. Proved undeveloped reserves decreased by
41
MMBOE primarily associated with divestiture activities in the Rockies.
|
•
|
Revisions of prior estimates
Proved reserves increased by 577 MMBOE related to successful infill drilling in large onshore areas such as the Wattenberg area and the Eagleford and Haynesville shales. Partially offsetting these positive infill revisions was a net decrease of 138 MMBOE, primarily associated with the optimization of horizontal drilling locations and the discontinuation of vertical well workover plans in the Wattenberg area.
|
•
|
Extensions and discoveries
Proved reserves increased by 63 MMBOE primarily as a result of successful drilling in the Marcellus and Wolfcamp shale plays. Although shale plays represented only 17% of the Company’s total proved reserves at December 31, 2014, growth in the shale plays contributed 49 MMBOE, or 78%, of the total extensions and discoveries.
|
•
|
Sales in place
Proved developed reserves decreased by 69 MMBOE and proved undeveloped reserves decreased by 55 MMBOE due to divestitures, including the divestiture of the Company’s interest in the Pinedale/Jonah assets in Wyoming, the Company’s Chinese subsidiary, and a portion of the Company’s working interest in the East Texas Chalk area.
|
•
|
Revisions of prior estimates
Proved reserves increased by 410 MMBOE related to successful infill drilling, primarily in large onshore areas such as Wattenberg, Greater Natural Buttes, and the Eagleford shale, and 30 MMBOE resulting from improved oil and natural-gas prices. Partially offsetting these positive revisions were decreases of 53 MMBbls of NGLs reserves due to lower ethane prices and 40 MMBOE due to other non-price-related revisions primarily in the Rockies.
|
•
|
Extensions and discoveries
Proved reserves increased by 145 MMBOE as the result of successful drilling primarily in the Marcellus shale and the Gulf of Mexico. Although shale plays represented only 13% of the Company’s total proved reserves at December 31, 2013, growth in the shale plays contributed 70 MMBOE, or 48%, of the total extensions and discoveries.
|
•
|
Purchases in place
Proved reserves increased by 36 MMBOE due to acquisitions related to domestic assets almost exclusively in the Rockies.
|
•
|
Sales in place
Proved undeveloped reserves decreased by 12 MMBOE primarily due to a partial sale of a working interest in the Gulf of Mexico Heidelberg development project.
|
millions
|
United States
|
|
International
|
|
Total
|
||||||
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
|
|
December 31, 2014
|
|
|
|
|
|
||||||
Capitalized
|
|
|
|
|
|
||||||
Unproved properties
|
$
|
3,858
|
|
|
$
|
1,291
|
|
|
$
|
5,149
|
|
Proved properties
|
53,545
|
|
|
4,895
|
|
|
58,440
|
|
|||
|
57,403
|
|
|
6,186
|
|
|
63,589
|
|
|||
Less accumulated DD&A
|
29,055
|
|
|
1,902
|
|
|
30,957
|
|
|||
Net capitalized costs
|
$
|
28,348
|
|
|
$
|
4,284
|
|
|
$
|
32,632
|
|
millions
|
United States
|
|
International
|
|
Total
|
||||||
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
|
|
Year Ended December 31, 2013
|
|
|
|
|
|
||||||
Property acquisitions
|
|
|
|
|
|
||||||
Unproved
|
$
|
282
|
|
|
$
|
45
|
|
|
$
|
327
|
|
Proved
|
324
|
|
|
—
|
|
|
324
|
|
|||
Exploration
|
1,031
|
|
|
939
|
|
|
1,970
|
|
|||
Development
|
4,421
|
|
|
444
|
|
|
4,865
|
|
|||
Total costs incurred
|
$
|
6,058
|
|
|
$
|
1,428
|
|
|
$
|
7,486
|
|
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
|
|
|||
Other taxes
|
218
|
|
|
270
|
|
|
488
|
|
|||
|
2,514
|
|
|
514
|
|
|
3,028
|
|
|||
Exploration expenses
|
1,447
|
|
|
1,197
|
|
|
2,644
|
|
|||
Depreciation, depletion, and amortization
|
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
|
(2,332
|
)
|
|
252
|
|
|
(2,080
|
)
|
|||
Results of operations
|
$
|
(3,980
|
)
|
|
$
|
(709
|
)
|
|
$
|
(4,689
|
)
|
millions
|
United States
|
|
International
|
|
Total
|
||||||
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
|
|
|||
Other taxes
|
652
|
|
|
535
|
|
|
1,187
|
|
|||
|
3,098
|
|
|
803
|
|
|
3,901
|
|
|||
Exploration expenses
|
1,218
|
|
|
421
|
|
|
1,639
|
|
|||
Depreciation, depletion, and amortization
|
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
|
995
|
|
|
979
|
|
|
1,974
|
|
|||
Results of operations
|
$
|
1,709
|
|
|
$
|
2,672
|
|
|
$
|
4,381
|
|
Year Ended December 31, 2013
|
|
|
|
|
|
||||||
Net revenues from production
|
|
|
|
|
|
||||||
Third-party sales
|
$
|
6,567
|
|
|
$
|
856
|
|
|
$
|
7,423
|
|
Sales to consolidated affiliates
|
3,685
|
|
|
2,720
|
|
|
6,405
|
|
|||
Gains (losses) on property dispositions
|
(618
|
)
|
|
(3
|
)
|
|
(621
|
)
|
|||
|
9,634
|
|
|
3,573
|
|
|
13,207
|
|
|||
Production costs
|
|
|
|
|
|
||||||
Oil and gas operating
|
874
|
|
|
218
|
|
|
1,092
|
|
|||
Oil and gas transportation
|
959
|
|
|
22
|
|
|
981
|
|
|||
Production-related general and administrative expenses
|
332
|
|
|
5
|
|
|
337
|
|
|||
Other taxes
|
569
|
|
|
455
|
|
|
1,024
|
|
|||
|
2,734
|
|
|
700
|
|
|
3,434
|
|
|||
Exploration expenses
|
611
|
|
|
718
|
|
|
1,329
|
|
|||
Depreciation, depletion and amortization
|
3,222
|
|
|
399
|
|
|
3,621
|
|
|||
Impairments related to oil and gas properties
|
704
|
|
|
—
|
|
|
704
|
|
|||
Other operating expense
|
54
|
|
|
33
|
|
|
87
|
|
|||
|
2,309
|
|
|
1,723
|
|
|
4,032
|
|
|||
Income tax expense
|
845
|
|
|
1,005
|
|
|
1,850
|
|
|||
Results of operations
|
$
|
1,464
|
|
|
$
|
718
|
|
|
$
|
2,182
|
|
millions
|
United States
|
|
International
|
|
Total
|
||||||
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
|
|
December 31, 2013
|
|
|
|
|
|
||||||
Future cash inflows
|
$
|
102,765
|
|
|
$
|
28,454
|
|
|
$
|
131,219
|
|
Future production costs
|
33,271
|
|
|
6,819
|
|
|
40,090
|
|
|||
Future development costs
|
12,285
|
|
|
1,501
|
|
|
13,786
|
|
|||
Future income tax expenses
|
20,222
|
|
|
8,148
|
|
|
28,370
|
|
|||
Future net cash flows
|
36,987
|
|
|
11,986
|
|
|
48,973
|
|
|||
10% annual discount for estimated timing of cash flows
|
15,818
|
|
|
4,049
|
|
|
19,867
|
|
|||
Standardized measure of discounted future net cash flows
|
$
|
21,169
|
|
|
$
|
7,937
|
|
|
$
|
29,106
|
|
millions
|
United States
|
|
International
|
|
Total
|
||||||
2015
|
|
|
|
|
|
||||||
Balance at January 1
|
$
|
24,148
|
|
|
$
|
6,512
|
|
|
$
|
30,660
|
|
Sales and transfers of oil and gas produced, net of production costs
|
(4,079
|
)
|
|
(1,153
|
)
|
|
(5,232
|
)
|
|||
Net changes in prices and production costs
|
(28,967
|
)
|
|
(8,010
|
)
|
|
(36,977
|
)
|
|||
Changes in estimated future development costs
|
4,408
|
|
|
221
|
|
|
4,629
|
|
|||
Extensions, discoveries, additions, and improved recovery, less related costs
|
219
|
|
|
—
|
|
|
219
|
|
|||
Development costs incurred during the period
|
2,311
|
|
|
379
|
|
|
2,690
|
|
|||
Revisions of previous quantity estimates
|
(1,890
|
)
|
|
47
|
|
|
(1,843
|
)
|
|||
Purchases of minerals in place
|
30
|
|
|
—
|
|
|
30
|
|
|||
Sales of minerals in place
|
(2,262
|
)
|
|
—
|
|
|
(2,262
|
)
|
|||
Accretion of discount
|
3,648
|
|
|
1,143
|
|
|
4,791
|
|
|||
Net change in income taxes
|
9,940
|
|
|
3,193
|
|
|
13,133
|
|
|||
Other
|
(414
|
)
|
|
261
|
|
|
(153
|
)
|
|||
Balance at December 31
|
$
|
7,092
|
|
|
$
|
2,593
|
|
|
$
|
9,685
|
|
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
|
United States
|
|
International
|
|
Total
|
||||||
2013
|
|
|
|
|
|
||||||
Balance at January 1
|
$
|
17,538
|
|
|
$
|
8,776
|
|
|
$
|
26,314
|
|
Sales and transfers of oil and gas produced, net of production costs
|
(7,517
|
)
|
|
(2,881
|
)
|
|
(10,398
|
)
|
|||
Net changes in prices and production costs
|
1,433
|
|
|
(1,072
|
)
|
|
361
|
|
|||
Changes in estimated future development costs
|
(2,326
|
)
|
|
(193
|
)
|
|
(2,519
|
)
|
|||
Extensions, discoveries, additions, and improved recovery, less related costs
|
2,659
|
|
|
(128
|
)
|
|
2,531
|
|
|||
Development costs incurred during the period
|
1,076
|
|
|
193
|
|
|
1,269
|
|
|||
Revisions of previous quantity estimates
|
6,526
|
|
|
1,324
|
|
|
7,850
|
|
|||
Purchases of minerals in place
|
253
|
|
|
—
|
|
|
253
|
|
|||
Sales of minerals in place
|
284
|
|
|
—
|
|
|
284
|
|
|||
Accretion of discount
|
2,671
|
|
|
1,465
|
|
|
4,136
|
|
|||
Net change in income taxes
|
(1,865
|
)
|
|
401
|
|
|
(1,464
|
)
|
|||
Other
|
437
|
|
|
52
|
|
|
489
|
|
|||
Balance at December 31
|
$
|
21,169
|
|
|
$
|
7,937
|
|
|
$
|
29,106
|
|
millions except per-share amounts
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
||||||||
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
|
|
||||
|
|
|
|
|
|
|
|
||||||||
2014
|
|
|
|
|
|
|
|
||||||||
Sales revenues
|
$
|
4,338
|
|
|
$
|
4,385
|
|
|
$
|
4,230
|
|
|
$
|
3,422
|
|
Gains (losses) on divestitures and other, net
|
1,506
|
|
|
54
|
|
|
780
|
|
|
(245
|
)
|
||||
Impairments
|
3
|
|
|
117
|
|
|
394
|
|
|
322
|
|
||||
Operating income (loss)
|
2,975
|
|
|
1,209
|
|
|
1,698
|
|
|
(479
|
)
|
||||
Tronox-related contingent loss
|
4,300
|
|
|
19
|
|
|
19
|
|
|
22
|
|
||||
Net income (loss)
|
(2,626
|
)
|
|
266
|
|
|
1,147
|
|
|
(350
|
)
|
||||
Net income (loss) attributable to noncontrolling interests
|
43
|
|
|
39
|
|
|
60
|
|
|
45
|
|
||||
Net income (loss) attributable to common stockholders
|
(2,669
|
)
|
|
227
|
|
|
1,087
|
|
|
(395
|
)
|
||||
Earnings per share
|
|
|
|
|
|
|
|
||||||||
Net income (loss) attributable to common stockholders—basic
|
$
|
(5.30
|
)
|
|
$
|
0.45
|
|
|
$
|
2.13
|
|
|
$
|
(0.78
|
)
|
Net income (loss) attributable to common stockholders—diluted
|
$
|
(5.30
|
)
|
|
$
|
0.45
|
|
|
$
|
2.12
|
|
|
$
|
(0.78
|
)
|
Average number common shares outstanding—basic
|
504
|
|
|
505
|
|
|
506
|
|
|
507
|
|
||||
Average number common shares outstanding—diluted
|
504
|
|
|
507
|
|
|
508
|
|
|
507
|
|
(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 7.625% Senior Notes due 2014, filed as Exhibit 4.2 to Form 8-K filed on March 6, 2009
|
|
|
(vii)
|
|
Form of 8.700% Senior Notes due 2019, filed as Exhibit 4.3 to Form 8-K filed on March 6, 2009
|
|
|
(viii)
|
|
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
|
|
|
(ix)
|
|
Form of 5.75% Senior Notes due 2014, filed as Exhibit 4.2 to Form 8-K filed on June 12, 2009
|
|
|
(x)
|
|
Form of 6.95% Senior Notes due 2019, filed as Exhibit 4.3 to Form 8-K filed on June 12, 2009
|
|
|
(xi)
|
|
Form of 7.95% Senior Notes due 2039, filed as Exhibit 4.4 to Form 8-K filed on June 12, 2009
|
|
|
(xii)
|
|
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
|
(xiii)
|
|
Form of 6.200% Senior Notes due 2040, filed as Exhibit 4.2 to Form 8-K filed on March 16, 2010
|
|
|
(xiv)
|
|
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
|
|
|
(xv)
|
|
Form of 6.375% Senior Notes due 2017, filed as Exhibit 4.2 to Form 8-K filed on August 12, 2010
|
|
|
(xvi)
|
|
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
|
|
|
(xvii)
|
|
Form of 3.45% Senior Notes due 2024, filed as Exhibit 4.2 to Form 8-K filed on July 7, 2014
|
|
|
(xviii)
|
|
Form of 4.50% Senior Notes due 2044, filed as Exhibit 4.3 to Form 8-K filed on July 7, 2014
|
|
|
(xix)
|
|
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
|
|
|
(xx)
|
|
Form of Unit (included in Exhibit 4.xix)
|
|
|
(xxi)
|
|
Form of Purchase Contract (included in Exhibit 4.xix)
|
|
|
(xxii)
|
|
Form of Amortizing Note (included in Exhibit 4.ii)
|
†
|
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
|
†
|
|
(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
|
Exhibit
Number
|
|
Description
|
||
†
|
10
|
(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 the quarter ended March 31, 2015, filed on May 4, 2015
|
†
|
|
(xvii)
|
|
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
|
†
|
|
(xviii)
|
|
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
|
†
|
|
(xix)
|
|
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 the year ended December 31, 2014, filed on February 20, 2015
|
†
|
|
(xx)
|
|
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 the year ended December 31, 2014, filed on February 20, 2015
|
†
|
|
(xxi)
|
|
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 the year ended December 31, 2014, filed on February 20, 2015
|
†
|
|
(xxii)
|
|
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
|
†
|
|
(xxiii)
|
|
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 the year ended December 31, 2014, filed on February 20, 2015
|
†
|
|
(xxiv)
|
|
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
|
†
|
|
(xxv)
|
|
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
|
†
|
|
(xxvi)
|
|
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
|
†
|
|
(xxvii)
|
|
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
|
†
|
|
(xxviii)
|
|
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
|
†
|
|
(xxix)
|
|
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
|
†
|
|
(xxx)
|
|
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
|
†
|
|
(xxxi)
|
|
Form of Termination Agreement and Release of All Claims Under Officer Severance Plan, filed as Exhibit 10(b)(v) to Form 10-Q for quarter ended September 30, 2003, filed on November 12, 2003
|
Exhibit
Number
|
|
Description
|
||
†
|
10
|
(xxxii)
|
|
Form of Director and Officer Indemnification Agreement, filed as Exhibit 10 to Form 8-K filed on September 3, 2004
|
|
|
(xxxiii)
|
|
$5,000,000,000 Revolving Credit Agreement, dated as of September 2, 2010, among Anadarko Petroleum Corporation, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., DnB NorBank ASA, The Royal Bank of Scotland plc, Société Générale, and Wells Fargo Bank, N.A., as Syndication Agents, and the several lenders named therein, filed as Exhibit 10.1 to Form 8-K filed on September 8, 2010
|
|
|
(xxxiv)
|
|
First Amendment to Revolving Credit Agreement, dated as of August 3, 2011, to the Revolving Credit Agreement dated as of September 2, 2010, among Anadarko Petroleum Corporation, as Borrower, JPMorgan Chase Bank, N.A. as Administrative Agent, Bank of America, N.A., DnB Nor Bank ASA, The Royal Bank of Scotland plc, Société Générale, and Wells Fargo Bank, N.A., as co-syndication agents, and each of the Lenders from time to time party thereto, filed as Exhibit 10(i) to Form 10-Q for quarter ended September 30, 2011, filed on October 31, 2011
|
|
|
(xxxv)
|
|
Second Amendment to Revolving Credit Agreement, dated as of March 26, 2014, to the Revolving Credit Agreement dated as of September 2, 2010, as amended on August 3, 2011, among Anadarko Petroleum Corporation, as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., DnB Nor Bank ASA, The Royal Bank of Scotland plc, Société Générale, and Wells Fargo Bank, N.A., as co-syndication agents, and each of the Lenders from time to time party thereto, filed as Exhibit 10(ii) to Form 10-Q for quarter ended March 31, 2014, filed on May 5, 2014
|
†
|
|
(xxxvi)
|
|
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
|
†
|
|
(xxxvii)
|
|
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
|
†
|
|
(xxxviii)
|
|
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
|
†
|
|
(xxxvix)
|
|
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
|
†
|
|
(xl)
|
|
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
|
†*
|
|
(xli)
|
|
First Amendment to Anadarko Petroleum Corporation 2008 Director Compensation Plan, dated February 8, 2016
|
†
|
|
(xlii)
|
|
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
|
†
|
|
(xliii)
|
|
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
|
†*
|
|
(xliv)
|
|
Terms and Conditions of Elective Deferred Share Awards for Anadarko Petroleum Corporation 2008 Director Compensation Plan
|
†
|
|
(xlv)
|
|
Anadarko Petroleum Corporation Benefits Trust Agreement, amended and restated effective as of November 5, 2008, filed as Exhibit 10(lvi) to Form 10-K for year ended December 31, 2008, filed on February 25, 2009
|
†
|
|
(xlvi)
|
|
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 the quarter ended June 30, 2014, filed on July 29, 2014
|
†
|
|
(xlvii)
|
|
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 the quarter ended June 30, 2014, filed on July 29, 2014
|
Exhibit
Number
|
|
Description
|
||
|
10
|
(xlviii)
|
|
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
|
|
|
(xlix)
|
|
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)
|
†
|
|
(l)
|
|
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
|
†
|
|
(li)
|
|
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
|
†
|
|
(lii)
|
|
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 the quarter ended June 30, 2015, filed on July 28, 2015
|
†
|
|
(liii)
|
|
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
|
†
|
|
(liv)
|
|
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
|
†
|
|
(lv)
|
|
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
|
†
|
|
(lvi)
|
|
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
|
†
|
|
(lvii)
|
|
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
|
†
|
|
(lviii)
|
|
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
|
†
|
|
(lix)
|
|
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
|
†
|
|
(lx)
|
|
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
|
†
|
|
(lxi)
|
|
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
|
|
|
(lxii)
|
|
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
|
Exhibit
Number
|
|
Description
|
||
|
10
|
(lxiii)
|
|
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
|
|
|
(lxiv)
|
|
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
|
|
|
(lxv)
|
|
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
|
|
|
(lxvi)
|
|
364-Day Revolving 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 10.2 to Form 8-K filed on June 23, 2014
|
|
|
(lxvii)
|
|
First Amendment to 364-Day Revolving 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 10.2 to Form 8-K filed on November 19, 2014
|
|
|
(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 the 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
|
*
|
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, 2016
|
By:
|
|
/s/ ROBERT G. GWIN
|
|
|
|
Robert G. Gwin
Executive Vice President, Finance and Chief Financial Officer
|
By:
|
/s/ ROBERT G. GWIN
|
|
|
Robert G. Gwin, Attorney-in-Fact
|
|
“
A
”
|
equals the aggregate grant date fair value (computed as of the date of grant in accordance with applicable financial accounting rules) of all awards granted under the Director Programs (other than with respect to compensation described in “
B
” below) to such Eligible Director during such calendar year; and
|
“
B
”
|
equals the aggregate cash value of such Eligible Director’s retainer, meeting attendance fees, committee assignment fees, lead director retainer, committee chair and member retainers and other Board fees related to service on the Board or committee(s) of the Board that are initially denominated as a cash amount or any other property other than Common Stock (whether paid currently or on a deferred basis or in cash or other property (including Common Stock)) for such calendar year;
|
ANADARKO PETROLEUM CORPORATION
|
|
|
|
|
|
By:
|
/s/ Julia A. Struble
|
|
Julia A. Struble
|
|
Vice President, Human Resources
|
•
|
Grant of Deferred Shares
:
On the last business day of each quarter during 20__, you will be granted a number of Deferred Shares with a grant date fair value equal to the amount of your quarterly fees you elected to defer for such quarter in the form of Deferred Shares in accordance with your Form of Compensation Election (your “
Election Form
”). You will be provided a quarterly summary of the number of Deferred Shares issued hereunder, which shall be subject to the terms and conditions set forth herein.
|
•
|
Deferred Shares Generally
:
Deferred Shares represent a vested contractual right to receive shares of Anadarko Petroleum Corporation (the “
Company
”) common stock, par value $0.10 per share (“
Common
Stock
”), at the time(s) of settlement specified in your Election Form. Upon grant, the Deferred Shares will not be issued in your name, but will be held by the Company, either in book-entry form or by the Company’s Benefits Trust (the “
Trust
”) until the time of settlement set forth in your Election Form. Deferred Shares are considered an unsecured obligation of the Company and any and all assets held in the Trust are subject to claims of the general creditors of the Company. Until the issuance of Common Stock in settlement of your Deferred Shares, you will not have rights as a stockholder of the Company.
|
•
|
Voting Rights
: Although you will not have beneficial ownership of the Deferred Shares prior to settlement, to the extent the shares underlying your Deferred Shares are held by the Trust, you may have the opportunity to direct the voting of your Deferred Shares (which voting instructions the Trustee of the Trust may not follow, in its sole discretion) and such Deferred Shares will be counted toward your stock ownership requirements.
|
•
|
Dividend Equivalents
: You will receive a cash payment equal to the cash dividends that are paid on the Company’s common stock each quarter, with such cash amount to be paid within 30 days after the date that such dividends are paid to the Company’s regular stockholders.
|
•
|
Mandatory Holding Period
: Except in the event of your death or Permanent Disability, no shares of Common Stock will be issued in settlement of your Deferred Shares prior to the one-year anniversary of the grant of the applicable Deferred Shares.
|
•
|
Subject to Terms of Plan
: Your Deferred Shares are subject to the terms and conditions of the Company’s 2008 Director Compensation Plan and the Election Form. In the event of any conflict between the 2008 Director Compensation Plan and the Election Form, the 2008 Director Compensation Plan shall control.
|
•
|
Payment of Taxes
: You are solely responsible for the payment of any taxes associated with the issuance or settlement of Deferred Shares. You acknowledge that the Company has made no representation as to the tax consequences of your Deferred Shares hereunder.
|
|
|
|
Years Ended December 31,
|
||||||||||||||||||
|
|
|
(Unaudited)
|
||||||||||||||||||
millions except ratio amounts
|
2015
|
|
2014
|
|
2013
|
|
2012
|
|
2011
|
||||||||||||
Income (loss) from continuing operations before income taxes
|
$
|
(9,689
|
)
|
|
$
|
54
|
|
|
$
|
2,106
|
|
|
$
|
3,565
|
|
|
$
|
(3,424
|
)
|
||
Equity (income) adjustment
|
(86
|
)
|
|
(119
|
)
|
|
(64
|
)
|
|
(110
|
)
|
|
(102
|
)
|
|||||||
Fixed charges
|
1,240
|
|
|
1,245
|
|
|
1,173
|
|
|
1,209
|
|
|
1,232
|
|
|||||||
Amortization of capitalized interest
|
74
|
|
|
61
|
|
|
46
|
|
|
17
|
|
|
29
|
|
|||||||
Distributed income of equity investees
|
105
|
|
|
121
|
|
|
25
|
|
|
33
|
|
|
34
|
|
|||||||
Capitalized interest
|
(164
|
)
|
|
(201
|
)
|
|
(263
|
)
|
|
(221
|
)
|
|
(147
|
)
|
|||||||
Non-controlling interest in pre-tax income of subsidiaries that have not incurred fixed charges
|
(21
|
)
|
|
(14
|
)
|
|
(11
|
)
|
|
(10
|
)
|
|
(7
|
)
|
|||||||
|
Total Earnings
|
$
|
(8,541
|
)
|
|
$
|
1,147
|
|
|
$
|
3,012
|
|
|
$
|
4,483
|
|
|
$
|
(2,385
|
)
|
|
Interest expense including capitalized interest
|
990
|
|
|
974
|
|
|
930
|
|
|
954
|
|
|
984
|
|
|||||||
Interest expense included in other (income) expense
|
37
|
|
|
36
|
|
|
37
|
|
|
42
|
|
|
38
|
|
|||||||
Estimated interest portion of rental expenditures
|
213
|
|
|
235
|
|
|
206
|
|
|
213
|
|
|
210
|
|
|||||||
|
Total Fixed Charges
|
$
|
1,240
|
|
|
$
|
1,245
|
|
|
$
|
1,173
|
|
|
$
|
1,209
|
|
|
$
|
1,232
|
|
|
Preferred Stock Dividends
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Combined Fixed Charges and Preferred Stock Dividends
|
$
|
1,240
|
|
|
$
|
1,245
|
|
|
$
|
1,173
|
|
|
$
|
1,209
|
|
|
$
|
1,232
|
|
||
Ratio of Earnings to Fixed Charges
|
*
|
|
|
*
|
|
|
2.57
|
|
|
3.71
|
|
|
*
|
|
|||||||
Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends
|
*
|
|
|
*
|
|
|
2.57
|
|
|
3.71
|
|
|
*
|
|
*
|
As a result of the Company’s net loss in 2015, 2014, and 2011, Anadarko’s earnings did not cover total fixed charges by $9,781 million for 2015, $98 million for 2014, and $3,617 million for 2011.
|
(1)
|
The names of certain subsidiaries have been omitted since, considered in the aggregate as a single subsidiary, they would not constitute a
significant subsidiary
, as of the end of the year covered by this report, as defined under the Securities and Exchange Commission Regulation S-X 210.1-02(w).
|
(2)
|
Subsidiary meets the conditions of a
significant subsidiary
under the Securities and Exchange Commission Regulation S-X 210.1-02(w).
|
/s/ KPMG LLP
|
|
Houston, Texas
|
February 17, 2016
|
Re:
|
Securities and Exchange Commission
|
|
Form 10-K of Anadarko Petroleum Corporation
|
|
Very truly yours,
|
|
|
|
|
|
MILLER AND LENTS, LTD.
|
|
|
Texas Registered Engineering Firm No. F-1442
|
|
By:
|
/s/ ROBERT J. OBERST
|
|
|
Robert J. Oberst,
P.E.
|
|
|
Chairman
|
|
/s/ R. A. WALKER
|
|
/s/ ANTHONY R. CHASE
|
R. A. Walker
|
|
Anthony R. Chase
|
|
|
|
/s/ KEVIN P. CHILTON
|
|
/s/ H. PAULETT EBERHART
|
Kevin P. Chilton
|
|
H. Paulett Eberhart
|
|
|
|
/s/ PETER J. FLUOR
|
|
/s/ RICHARD L. GEORGE
|
Peter J. Fluor
|
|
Richard L. George
|
|
|
|
/s/ JOSEPH W. GORDER
|
|
/s/ JOHN R. GORDON
|
Joseph W. Gorder
|
|
John R. Gordon
|
|
|
|
/s/ SEAN GOURLEY
|
|
/s/ MARK C. MCKINLEY
|
Sean Gourley
|
|
Mark C. McKinley
|
|
|
|
/s/ ERIC D. MULLINS
|
|
|
Eric D. Mullins
|
|
|
|
|
|
1.
|
I have reviewed this annual report on Form 10-K of Anadarko Petroleum Corporation;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
/s/ R. A. WALKER
|
R. A. Walker
|
Chairman, President and Chief Executive Officer
|
1.
|
I have reviewed this annual report on Form 10-K of Anadarko Petroleum Corporation;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
/s/ ROBERT G. GWIN
|
Robert G. Gwin
|
Executive Vice President, Finance and Chief Financial Officer
|
(1)
|
the Annual Report on Form 10-K of the Company for the period ended
December 31, 2015
, as filed with the Securities and Exchange Commission on the date hereof (Report), fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
|
(2)
|
the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
February 17, 2016
|
|
|
|
|
|
|
|
/s/ R. A. WALKER
|
|
|
R. A. Walker
|
|
|
Chairman, President and Chief Executive Officer
|
|
|
|
February 17, 2016
|
|
|
|
|
|
|
|
/s/ ROBERT G. GWIN
|
|
|
Robert G. Gwin
|
|
|
Executive Vice President, Finance and Chief Financial Officer
|
Re:
|
Procedures and Methods Review of Anadarko Petroleum Corporation
|
|
Proved Reserves and Future Net Cash Flows As of December 31, 2015
|
|
Very truly yours,
|
|
|
|
MILLER AND LENTS, LTD.
|
|
Texas Registered Engineering Firm No. F-1442
|
By:
|
/s/ ROBERT J. OBERST
|
|
Robert J. Oberst,
P.E.
|
|
Chairman
|