Delaware
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25-0996816
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(State or other jurisdiction of incorporation or organization)
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(I.R.S. Employer Identification No.)
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Title of each class
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Name of each exchange on which registered
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Common Stock, par value $1.00
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New York Stock Exchange
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Large accelerated filer
þ
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Accelerated filer
o
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Non-accelerated filer
o
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(Do not check if a smaller reporting company)
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Smaller reporting company
o
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Emerging growth company
o
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Table of Contents
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•
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conditions in the oil and gas industry, including supply and demand levels for crude oil and condensate, NGLs and natural gas and the resulting impact on price;
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•
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changes in expected reserve or production levels;
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•
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changes in political or economic conditions in the jurisdictions in which we operate, including changes in foreign currency exchange rates, interest rates, inflation rates, and global and domestic market conditions;
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•
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risks relating to our hedging activities;
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•
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capital available for exploration and development;
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•
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drilling and operating risks;
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•
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well production timing;
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•
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availability of drilling rigs, materials and labor, including the costs associated therewith;
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•
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difficulty in obtaining necessary approvals and permits;
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•
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non-performance by third parties of their contractual obligations;
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•
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unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response thereto;
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•
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cyber-attacks;
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•
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changes in safety, health, environmental, tax and other regulations;
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•
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other geological, operating and economic considerations; and
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•
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other factors discussed in Item 1. Business, Item 1A. Risk Factors, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A. Quantitative and Qualitative Disclosures About Market Risk, and elsewhere in this report.
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•
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United States E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas in the United States;
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•
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International E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of the United States and produces and markets products manufactured from natural gas, such as LNG and methanol, in E.G.
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Africa
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||||||||||
December 31, 2017
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U.S.
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E.G.
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Libya
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Total
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Other Int'l
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Total from Cont Ops
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||||||
Proved Developed Reserves
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||||||
Crude oil and condensate
(mmbbl)
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263
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|
|
39
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165
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204
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|
|
17
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484
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Natural gas liquids
(mmbbl)
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118
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|
|
25
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|
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—
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25
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|
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—
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143
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Natural gas
(bcf)
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726
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|
833
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94
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927
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2
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1,655
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Total proved developed reserves
(mmboe)
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502
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203
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|
181
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384
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17
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903
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Proved Undeveloped Reserves
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Crude oil and condensate (
mmbbl
)
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307
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—
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—
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—
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9
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316
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Natural gas liquids (
mmbbl
)
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111
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—
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—
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—
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—
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111
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Natural gas (
bcf
)
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598
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—
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110
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110
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6
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714
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Total proved undeveloped reserves (
mmboe
)
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518
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—
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18
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18
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10
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546
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Total Proved Reserves
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Crude oil and condensate (
mmbbl
)
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570
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39
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165
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204
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26
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800
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Natural gas liquids (
mmbbl
)
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229
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25
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—
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25
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—
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254
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Natural gas (
bcf
)
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1,324
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833
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204
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1,037
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8
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2,369
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Total proved reserves (
mmboe
)
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1,020
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203
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199
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402
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27
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1,449
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Productive Wells
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Oil
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Natural Gas
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Service Wells
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Drilling Wells
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||||||||||||||||
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Gross
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Net
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Gross
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Net
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Gross
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Net
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Gross
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Net
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||||||||
2017
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||||||||
U.S.
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5,132
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1,905
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1,690
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676
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799
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70
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33
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13
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E.G.
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—
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—
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19
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12
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—
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—
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—
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—
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Libya
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1,071
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175
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7
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2
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94
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16
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—
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—
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Total Africa
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1,071
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175
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26
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14
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94
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16
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—
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—
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Other International
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61
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22
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19
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7
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23
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8
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—
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—
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Total
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6,264
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2,102
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1,735
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697
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916
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94
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33
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13
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2016
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||||||||
U.S.
(a)
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4,533
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1,650
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1,830
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708
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821
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85
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|
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E.G.
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—
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—
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17
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|
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11
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2
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1
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||
Libya
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1,071
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175
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7
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1
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|
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94
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|
|
16
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|
|
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||
Total Africa
|
1,071
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|
175
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|
|
24
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|
12
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|
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96
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|
17
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|
|
|
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|
||
Other International
|
62
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|
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23
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35
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|
14
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23
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8
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||
Total
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5,666
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1,848
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1,889
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734
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940
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110
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||
2015
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||||||||
U.S.
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7,198
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2,878
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1,796
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750
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2,727
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747
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E.G.
|
—
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—
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|
17
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|
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11
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|
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2
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|
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1
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|
|
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|
||
Libya
|
1,071
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|
|
175
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|
|
7
|
|
|
1
|
|
|
94
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|
|
16
|
|
|
|
|
|
||
Total Africa
|
1,071
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|
|
175
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|
|
24
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|
|
12
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|
|
96
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|
|
17
|
|
|
|
|
|
||
Other International
|
59
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|
|
21
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|
|
39
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|
|
16
|
|
|
24
|
|
|
8
|
|
|
|
|
|
||
Total
|
8,328
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|
|
3,074
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|
|
1,859
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|
|
778
|
|
|
2,847
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|
|
772
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|
|
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|
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(a)
|
Reduction in December 31, 2016 gross and net productive wells and service wells is primarily due to the dispositions of certain conventional West Texas and Wyoming assets in 2016. See Item 8. Financial Statements and Supplementary Data - Note
5
to the consolidated financial statements for information about these dispositions.
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Development
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Exploratory
|
|
|
|||||||||||||||||||||
|
Oil
|
|
Natural
Gas
|
|
Dry
|
|
Total
|
|
Oil
|
|
Natural
Gas
|
|
Dry
|
|
Total
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|
Total
|
|||||||||
2017
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
U.S.
|
107
|
|
|
27
|
|
|
—
|
|
|
134
|
|
|
88
|
|
|
16
|
|
|
—
|
|
|
104
|
|
|
238
|
|
E.G.
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Libya
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total Africa
|
—
|
|
|
—
|
|
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Other International
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
107
|
|
|
27
|
|
|
—
|
|
|
134
|
|
|
88
|
|
|
16
|
|
|
—
|
|
|
104
|
|
|
238
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
U.S.
|
64
|
|
|
12
|
|
|
—
|
|
|
76
|
|
|
70
|
|
|
27
|
|
|
—
|
|
|
97
|
|
|
173
|
|
E.G.
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Libya
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total Africa
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Other International
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
64
|
|
|
12
|
|
|
—
|
|
|
76
|
|
|
70
|
|
|
27
|
|
|
—
|
|
|
97
|
|
|
173
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
U.S.
|
135
|
|
|
36
|
|
|
11
|
|
|
182
|
|
|
49
|
|
|
48
|
|
|
1
|
|
|
98
|
|
|
280
|
|
E.G.
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
1
|
|
|
2
|
|
Libya
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total Africa
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
1
|
|
|
2
|
|
Other International
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
Total
|
136
|
|
|
37
|
|
|
11
|
|
|
184
|
|
|
49
|
|
|
48
|
|
|
2
|
|
|
99
|
|
|
283
|
|
|
Developed
|
|
Undeveloped
|
|
Developed and
Undeveloped
|
||||||||||||
(In thousands)
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
U.S.
|
1,529
|
|
|
1,008
|
|
|
388
|
|
|
322
|
|
|
1,917
|
|
|
1,330
|
|
E.G.
|
82
|
|
|
67
|
|
|
54
|
|
|
36
|
|
|
136
|
|
|
103
|
|
Libya
|
12,909
|
|
|
2,108
|
|
|
—
|
|
|
—
|
|
|
12,909
|
|
|
2,108
|
|
Other Africa
|
—
|
|
|
—
|
|
|
277
|
|
|
277
|
|
|
277
|
|
|
277
|
|
Total Africa
|
12,991
|
|
|
2,175
|
|
|
331
|
|
|
313
|
|
|
13,322
|
|
|
2,488
|
|
Other International
|
86
|
|
|
31
|
|
|
171
|
|
|
32
|
|
|
257
|
|
|
63
|
|
Total
|
14,606
|
|
|
3,214
|
|
|
890
|
|
|
667
|
|
|
15,496
|
|
|
3,881
|
|
|
|
Africa
|
|
|
|
|
|
|
|
|
||||||||||
|
U.S.
|
|
E.G.
|
|
Libya
|
|
Other Int'l
|
|
Cont Ops
|
|
Disc Ops
|
|
Total |
|||||||
Year Ended December 31,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
2017
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Crude and condensate
(mbbld)
(a)
|
133
|
|
|
21
|
|
|
19
|
|
|
12
|
|
|
185
|
|
|
—
|
|
|
185
|
|
Natural gas liquids
(mbbld)
|
43
|
|
|
11
|
|
|
—
|
|
|
1
|
|
|
55
|
|
|
—
|
|
|
55
|
|
Natural gas
(mmcfd)
(b)
|
348
|
|
|
459
|
|
|
4
|
|
|
22
|
|
|
833
|
|
|
—
|
|
|
833
|
|
Synthetic crude oil
(mbbld)
(c)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
18
|
|
|
18
|
|
Total sales volumes
(mboed)
|
234
|
|
|
109
|
|
|
20
|
|
|
16
|
|
|
379
|
|
|
18
|
|
|
397
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Crude and condensate
(mbbld)
(a)
|
131
|
|
|
20
|
|
|
3
|
|
|
12
|
|
|
166
|
|
|
—
|
|
|
166
|
|
Natural gas liquids
(mbbld)
|
40
|
|
|
11
|
|
|
—
|
|
|
—
|
|
|
51
|
|
|
—
|
|
|
51
|
|
Natural gas
(mmcfd)
(b)
|
314
|
|
|
425
|
|
|
—
|
|
|
28
|
|
|
767
|
|
|
—
|
|
|
767
|
|
Synthetic crude oil
(mbbld)
(c)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
48
|
|
|
48
|
|
Total sales volumes
(mboed)
|
223
|
|
|
102
|
|
|
3
|
|
|
17
|
|
|
345
|
|
|
48
|
|
|
393
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Crude and condensate
(mbbld)
(a)
|
171
|
|
|
19
|
|
|
—
|
|
|
14
|
|
|
204
|
|
|
—
|
|
|
204
|
|
Natural gas liquids
(mbbld)
|
39
|
|
|
10
|
|
|
—
|
|
|
—
|
|
|
49
|
|
|
—
|
|
|
49
|
|
Natural gas
(mmcfd)
(b)
|
351
|
|
|
410
|
|
|
—
|
|
|
21
|
|
|
782
|
|
|
—
|
|
|
782
|
|
Synthetic crude oil
(mbbld)
(c)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
45
|
|
|
45
|
|
Total sales volumes
(mboed)
|
269
|
|
|
97
|
|
|
—
|
|
|
18
|
|
|
384
|
|
|
45
|
|
|
429
|
|
(a)
|
The amounts correspond with the basis for fiscal settlements with governments, representing equity tanker liftings and direct deliveries of liquid hydrocarbons.
|
(b)
|
Includes natural gas acquired for injection and subsequent resale.
|
(c)
|
Upgraded bitumen excluding blendstocks.
|
|
|
|
Africa
|
|
|
|
|
|
|
|
|
||||||||||||||||
(Dollars per boe)
|
U.S.
|
|
E.G.
|
|
Libya
|
|
Other Int'l
|
|
Cont Ops
|
|
Disc Ops
|
|
Total
|
||||||||||||||
2017
|
$
|
9.49
|
|
|
$
|
2.12
|
|
|
$
|
6.08
|
|
|
$
|
26.61
|
|
|
$
|
7.90
|
|
|
$
|
29.72
|
|
|
$
|
9.23
|
|
2016
|
9.84
|
|
|
2.17
|
|
|
N.M.
|
|
|
23.13
|
|
|
8.41
|
|
|
29.36
|
|
|
11.02
|
|
|||||||
2015
|
10.65
|
|
|
2.37
|
|
|
N.M.
|
|
|
27.23
|
|
|
9.54
|
|
|
38.42
|
|
|
12.62
|
|
(a)
|
Production, severance and property taxes are excluded; however, shipping and handling as well as other operating expenses are included in the production costs used in this calculation. See Item 8. Financial Statements and Supplementary Data – Supplementary Information on Oil and Gas Producing Activities - Results of Operations for Oil and Gas Production Activities for more information regarding production costs.
|
|
|
|
Africa
|
|
|
|
|
|
|
||||||||||||||||||
(Dollars per unit)
|
U.S.
|
|
E.G.
|
|
Libya
|
|
Total
|
|
Other Int'l
|
|
Disc Ops
|
|
Total |
||||||||||||||
2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
Crude and condensate
(bbl)
|
$
|
49.35
|
|
|
$
|
46.02
|
|
|
$
|
60.72
|
|
|
$
|
53.11
|
|
|
$
|
52.66
|
|
|
$
|
—
|
|
|
$
|
50.38
|
|
Natural gas liquids
(bbl)
|
20.55
|
|
|
1.00
|
|
(b)
|
—
|
|
|
1.00
|
|
|
39.65
|
|
|
—
|
|
|
16.65
|
|
|||||||
Natural gas
(mcf)
|
2.84
|
|
|
0.24
|
|
(b)
|
5.03
|
|
|
0.28
|
|
|
6.28
|
|
|
—
|
|
|
1.51
|
|
|||||||
Synthetic crude oil
(bbl)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
47.39
|
|
|
47.39
|
|
|||||||
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
Crude and condensate
(bbl)
|
$
|
38.57
|
|
|
$
|
38.85
|
|
|
$
|
57.69
|
|
|
$
|
40.95
|
|
|
$
|
43.21
|
|
|
$
|
—
|
|
|
$
|
39.23
|
|
Natural gas liquids
(bbl)
|
13.15
|
|
|
1.00
|
|
(b)
|
—
|
|
|
1.00
|
|
|
26.41
|
|
|
—
|
|
|
10.68
|
|
|||||||
Natural gas
(mcf)
|
2.38
|
|
|
0.24
|
|
(b)
|
—
|
|
|
0.24
|
|
|
4.80
|
|
|
—
|
|
|
1.26
|
|
|||||||
Synthetic crude oil
(bbl)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
37.57
|
|
|
37.57
|
|
|||||||
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
Crude and condensate
(bbl)
|
$
|
43.50
|
|
|
$
|
42.83
|
|
|
$
|
—
|
|
|
$
|
42.83
|
|
|
$
|
53.91
|
|
|
$
|
—
|
|
|
$
|
44.14
|
|
Natural gas liquids
(bbl)
|
13.37
|
|
|
1.00
|
|
(b)
|
—
|
|
|
1.00
|
|
|
32.53
|
|
|
—
|
|
|
11.16
|
|
|||||||
Natural gas
(mcf)
|
2.66
|
|
|
0.24
|
|
(b)
|
—
|
|
|
0.24
|
|
|
6.85
|
|
|
—
|
|
|
1.50
|
|
|||||||
Synthetic crude oil
(bbl)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
40.13
|
|
|
40.13
|
|
(a)
|
Excludes gains or losses on commodity derivative instruments.
|
(b)
|
Primarily represents fixed prices under long-term contracts with Alba Plant LLC, AMPCO and/or EGHoldings, which are equity method investees. We include our share of income from each of these equity method investees in our International E&P Segment.
|
|
|
2018
|
|
2019
|
|
2020
|
|
Thereafter
|
|
Commitment Period Through
|
|||
Eagle Ford
|
|
|
|
|
|
|
|
|
|
|
|||
Crude and condensate
(mbbld)
|
|
95
|
|
|
65
|
|
|
51
|
|
|
—
|
|
2020
|
Natural gas liquids
(mbbld)
|
|
1
|
|
|
1
|
|
|
—
|
|
|
—
|
|
2020
|
Natural gas
(mmcfd)
|
|
168
|
|
|
168
|
|
|
168
|
|
|
46 - 70
|
|
2022
|
Bakken
|
|
|
|
|
|
|
|
|
|
|
|||
Crude and condensate
(mbbld)
|
|
10
|
|
|
10
|
|
|
10
|
|
|
5 - 10
|
|
2027
|
Natural gas
(mmcfd)
|
|
2
|
|
|
2
|
|
|
2
|
|
|
2 - 25
|
|
2027
|
Oklahoma
|
|
|
|
|
|
|
|
|
|
|
|||
Natural gas
(mmcfd)
|
|
—
|
|
|
90
|
|
|
118
|
|
|
110 - 148
|
|
2030
|
Lee M. Tillman
|
|
56
|
|
President and Chief Executive Officer
|
Dane E. Whitehead
|
|
56
|
|
Executive Vice President and Chief Financial Officer
|
T. Mitch Little
|
|
54
|
|
Executive Vice President—Operations
|
Reginald D. Hedgebeth
|
|
50
|
|
Senior Vice President, General Counsel and Secretary
|
Patrick J. Wagner
|
|
53
|
|
Executive Vice President-Corporate Development and Strategy
|
Catherine L. Krajicek
|
|
56
|
|
Vice President—Conventional
|
Gary E. Wilson
|
|
56
|
|
Vice President, Controller and Chief Accounting Officer
|
•
|
our Code of Business Conduct and Code of Ethics for Senior Financial Officers;
|
•
|
our Corporate Governance Principles; and
|
•
|
the charters of our Audit and Finance Committee, Compensation Committee, Corporate Governance and Nominating Committee and Health, Environmental, Safety and Corporate Responsibility Committee.
|
•
|
worldwide and domestic supplies of and demand for crude oil and condensate, NGLs and natural gas;
|
•
|
the cost of exploring for, developing and producing crude oil and condensate, NGLs and natural gas;
|
•
|
the ability of the members of OPEC and certain non-OPEC members, such as Russia, to agree to and maintain production controls;
|
•
|
the production levels of non-OPEC countries, including production levels in the shale plays in the United States;
|
•
|
the level of drilling, completion and production activities by other exploration and production companies, and variability therein, in response to market conditions;
|
•
|
political instability or armed conflict in oil and natural gas producing regions;
|
•
|
changes in weather patterns and climate;
|
•
|
natural disasters such as hurricanes and tornadoes;
|
•
|
the price and availability of alternative and competing forms of energy;
|
•
|
the effect of conservation efforts;
|
•
|
epidemics or pandemics;
|
•
|
technological advances affecting energy consumption and energy supply;
|
•
|
domestic and foreign governmental regulations and taxes; and
|
•
|
general economic conditions worldwide.
|
•
|
reducing the amount of crude oil and condensate, NGLs and natural gas that we can produce economically;
|
•
|
reducing our revenues, operating income and cash flows;
|
•
|
causing us to reduce our capital expenditures, and delay or postpone some of our capital projects;
|
•
|
requiring us to impair the carrying value of our assets;
|
•
|
reducing the standardized measure of discounted future net cash flows relating to crude oil and condensate, NGLs and natural gas; and
|
•
|
increasing the costs of obtaining capital, such as equity and short- and long-term debt.
|
|
SEC Pricing 2017
|
||
WTI Crude oil (per bbl)
|
$
|
51.34
|
|
Henry Hub natural gas (per mmbtu)
|
$
|
2.98
|
|
Brent crude oil (per bbl)
|
$
|
54.39
|
|
Mont Belvieu NGLs (per bbl)
|
$
|
22.03
|
|
•
|
location, size and shape of the accumulation as well as fluid, rock and producing characteristics of the accumulation;
|
•
|
historical production from the area, compared with production from other analogous producing areas;
|
•
|
the assumed impacts of regulation by governmental agencies;
|
•
|
assumptions concerning future operating costs, taxes, development costs and workover and repair costs; and
|
•
|
industry economic conditions, levels of cash flows from operations and other operating considerations.
|
•
|
the amount and timing of production;
|
•
|
the revenues and costs associated with that production; and
|
•
|
the amount and timing of future development expenditures.
|
•
|
obtaining rights to explore for, develop and produce crude oil and condensate, NGLs and natural gas in promising areas;
|
•
|
drilling success;
|
•
|
the ability to complete projects timely and cost effectively;
|
•
|
the ability to find or acquire additional proved reserves at acceptable costs; and
|
•
|
the ability to fund such activity.
|
•
|
unexpected drilling conditions;
|
•
|
title problems;
|
•
|
pressure or irregularities in formations;
|
•
|
equipment failures or accidents;
|
•
|
inflation in exploration and drilling costs;
|
•
|
fires, explosions, blowouts or surface cratering;
|
•
|
lack of access to pipelines or other transportation methods; and
|
•
|
shortages or delays in the availability of services or delivery of equipment.
|
•
|
denial of or delay in receiving requisite regulatory approvals and/or permits;
|
•
|
unplanned increases in the cost of construction materials or labor;
|
•
|
disruptions in transportation of components or construction materials;
|
•
|
increased costs or operational delays resulting from shortages of water;
|
•
|
adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of vendors or suppliers;
|
•
|
shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;
|
•
|
market-related increases in a project’s debt or equity financing costs; and
|
•
|
nonperformance by, or disputes with, vendors, suppliers, contractors or subcontractors.
|
•
|
changes in governmental policies relating to crude oil and condensate, NGLs or natural gas and taxation;
|
•
|
other political, economic or diplomatic developments and international monetary fluctuations;
|
•
|
political and economic instability, war, acts of terrorism, armed conflict and civil disturbances;
|
•
|
the possibility that a government may seize our property with or without compensation, may attempt to renegotiate or revoke existing contractual arrangements or may impose additional taxes or royalty burdens; and
|
•
|
fluctuating currency values, hard currency shortages and currency controls.
|
•
|
volatility in global crude oil prices which could negatively impact the global economy, resulting in slower economic growth rates and reduced demand for our products;
|
•
|
negative impact on the world crude oil supply if transportation avenues are disrupted;
|
•
|
security concerns leading to the prolonged evacuation of our personnel;
|
•
|
damage to, or the inability to access, production facilities or other operating assets; and
|
•
|
inability of our service and equipment providers to deliver items necessary for us to conduct our operations.
|
•
|
we may be more vulnerable to general adverse economic and industry conditions;
|
•
|
a portion of our cash flows from operating activities must be used to service our indebtedness and is not available for other purposes;
|
•
|
our flexibility in planning for, or reacting to, changes in our industry may be limited;
|
•
|
a financial covenant in our Credit Agreement stipulates that our total debt to capitalization ratio will not exceed 65% as of the last day of any fiscal quarter, and if exceeded, may make additional borrowings more expensive and affect our ability to plan for and react to changes in the economy and our industry;
|
•
|
we may be at a competitive disadvantage as compared to similar companies that have less debt; and
|
•
|
additional financing in the future for working capital, capital expenditures, acquisitions or development activities, general corporate or other purposes may have higher costs and more restrictive covenants.
|
Period
|
Total Number of
Shares
Purchased
(a)
|
|
Average
Price Paid
per Share
|
|
Total Number of
Shares Purchased
as Part of Publicly
Announced Plans
or Programs
(b)
|
|
Approximate
Dollar Value of
Shares that May
Yet Be Purchased
Under the Plans
or Programs
(b)
|
|||||
10/01/17 – 10/31/17
|
49,046
|
|
|
$13.38
|
|
—
|
|
|
$
|
1,500,285,529
|
|
|
11/01/17 – 11/30/17
|
2,813
|
|
|
$14.62
|
|
—
|
|
|
$
|
1,500,285,529
|
|
|
12/01/17 – 12/31/17
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
1,500,285,529
|
|
Total
|
51,859
|
|
|
$13.45
|
|
—
|
|
|
|
(a)
|
51,859
shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.
|
(b)
|
In January 2006, we announced a $2.0 billion share repurchase program. Our Board of directors subsequently increased the authorization for repurchases under the program by $500 million in January 2007, by $500 million in May 2007, by $2.0 billion in July 2007, and by $1.2 billion in December 2013, for a total authorized amount of $6.2 billion. The remaining share repurchase authorization as of
December 31, 2017
is $1.5 billion. No repurchases were made under the program in 2017.
|
|
Year Ended December 31,
|
||||||||||||||||||
(In millions, except per share data)
|
2017
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
||||||||||
Statement of Income Data
(a)(b)(c)
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues
|
$
|
4,373
|
|
|
$
|
3,170
|
|
|
$
|
4,635
|
|
|
$
|
9,238
|
|
|
$
|
9,731
|
|
Income (loss) from continuing operations
|
(830
|
)
|
|
(2,087
|
)
|
|
(1,701
|
)
|
|
710
|
|
|
710
|
|
|||||
Discontinued operations
|
(4,893
|
)
|
|
(53
|
)
|
|
(503
|
)
|
|
2,336
|
|
|
1,043
|
|
|||||
Net income (loss)
|
(5,723
|
)
|
|
(2,140
|
)
|
|
(2,204
|
)
|
|
3,046
|
|
|
1,753
|
|
|||||
Per Share Data
(a)(b)(c)
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic:
|
|
|
|
|
|
|
|
|
|
||||||||||
Income (loss) from continuing operations
|
$
|
(0.97
|
)
|
|
$
|
(2.55
|
)
|
|
$
|
(2.51
|
)
|
|
$
|
1.04
|
|
|
$
|
1.01
|
|
Discontinued operations
|
$
|
(5.76
|
)
|
|
$
|
(0.06
|
)
|
|
$
|
(0.75
|
)
|
|
$
|
3.44
|
|
|
$
|
1.48
|
|
Net income (loss)
|
$
|
(6.73
|
)
|
|
$
|
(2.61
|
)
|
|
$
|
(3.26
|
)
|
|
$
|
4.48
|
|
|
$
|
2.49
|
|
Diluted:
|
|
|
|
|
|
|
|
|
|
||||||||||
Income (loss) from continuing operations
|
$
|
(0.97
|
)
|
|
$
|
(2.55
|
)
|
|
$
|
(2.51
|
)
|
|
$
|
1.04
|
|
|
$
|
1.00
|
|
Discontinued operations
|
$
|
(5.76
|
)
|
|
$
|
(0.06
|
)
|
|
$
|
(0.75
|
)
|
|
$
|
3.42
|
|
|
$
|
1.47
|
|
Net income (loss)
|
$
|
(6.73
|
)
|
|
$
|
(2.61
|
)
|
|
$
|
(3.26
|
)
|
|
$
|
4.46
|
|
|
$
|
2.47
|
|
Statement of Cash Flows Data
(b)
|
|
|
|
|
|
|
|
|
|
||||||||||
Additions to property, plant and equipment related to continuing operations
|
$
|
(1,974
|
)
|
|
$
|
(1,204
|
)
|
|
$
|
(3,485
|
)
|
|
$
|
(4,937
|
)
|
|
$
|
(4,170
|
)
|
Dividends paid
|
170
|
|
|
162
|
|
|
460
|
|
|
543
|
|
|
508
|
|
|||||
Dividends per share
|
$
|
0.20
|
|
|
$
|
0.20
|
|
|
$
|
0.68
|
|
|
$0.80
|
|
$0.72
|
||||
Balance Sheet Data at December 31
|
|
|
|
|
|
|
|
|
|
||||||||||
Total assets
|
$
|
22,012
|
|
|
$
|
31,094
|
|
|
$
|
32,311
|
|
|
$
|
35,983
|
|
|
$
|
35,588
|
|
Total long-term debt, including capitalized leases
|
5,494
|
|
|
6,581
|
|
|
7,268
|
|
|
5,285
|
|
|
6,352
|
|
(a)
|
Includes impairments to producing properties of
$229 million
,
$67 million
,
$381 million
,
$132 million
and
$96 million
in
2017
,
2016
,
2015
,
2014
and
2013
and impairments to unproved properties of
$246 million
,
$195 million
,
$655 million
,
$306 million
and
$572 million
in
2017
,
2016
,
2015
,
2014
and
2013
(see Item 8. Financial Statements and Supplementary Data – Note
10
to the consolidated financial statements). Includes a goodwill impairment of
$340 million
in 2015 related to the U.S. E&P reporting unit (see Item 8. Financial Statements and Supplementary Data – Note
12
to the consolidated financial statements).
|
(b)
|
We closed on the sale of our Canada business in 2017 which resulted in an after-tax non-cash impairment charge of
$4.96 billion
and our Angola assets and Norway business in 2014 (see Item 8. Financial Statements and Supplementary Data – Note
5
to the consolidated financial statements). The applicable periods have been recast to reflect as discontinued operations.
|
(c)
|
December 31, 2016 includes the increase of a valuation allowance on certain of our deferred tax assets for $1,346 million (see Item 8. Financial Statements and Supplementary Data – Note 9 to the consolidated financial statements).
|
•
|
United States E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas in the United States
|
•
|
International E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of the United States and produces and markets products manufactured from natural gas, such as LNG and methanol, in E.G.
|
•
|
Ended 2017 with liquidity of
$4.0 billion
, comprised of
$563 million
in cash and cash equivalents and an undrawn $3.4 billion revolving credit facility, which was increased from $3.3 billion in July 2017. Remaining proceeds of $750 million from the sale of our Canadian business are scheduled to be received in the first quarter of 2018.
|
•
|
In third quarter 2017, we issued $1 billion of 4.4% senior unsecured notes due in 2027 and redeemed approximately
$1.75 billion
of debt due in 2017, 2018 and 2019. This offering and redemption reduced our future annual interest expense by approximately $64 million.
|
•
|
In December 2017, we redeemed $1 billion of 5.125% municipal revenue bonds due in 2037 in a refunding transaction that preserved our ability to remarket up to $1 billion of tax-exempt municipal bonds prior to 2037. This redemption reduced our future annual interest expense by approximately $51 million.
|
•
|
We closed on the sale of our Canadian business for approximately $2.5 billion with over $1.8 billion in proceeds received to date and $750 million to be received in first quarter 2018.
|
•
|
We closed on multiple Permian basin acquisitions for approximately
$1.9 billion
of cash on hand.
|
•
|
Total 2017 net sales volumes from continuing operations are
379
mboed, including Libya, which is
10%
higher compared to 2016. This includes a 12% increase in sales volumes from the U.S resource plays to 217 mboed within our
United States E&P
segment.
|
•
|
Due to improved cost structure and higher sales volumes, our production expense rate in our
United States E&P
segment decreased
7%
to
$5.57
per boe in 2017 compared to last year. In our International E&P segment, our production expense rate decreased
14%
to
$4.33
per boe in 2017 primarily due to an increase in sales volumes in E.G. and Libya.
|
•
|
Added proved reserves of 193 mmboe for a reserve replacement ratio from continuing operations of 140%.
|
•
|
Net cash provided by operating activities in
2017
was
$2.0 billion
, compared to
$901 million
in
2016
primarily as a result of improved price realizations, increased sales volumes and lower unit production expenses.
|
•
|
Our net loss per share from continuing operations was
$0.97
in
2017
as compared to a net loss per share of
$2.55
last year. Included in the 2017 net loss are:
|
◦
|
An increase in sales and other operating revenues of over 40% to
$4.2 billion
primarily due to improved price realizations and increased sales volumes.
|
◦
|
Our sales volumes from continuing operations increased
10%
while production expense remained flat during 2017 as a result of improved cost structure.
|
◦
|
Depreciation, depletion and amortization expense increased
10%
to
$2.4 billion
due to our increase in sales volumes from continuing operations.
|
◦
|
Exploration and impairment expenses increased by
$248 million
to
$638 million
, year over year, primarily due to non-cash impairment charges on proved and unproved properties primarily as a result of the anticipated sales of certain non-core international assets and due to lower forecasted long-term commodity prices.
|
◦
|
Our provision for income taxes was
$376 million
in 2017 primarily as a result of our full valuation allowance on our net federal deferred tax assets throughout 2017 and the effects of our foreign operations. See Item 8. Financial Statements and Supplementary Data - Note
7
to the consolidated financial statements for a discussion of the effects of U.S. Tax Reform Legislation.
|
(In millions)
|
Capital Development Program
|
||
United States E&P
|
|
||
Eagle Ford
|
$
|
710
|
|
Bakken
|
590
|
|
|
Oklahoma
|
410
|
|
|
Northern Delaware
|
380
|
|
|
Total United States E&P
|
$
|
2,090
|
|
International E&P and corporate other
(a)
|
210
|
|
|
Total Capital Development Program
|
$
|
2,300
|
|
Net Sales Volumes
|
2017
|
|
Increase
(Decrease) |
|
2016
|
|
Increase
(Decrease) |
|
2015
|
||
United States E&P
(mboed)
|
234
|
|
5
|
%
|
|
223
|
|
(17
|
)%
|
|
269
|
International E&P
(a)
(mboed)
|
145
|
|
19
|
%
|
|
122
|
|
5
|
%
|
|
116
|
Total Continuing Operations
(mboed)
|
379
|
|
10
|
%
|
|
345
|
|
(10
|
)%
|
|
385
|
Sales Mix - U.S. Resource Plays - 2017
|
|
Oklahoma
|
|
Eagle Ford
|
|
Bakken
|
|
Northern Delaware
|
|
Total
|
Crude oil and condensate
|
|
28%
|
|
58%
|
|
83%
|
|
66%
|
|
57%
|
Natural gas liquids
|
|
26%
|
|
21%
|
|
10%
|
|
8%
|
|
19%
|
Natural gas
|
|
46%
|
|
21%
|
|
7%
|
|
26%
|
|
24%
|
•
|
Eagle Ford
– Our net sales volumes were
101
mboed in 2017,
4%
lower compared to 2016. We brought fewer wells to sales in 2017, while we increased well productivity through completion optimization and efficiency gains.
|
•
|
Bakken
– Our net sales volumes were
56
mboed in 2017 compared to
54
mboed in 2016. In 2017, we improved well performance with continued application of high intensity completions. During the year, we set a new record in the Williston Basin for the highest 30-day initial production oil rate.
|
•
|
Oklahoma
– Our net sales volumes in 2017 increased by
54%
to
54
mboed compared to year ended 2016. Our activity during 2017 was concentrated in the STACK and was focused on leasehold capture, delineation drilling and infill spacing pilots.
|
•
|
Northern Delaware
– Our net sales volumes were
6
mboed in 2017 which reflected a partial year of production following the second quarter 2017 closing of the BC Operating and Black Mountain assets. During 2017 we focused our activity on delineation and leasehold capture across our position in Eddy and Lea Counties, New Mexico.
|
Net Sales Volumes
|
2017
|
|
Increase
(Decrease) |
|
2016
|
|
Increase
(Decrease) |
|
2015
|
Equivalent Barrels
(mboed)
|
|
|
|
|
|
|
|
|
|
Equatorial Guinea
|
109
|
|
7%
|
|
102
|
|
5%
|
|
97
|
United Kingdom
(a)
|
14
|
|
(18)%
|
|
17
|
|
(11)%
|
|
19
|
Libya
|
20
|
|
567%
|
|
3
|
|
100%
|
|
—
|
Other International
|
2
|
|
100%
|
|
—
|
|
—%
|
|
—
|
Total International E&P
(mboed)
|
145
|
|
19%
|
|
122
|
|
5%
|
|
116
|
Equity Method Investees
|
|
|
|
|
|
|
|
|
|
LNG
(mtd)
|
6,423
|
|
9%
|
|
5,874
|
|
—%
|
|
5,884
|
Methanol
(mtd)
|
1,374
|
|
1%
|
|
1,358
|
|
45%
|
|
937
|
Condensate & LPG
(boed)
|
14,501
|
|
8%
|
|
13,430
|
|
10%
|
|
12,208
|
•
|
Equatorial Guinea
– Net sales volumes in 2017 were higher than 2016 as a result of the completion and start-up of our Alba field compression project in mid-2016 and lower volumes in first quarter 2016 due to a planned turnaround. Additionally, in April 2017 we received host government approval to develop Block D offshore E.G. through unitization with the Alba field.
|
•
|
United Kingdom
– Net sales volumes in 2017 decreased compared to 2016 primarily as a result of planned turn-around activity at the Brae and Foinaven complexes and the temporary shut-down of the outside-operated Forties Pipeline System during fourth quarter 2017.
|
•
|
Libya
– While civil and political unrest has interrupted operations in recent years, our production resumed in October 2016. During December 2016, liftings resumed from the Es Sider crude oil terminal. During 2017, sales volumes and production continued, except for a brief interruption in March 2017 due to civil unrest.
|
|
|
2017
|
|
Increase (Decrease)
|
|
2016
|
|
Increase (Decrease)
|
|
2015
|
|||||||
Average Price Realizations
(a)
|
|
|
|
|
|
|
|
|
|
|
|||||||
Crude Oil and Condensate
(per bbl)
(b)
|
|
|
$49.35
|
|
|
28
|
%
|
|
|
$38.57
|
|
|
(11
|
)%
|
|
43.50
|
|
Natural Gas Liquids
(per bbl)
|
|
20.55
|
|
|
56
|
%
|
|
13.15
|
|
|
(2
|
)%
|
|
13.37
|
|
||
Total Liquid Hydrocarbons
(per bbl)
|
|
42.31
|
|
|
29
|
%
|
|
32.71
|
|
|
(14
|
)%
|
|
37.85
|
|
||
Natural Gas
(per mcf)
(c)
|
|
2.84
|
|
|
19
|
%
|
|
2.38
|
|
|
(11
|
)%
|
|
2.66
|
|
||
Benchmarks
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
WTI crude oil average of daily prices
(per bbl)
|
|
|
$50.85
|
|
|
17
|
%
|
|
|
$43.47
|
|
|
(11
|
)%
|
|
48.76
|
|
LLS crude oil average of daily prices
(per bbl)
|
|
54.04
|
|
|
20
|
%
|
|
45.02
|
|
|
(14
|
)%
|
|
52.33
|
|
||
Mont Belvieu NGLs
(per bbl)
(d)
|
|
23.76
|
|
|
37
|
%
|
|
17.40
|
|
|
3
|
%
|
|
16.94
|
|
||
Henry Hub natural gas settlement date average (per
mmbtu)
|
|
3.11
|
|
|
26
|
%
|
|
2.46
|
|
|
(8
|
)%
|
|
2.66
|
|
(a)
|
Excludes gains or losses on commodity derivative instruments.
|
(b)
|
Inclusion of realized gains on crude oil derivative instruments would have increased average liquid hydrocarbon price realizations per barrel by
$0.75
,
$0.92
, and
$1.24
for
2017
,
2016
, and
2015
.
|
(c)
|
Inclusion of realized gains (losses) on natural gas derivative instruments would have a minimal impact on average price realizations for the periods presented.
|
(d)
|
Bloomberg Finance LLP: Y-grade Mix NGL of 50% ethane, 25% propane, 10% butane, 5% isobutane and 10% natural gasoline.
|
|
|
2017
|
|
Increase (Decrease)
|
|
2016
|
|
(Decrease)
|
|
2015
|
||||||||
Average Price Realizations
|
|
|
|
|
|
|
|
|
|
|
||||||||
Crude Oil and Condensate
(per bbl)
|
|
|
$53.05
|
|
|
27
|
%
|
|
|
$41.70
|
|
|
(12
|
)%
|
|
|
$47.50
|
|
Natural Gas Liquids
(per bbl)
|
|
3.15
|
|
|
49
|
%
|
|
2.11
|
|
|
(25
|
)%
|
|
2.81
|
|
|||
Total Liquid Hydrocarbons
(per bbl)
|
|
43.36
|
|
|
35
|
%
|
|
32.10
|
|
|
(12
|
)%
|
|
36.67
|
|
|||
Natural Gas
(per mcf)
|
|
0.55
|
|
|
6
|
%
|
|
0.52
|
|
|
(24
|
)%
|
|
0.68
|
|
|||
Benchmark
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Brent (Europe) crude oil
(per bbl)
(a)
|
|
|
$54.25
|
|
|
25
|
%
|
|
|
$43.55
|
|
|
(17
|
)%
|
|
|
$52.35
|
|
(a)
|
Average of monthly prices obtained from the United States Energy Information Agency website.
|
|
Year Ended December 31,
|
|||||
(In millions)
|
2017
|
2016
|
||||
Sales and other operating revenues, including related party
|
|
|
||||
United States E&P
|
$
|
3,138
|
|
$
|
2,375
|
|
International E&P
|
1,154
|
|
665
|
|
||
Segment sales and other operating revenues, including related party
|
4,292
|
|
3,040
|
|
||
Unrealized gain (loss) on commodity derivative instruments
|
(81
|
)
|
(110
|
)
|
||
Sales and other operating revenues, including related party
|
$
|
4,211
|
|
$
|
2,930
|
|
($ per boe)
|
2017
|
2016
|
||||
Production Expense Rate
|
|
|
||||
United States E&P
|
|
$5.57
|
|
|
$5.96
|
|
International E&P
|
|
$4.33
|
|
|
$5.05
|
|
|
Year Ended December 31,
|
|||||
(In millions)
|
2017
|
2016
|
||||
Exploration Expenses
|
|
|
||||
Unproved property impairments
|
$
|
246
|
|
$
|
195
|
|
Dry well costs
|
77
|
|
25
|
|
||
Geological and geophysical
|
25
|
|
5
|
|
||
Other
|
61
|
|
98
|
|
||
Total exploration expenses
|
$
|
409
|
|
$
|
323
|
|
($ per boe)
|
2017
|
2016
|
||||
DD&A rate
|
|
|
||||
United States E&P
|
|
$23.51
|
|
|
$22.49
|
|
International E&P
|
|
$6.19
|
|
|
$6.21
|
|
|
Year Ended December 31,
|
|||||
(In millions)
|
2017
|
2016
|
||||
Taxes other than income
|
|
|
||||
Production and severance
|
$
|
121
|
|
$
|
91
|
|
Ad valorem
|
13
|
|
23
|
|
||
Other
|
49
|
|
37
|
|
||
Total
|
$
|
183
|
|
$
|
151
|
|
|
Year Ended December 31,
|
||||||
(In millions)
|
2017
|
|
2016
|
||||
United States E&P
|
$
|
(148
|
)
|
|
$
|
(415
|
)
|
International E&P
|
374
|
|
|
228
|
|
||
Segment income (loss)
|
226
|
|
|
(187
|
)
|
||
Items not allocated to segments, net of income taxes
(a)
|
(1,056
|
)
|
|
(1,900
|
)
|
||
Income (loss) from continuing operations
|
(830
|
)
|
|
(2,087
|
)
|
||
Income (loss) from discontinued operations
(b)
|
(4,893
|
)
|
|
(53
|
)
|
||
Net income (loss)
|
$
|
(5,723
|
)
|
|
$
|
(2,140
|
)
|
|
Year Ended December 31,
|
|||||
(In millions)
|
2016
|
2015
|
||||
Sales and other operating revenues, including related party
|
|
|
||||
United States E&P
|
$
|
2,375
|
|
$
|
3,358
|
|
International E&P
|
665
|
|
728
|
|
||
Segment sales and other operating revenues, including related party
|
3,040
|
|
4,086
|
|
||
Unrealized gain on crude oil derivative instruments
|
(110
|
)
|
50
|
|
||
Sales and other operating revenues, including related party
|
$
|
2,930
|
|
$
|
4,136
|
|
($ per boe)
|
2016
|
2015
|
||||
Production Expense Rate
|
|
|
||||
United States E&P
|
|
$5.96
|
|
|
$7.38
|
|
International E&P
|
|
$5.05
|
|
|
$5.99
|
|
|
Year Ended December 31,
|
|||||
(In millions)
|
2016
|
2015
|
||||
Exploration Expenses
|
|
|
||||
Unproved property impairments
|
$
|
195
|
|
$
|
655
|
|
Dry well costs
|
25
|
|
212
|
|
||
Geological and geophysical
|
5
|
|
31
|
|
||
Other
|
98
|
|
73
|
|
||
Total exploration expenses
|
$
|
323
|
|
$
|
971
|
|
($ per boe)
|
2016
|
2015
|
||||
DD&A rate
|
|
|
||||
United States E&P
|
|
$22.49
|
|
|
$24.24
|
|
International E&P
|
|
$6.21
|
|
|
$6.95
|
|
|
Year Ended December 31,
|
|||||
(In millions)
|
2016
|
2015
|
||||
Taxes other than income
|
|
|
||||
Production and severance
|
$
|
91
|
|
$
|
131
|
|
Ad valorem
|
23
|
|
39
|
|
||
Other
|
37
|
|
46
|
|
||
Total taxes other than income
|
$
|
151
|
|
$
|
216
|
|
|
Year Ended December 31,
|
||||||
(In millions)
|
2016
|
|
2015
|
||||
United States E&P
|
$
|
(415
|
)
|
|
$
|
(452
|
)
|
International E&P
|
228
|
|
|
112
|
|
||
Segment income (loss)
|
(187
|
)
|
|
(340
|
)
|
||
Items not allocated to segments, net of income taxes
(a)
|
(1,900
|
)
|
|
(1,361
|
)
|
||
Income (loss) from continuing operations
|
(2,087
|
)
|
|
(1,701
|
)
|
||
Income (loss) from discontinued operations
(b)
|
(53
|
)
|
|
(503
|
)
|
||
Net income (loss)
|
$
|
(2,140
|
)
|
|
$
|
(2,204
|
)
|
•
|
Improved cost structure by reducing production expense per boe in 2017.
|
•
|
Total 2017 net sales volumes from continuing operations increased
10%
compared to 2016.
|
•
|
Divested certain non-core assets resulting in net proceeds of $
1.79 billion
.
|
•
|
We closed on multiple Permian basin acquisitions for $
1.89 billion
with cash on hand.
|
•
|
Through multiple financing transactions we have reduced total debt by approximately
$1.75 billion
which will result in a reduction to our future annual interest expense of approximately $115 million.
|
•
|
Expect to receive $750 million in remaining proceeds from the sale of our Canadian business by March 1, 2018.
|
•
|
Expanded the capacity of the revolving credit facility from $3.3 billion to $3.4 billion.
|
|
Year Ended December 31,
|
||||||||||
(In millions)
|
2017
|
|
2016
|
|
2015
|
||||||
Sources of cash and cash equivalents
|
|
|
|
|
|
|
|
||||
Operating activities - continuing operations
|
$
|
1,988
|
|
|
$
|
901
|
|
|
$
|
1,537
|
|
Disposals of assets, net of cash transferred to the buyer
|
1,787
|
|
|
1,219
|
|
|
225
|
|
|||
Common stock issuance
|
—
|
|
|
1,236
|
|
|
—
|
|
|||
Borrowings
|
988
|
|
|
—
|
|
|
1,996
|
|
|||
Other
|
68
|
|
|
56
|
|
|
101
|
|
|||
Total sources of cash and cash equivalents
|
$
|
4,831
|
|
|
$
|
3,412
|
|
|
$
|
3,859
|
|
Uses of cash and cash equivalents
|
|
|
|
|
|
||||||
Cash additions to property, plant and equipment
|
$
|
(1,974
|
)
|
|
$
|
(1,204
|
)
|
|
$
|
(3,485
|
)
|
Acquisitions, net of cash acquired
|
(1,891
|
)
|
|
(902
|
)
|
|
—
|
|
|||
Purchases of common stock
|
(11
|
)
|
|
(6
|
)
|
|
(11
|
)
|
|||
Debt repayments
|
(2,764
|
)
|
|
(1
|
)
|
|
(1,069
|
)
|
|||
Debt extinguishment costs
|
(46
|
)
|
|
—
|
|
|
—
|
|
|||
Dividends paid
|
(170
|
)
|
|
(162
|
)
|
|
(460
|
)
|
|||
Other
|
(30
|
)
|
|
(4
|
)
|
|
(8
|
)
|
|||
Total uses of cash and cash equivalents
|
$
|
(6,886
|
)
|
|
$
|
(2,279
|
)
|
|
$
|
(5,033
|
)
|
|
Year Ended December 31,
|
||||||||||
(In millions)
|
2017
|
|
2016
|
|
2015
|
||||||
United States E&P
|
$
|
2,081
|
|
|
$
|
936
|
|
|
$
|
2,553
|
|
International E&P
|
42
|
|
|
82
|
|
|
368
|
|
|||
Corporate
|
27
|
|
|
18
|
|
|
25
|
|
|||
Total capital expenditures
|
2,150
|
|
|
1,036
|
|
|
2,946
|
|
|||
Change in capital expenditure accrual
|
(176
|
)
|
|
168
|
|
|
539
|
|
|||
Additions to property, plant and equipment
|
$
|
1,974
|
|
|
$
|
1,204
|
|
|
$
|
3,485
|
|
(Dollars in millions)
|
2017
|
|
2016
|
||||
Long-term debt due within one year
|
$
|
—
|
|
|
$
|
686
|
|
Long-term debt
|
5,494
|
|
|
6,581
|
|
||
Total debt
|
$
|
5,494
|
|
|
$
|
7,267
|
|
Equity
|
$
|
11,708
|
|
|
$
|
17,541
|
|
Calculation
|
|
|
|
||||
Total debt
|
$
|
5,494
|
|
|
$
|
7,267
|
|
Total debt plus equity (total capitalization)
|
$
|
17,202
|
|
|
$
|
24,808
|
|
Debt-to-capital ratio
|
32
|
%
|
|
29
|
%
|
(In millions)
|
Total
|
|
2018
|
|
2019-
2020
|
|
2021-
2022
|
|
Later
Years
|
||||||||||
Short and long-term debt (includes interest)
(a)
|
$
|
8,776
|
|
|
$
|
256
|
|
|
$
|
1,103
|
|
|
$
|
1,512
|
|
|
$
|
5,905
|
|
Lease obligations
|
119
|
|
|
29
|
|
|
55
|
|
|
31
|
|
|
4
|
|
|||||
Purchase obligations:
|
|
|
|
|
|
|
|
|
|
||||||||||
Oil and gas activities
(b)
|
108
|
|
|
94
|
|
|
8
|
|
|
4
|
|
|
2
|
|
|||||
Service and materials contracts
(c)
|
115
|
|
|
65
|
|
|
48
|
|
|
2
|
|
|
—
|
|
|||||
Transportation and related contracts
|
1,581
|
|
|
313
|
|
|
483
|
|
|
241
|
|
|
544
|
|
|||||
Drilling rigs and fracturing crews
(d)
|
21
|
|
|
21
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Other
|
42
|
|
|
13
|
|
|
24
|
|
|
5
|
|
|
—
|
|
|||||
Total purchase obligations
|
1,867
|
|
|
506
|
|
|
563
|
|
|
252
|
|
|
546
|
|
|||||
Other long-term liabilities reported in the consolidated balance sheet
(e)
|
486
|
|
|
141
|
|
|
77
|
|
|
63
|
|
|
205
|
|
|||||
Total contractual cash obligations
(f)
|
$
|
11,248
|
|
|
$
|
932
|
|
|
$
|
1,798
|
|
|
$
|
1,858
|
|
|
$
|
6,660
|
|
(a)
|
Includes anticipated cash payments for interest of
$256 million
for
2018
,
$503 million
for
2019
-
2020
,
$477 million
for
2021
-
2022
and
$2,003 million
for the remaining years for a total of
$3,239 million
.
|
(b)
|
Oil and gas activities include contracts to acquire property, plant and equipment and commitments for oil and gas exploration such as costs related to contractually obligated exploratory work programs that are expensed immediately.
|
(c)
|
Service and materials contracts include contracts to purchase services such as utilities, supplies and various other maintenance and operating services.
|
(d)
|
Some contracts may be canceled at an amount less than the contract amount. Were we to elect that option where possible at December 31,
2017
our minimum commitment would be
$14 million
.
|
(e)
|
Primarily includes obligations for pension and other postretirement benefits including medical and life insurance. We have estimated projected funding requirements through 2027. Although unrecognized tax benefits are not a contractual obligation, they are presented in this table because they represent potential demands on our liquidity.
|
(f)
|
This table does not include the estimated discounted liability for dismantlement, abandonment and restoration costs of oil and gas properties of
$1,483 million
. See Item 8. Financial Statements and Supplementary Data – Note
11
to the consolidated financial statements.
|
|
SEC Pricing 2017
|
||
WTI Crude oil (per bbl)
|
$
|
51.34
|
|
Henry Hub natural gas (per mmbtu)
|
$
|
2.98
|
|
Brent crude oil (per bbl)
|
$
|
54.39
|
|
Mont Belvieu NGLs (per bbl)
|
$
|
22.03
|
|
|
Impact of a 10% Increase in Proved Reserves
|
|
Impact of a 10% Decrease in Proved Reserves
|
||||||||||||
(In millions, except per boe)
|
DD&A per boe
|
|
Pretax Income
|
|
DD&A per boe
|
|
Pretax Income
|
||||||||
United States E&P
|
$
|
(2.14
|
)
|
|
$
|
183
|
|
|
$
|
2.61
|
|
|
$
|
(224
|
)
|
International E&P
|
$
|
(0.56
|
)
|
|
$
|
30
|
|
|
$
|
0.69
|
|
|
$
|
(36
|
)
|
•
|
Level 1 – Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
|
•
|
Level 2 – Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the measurement date.
|
•
|
Level 3 – Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.
|
•
|
impairment assessments of long-lived assets;
|
•
|
impairment assessments of goodwill; and
|
•
|
recorded value of derivative instruments.
|
•
|
Future crude oil and condensate, NGLs and natural gas prices.
Our estimates of future prices are based on our analysis of market supply and demand and consideration of market price indicators. Although these commodity prices may experience extreme volatility in any given year, we believe long-term industry prices are driven by global market supply and demand. To estimate supply, we consider numerous factors, including the worldwide resource base, depletion rates and OPEC production policies. We believe demand is largely driven by global economic factors, such as population and income growth, governmental policies and vehicle stocks. The prices we use in our fair value estimates are consistent with those used in our planning and capital investment reviews. There has been significant volatility in crude oil and condensate, NGLs and natural gas prices and estimates of such future prices are inherently imprecise. See Item 1A. Risk Factors for further discussion on commodity prices.
|
•
|
Estimated quantities of crude oil and condensate, NGLs and natural gas.
Such quantities are based on a combination of proved reserves and risk-weighted probable reserves and resources such that the combined volumes represent the most likely expectation of recovery. See Item 1A. Risk Factors for further discussion on reserves.
|
•
|
Expected timing of production.
Production forecasts are the outcome of engineering studies which estimate reserves, as well as expected capital development programs. The actual timing of the production could be different than the projection. Cash flows realized later in the projection period are less valuable than those realized earlier due to the time value of money. The expected timing of production that we use in our fair value estimates is consistent with that used in our planning and capital investment reviews.
|
•
|
Discount rate commensurate with the risks involved.
We apply a discount rate to our expected cash flows based on a variety of factors, including market and economic conditions, operational risk, regulatory risk and political risk. A higher discount rate decreases the net present value of cash flows.
|
•
|
Future capital requirements.
Our estimates of future capital requirements are based upon a combination of authorized spending and internal forecasts.
|
•
|
the discount rate for measuring the present value of future plan obligations;
|
•
|
the expected long-term return on plan assets;
|
•
|
the rate of future increases in compensation levels; and
|
•
|
health care cost projections.
|
|
Impact of a 0.25% Increase in Discount Rate
|
|
Impact of a 0.25% Decrease in Discount Rate
|
||||||||||||
(In millions)
|
Obligation
|
|
Expense
|
|
Obligation
|
|
Expense
|
||||||||
U.S. pension plans
|
$
|
(4
|
)
|
|
$
|
—
|
|
|
$
|
4
|
|
|
$
|
—
|
|
Other U.S. postretirement benefit plans
|
$
|
(5
|
)
|
|
$
|
—
|
|
|
$
|
5
|
|
|
$
|
—
|
|
Crude Oil
|
|||||||||||
|
2018
|
|
2019
|
||||||||
|
First Quarter
|
|
Second Quarter
|
|
Third Quarter
|
|
Fourth Quarter
|
|
First Quarter
|
|
Second Quarter
|
Three-Way Collars
(a)
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbls/day)
|
85,000
|
|
85,000
|
|
85,000
|
|
85,000
|
|
10,000
|
|
10,000
|
Weighted average price per Bbl:
|
|
|
|
|
|
|
|
|
|
|
|
Ceiling
|
$56.38
|
|
$56.38
|
|
$56.96
|
|
$56.96
|
|
$60.00
|
|
$60.00
|
Floor
|
$51.65
|
|
$51.65
|
|
$51.53
|
|
$51.53
|
|
$55.00
|
|
$55.00
|
Sold put
|
$45.00
|
|
$45.00
|
|
$44.65
|
|
$44.65
|
|
$47.00
|
|
$47.00
|
Swaps
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbls/day)
|
20,000
|
|
20,000
|
|
—
|
|
—
|
|
—
|
|
—
|
Weighted average price per Bbl
|
$55.12
|
|
$55.12
|
|
$—
|
|
$—
|
|
$—
|
|
$—
|
Basis Swaps
(b)
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbls/day)
|
5,000
|
|
5,000
|
|
10,000
|
|
10,000
|
|
—
|
|
—
|
Weighted average price per Bbl
|
$(0.60)
|
|
$(0.60)
|
|
$(0.67)
|
|
$(0.67)
|
|
$—
|
|
$—
|
(a)
|
Between January 1, 2018 and February 12, 2018, we entered into 10,000 Bbls/day of three-way collars for July - December 2018 with an average ceiling
|
(b)
|
The basis differential price is between WTI Midland and WTI Cushing.
|
Natural Gas
|
||||
|
2018
|
|||
|
First Quarter
|
Second Quarter
|
Third Quarter
|
Fourth Quarter
|
Three-Way Collars
|
|
|
|
|
Volume (MMBtu/day)
|
200,000
|
160,000
|
160,000
|
160,000
|
Weighted average price per MMBtu
|
|
|
|
|
Ceiling
|
$3.79
|
$3.61
|
$3.61
|
$3.61
|
Floor
|
$3.08
|
$3.00
|
$3.00
|
$3.00
|
Sold put
|
$2.55
|
$2.50
|
$2.50
|
$2.50
|
(In millions)
|
Hypothetical Price Increase of 10%
|
Hypothetical Price Decrease of 10%
|
||||
Crude oil derivatives
|
$
|
(180
|
)
|
$
|
149
|
|
Natural gas derivatives
|
(8
|
)
|
7
|
|
||
Total
|
$
|
(188
|
)
|
$
|
156
|
|
(In millions)
|
Fair Value
|
|
Hypothetical Price Increase of 10%
|
Hypothetical Price Decrease of 10%
|
||||||
Financial assets (liabilities):
(a)
|
|
|
|
|
||||||
Long-term debt, including amounts due within one year
|
$
|
(5,976
|
)
|
(b)(c)
|
$
|
190
|
|
$
|
(202
|
)
|
(a)
|
Fair values of cash and cash equivalents, receivables, accounts payable and accrued interest approximate carrying value and are relatively insensitive to changes in interest rates due to the short-term maturity of the instruments. Accordingly, these instruments are excluded from the table.
|
(b)
|
Fair value was based on market prices where available, or current borrowing rates for financings with similar terms and maturities.
|
(c)
|
Excludes capital leases.
|
|
Page
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Lee M. Tillman
|
|
/s/ Dane E. Whitehead
|
|
|
President and Chief Executive Officer
|
|
Executive Vice President and Chief Financial Officer
|
|
|
/s/ Lee M. Tillman
|
|
/s/ Dane E. Whitehead
|
|
President and Chief Executive Officer
|
|
Executive Vice President and Chief Financial Officer
|
|
|
Year Ended December 31,
|
||||||||||
(In millions, except per share data)
|
2017
|
|
2016
|
|
2015
|
||||||
Revenues and other income:
|
|
|
|
|
|
||||||
Sales and other operating revenues, including related party
|
$
|
4,211
|
|
|
$
|
2,930
|
|
|
$
|
4,136
|
|
Marketing revenues
|
162
|
|
|
240
|
|
|
499
|
|
|||
Income from equity method investments
|
256
|
|
|
175
|
|
|
145
|
|
|||
Net gain (loss) on disposal of assets
|
58
|
|
|
389
|
|
|
120
|
|
|||
Other income
|
78
|
|
|
53
|
|
|
53
|
|
|||
Total revenues and other income
|
4,765
|
|
|
3,787
|
|
|
4,953
|
|
|||
Costs and expenses:
|
|
|
|
|
|
||||||
Production
|
706
|
|
|
712
|
|
|
979
|
|
|||
Marketing, including purchases from related parties
|
168
|
|
|
245
|
|
|
500
|
|
|||
Other operating
|
431
|
|
|
484
|
|
|
410
|
|
|||
Exploration
|
409
|
|
|
323
|
|
|
971
|
|
|||
Depreciation, depletion and amortization
|
2,372
|
|
|
2,156
|
|
|
2,721
|
|
|||
Impairments
|
229
|
|
|
67
|
|
|
721
|
|
|||
Taxes other than income
|
183
|
|
|
151
|
|
|
216
|
|
|||
General and administrative
|
400
|
|
|
481
|
|
|
588
|
|
|||
Total costs and expenses
|
4,898
|
|
|
4,619
|
|
|
7,106
|
|
|||
Income (loss) from operations
|
(133
|
)
|
|
(832
|
)
|
|
(2,153
|
)
|
|||
Net interest and other
|
(270
|
)
|
|
(332
|
)
|
|
(286
|
)
|
|||
Loss on early extinguishment of debt
|
(51
|
)
|
|
—
|
|
|
—
|
|
|||
Income (loss) from continuing operations before income taxes
|
(454
|
)
|
|
(1,164
|
)
|
|
(2,439
|
)
|
|||
Provision (benefit) for income taxes
|
376
|
|
|
923
|
|
|
(738
|
)
|
|||
Income (loss) from continuing operations
|
(830
|
)
|
|
(2,087
|
)
|
|
(1,701
|
)
|
|||
Income (loss) from discontinued operations
|
(4,893
|
)
|
|
(53
|
)
|
|
(503
|
)
|
|||
Net income (loss)
|
$
|
(5,723
|
)
|
|
$
|
(2,140
|
)
|
|
$
|
(2,204
|
)
|
Per Share Data
|
|
|
|
|
|
||||||
Basic:
|
|
|
|
|
|
||||||
Income (loss) from continuing operations
|
$
|
(0.97
|
)
|
|
$
|
(2.55
|
)
|
|
$
|
(2.51
|
)
|
Income (loss) from discontinued operations
|
$
|
(5.76
|
)
|
|
$
|
(0.06
|
)
|
|
$
|
(0.75
|
)
|
Net income (loss)
|
$
|
(6.73
|
)
|
|
$
|
(2.61
|
)
|
|
$
|
(3.26
|
)
|
Diluted:
|
|
|
|
|
|
||||||
Income (loss) from continuing operations
|
$
|
(0.97
|
)
|
|
$
|
(2.55
|
)
|
|
$
|
(2.51
|
)
|
Income (loss) from discontinued operations
|
$
|
(5.76
|
)
|
|
$
|
(0.06
|
)
|
|
$
|
(0.75
|
)
|
Net income (loss)
|
$
|
(6.73
|
)
|
|
$
|
(2.61
|
)
|
|
$
|
(3.26
|
)
|
Dividends
|
$
|
0.20
|
|
|
$
|
0.20
|
|
|
$
|
0.68
|
|
Weighted average shares:
|
|
|
|
|
|
||||||
Basic
|
850
|
|
|
819
|
|
|
677
|
|
|||
Diluted
|
850
|
|
|
819
|
|
|
677
|
|
|
Year Ended December 31,
|
||||||||||
(In millions)
|
2017
|
|
2016
|
|
2015
|
||||||
Net income (loss)
|
$
|
(5,723
|
)
|
|
$
|
(2,140
|
)
|
|
$
|
(2,204
|
)
|
Other comprehensive income (loss)
|
|
|
|
|
|
||||||
Postretirement and postemployment plans
|
|
|
|
|
|
||||||
Change in actuarial loss and other
|
21
|
|
|
16
|
|
|
228
|
|
|||
Income tax provision (benefit)
|
7
|
|
|
(4
|
)
|
|
(86
|
)
|
|||
Postretirement and postemployment plans, net of tax
|
28
|
|
|
12
|
|
|
142
|
|
|||
Derivative hedges
|
|
|
|
|
|
||||||
Net unrecognized gain (loss)
|
(13
|
)
|
|
61
|
|
|
—
|
|
|||
Reclassification of gains on terminated derivative hedges
|
(47
|
)
|
|
—
|
|
|
—
|
|
|||
Income tax provision (benefit)
|
21
|
|
|
(22
|
)
|
|
—
|
|
|||
Derivative hedges, net of tax
|
(39
|
)
|
|
39
|
|
|
—
|
|
|||
Foreign currency hedges
|
|
|
|
|
|
||||||
Net recognized loss reclassified to discontinued operations
|
34
|
|
|
—
|
|
|
—
|
|
|||
Income tax provision (benefit)
|
(4
|
)
|
|
—
|
|
|
—
|
|
|||
Foreign currency hedges, net of tax
|
30
|
|
|
—
|
|
|
—
|
|
|||
Other, net of tax
|
2
|
|
|
1
|
|
|
—
|
|
|||
Other comprehensive income (loss)
|
21
|
|
|
52
|
|
|
142
|
|
|||
Comprehensive income (loss)
|
$
|
(5,702
|
)
|
|
$
|
(2,088
|
)
|
|
$
|
(2,062
|
)
|
|
December 31,
|
||||||
(In millions, except par values and share amounts)
|
2017
|
|
2016
|
||||
Assets
|
|
|
|
||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
563
|
|
|
$
|
2,488
|
|
Receivables, less reserve of $12 and $6
|
1,082
|
|
|
748
|
|
||
Notes receivable
|
748
|
|
|
—
|
|
||
Inventories
|
126
|
|
|
136
|
|
||
Other current assets
|
36
|
|
|
66
|
|
||
Current assets held for sale
|
11
|
|
|
227
|
|
||
Total current assets
|
2,566
|
|
|
3,665
|
|
||
Equity method investments
|
847
|
|
|
931
|
|
||
Property, plant and equipment, less accumulated depreciation,
|
|
|
|
|
|
||
depletion and amortization of $21,564 and $20,255
|
17,665
|
|
|
16,727
|
|
||
Goodwill
|
115
|
|
|
115
|
|
||
Other noncurrent assets
|
764
|
|
|
558
|
|
||
Noncurrent assets held for sale
|
55
|
|
|
9,098
|
|
||
Total assets
|
$
|
22,012
|
|
|
$
|
31,094
|
|
Liabilities
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Accounts payable
|
$
|
1,395
|
|
|
$
|
967
|
|
Payroll and benefits payable
|
108
|
|
|
129
|
|
||
Accrued taxes
|
177
|
|
|
94
|
|
||
Other current liabilities
|
288
|
|
|
243
|
|
||
Long-term debt due within one year
|
—
|
|
|
686
|
|
||
Current liabilities held for sale
|
—
|
|
|
121
|
|
||
Total current liabilities
|
1,968
|
|
|
2,240
|
|
||
Long-term debt
|
5,494
|
|
|
6,581
|
|
||
Deferred tax liabilities
|
833
|
|
|
769
|
|
||
Defined benefit postretirement plan obligations
|
362
|
|
|
345
|
|
||
Asset retirement obligations
|
1,428
|
|
|
1,602
|
|
||
Deferred credits and other liabilities
|
217
|
|
|
225
|
|
||
Noncurrent liabilities held for sale
|
2
|
|
|
1,791
|
|
||
Total liabilities
|
10,304
|
|
|
13,553
|
|
||
Commitments and contingencies
|
|
|
|
|
|||
Stockholders’ Equity
|
|
|
|
||||
Preferred stock - no shares issued or outstanding (no par value,
|
|
|
|
||||
26 million shares authorized)
|
—
|
|
|
—
|
|
||
Common stock:
|
|
|
|
||||
Issued – 937 million and 937 million shares, respectively (par value $1 per share, 1.1 billion shares authorized)
|
937
|
|
|
937
|
|
||
Held in treasury, at cost – 87 million and 90 million shares
|
(3,325
|
)
|
|
(3,431
|
)
|
||
Additional paid-in capital
|
7,379
|
|
|
7,446
|
|
||
Retained earnings
|
6,779
|
|
|
12,672
|
|
||
Accumulated other comprehensive loss
|
(62
|
)
|
|
(83
|
)
|
||
Total stockholders' equity
|
11,708
|
|
|
17,541
|
|
||
Total liabilities and stockholders' equity
|
$
|
22,012
|
|
|
$
|
31,094
|
|
|
Year Ended December 31,
|
||||||||||
(In millions)
|
2017
|
|
2016
|
|
2015
|
||||||
Increase (decrease) in cash and cash equivalents
|
|
|
|
|
|
||||||
Operating activities:
|
|
|
|
|
|
|
|||||
Net income (loss)
|
$
|
(5,723
|
)
|
|
$
|
(2,140
|
)
|
|
$
|
(2,204
|
)
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
|
|||||
Discontinued operations
|
4,893
|
|
|
53
|
|
|
503
|
|
|||
Depreciation, depletion and amortization
|
2,372
|
|
|
2,156
|
|
|
2,721
|
|
|||
Impairments
|
229
|
|
|
67
|
|
|
721
|
|
|||
Exploratory dry well costs and unproved property impairments
|
323
|
|
|
220
|
|
|
867
|
|
|||
Net (gain) loss on disposal of assets
|
(58
|
)
|
|
(389
|
)
|
|
(120
|
)
|
|||
Deferred income taxes
|
(61
|
)
|
|
828
|
|
|
(804
|
)
|
|||
Net (gain) loss on derivative instruments
|
(11
|
)
|
|
63
|
|
|
(126
|
)
|
|||
Net cash received (paid) in settlement of derivative instruments
|
98
|
|
|
61
|
|
|
55
|
|
|||
Stock based compensation
|
50
|
|
|
48
|
|
|
45
|
|
|||
Equity method investments, net
|
20
|
|
|
17
|
|
|
33
|
|
|||
Changes in:
|
|
|
|
|
|
||||||
Current receivables
|
(334
|
)
|
|
67
|
|
|
790
|
|
|||
Inventories
|
10
|
|
|
64
|
|
|
25
|
|
|||
Current accounts payable and accrued liabilities
|
297
|
|
|
(137
|
)
|
|
(906
|
)
|
|||
All other operating, net
|
(117
|
)
|
|
(77
|
)
|
|
(63
|
)
|
|||
Net cash provided by operating activities from continuing operations
|
1,988
|
|
|
901
|
|
|
1,537
|
|
|||
Investing activities:
|
|
|
|
|
|
||||||
Additions to property, plant and equipment
|
(1,974
|
)
|
|
(1,204
|
)
|
|
(3,485
|
)
|
|||
Acquisitions, net of cash acquired
|
(1,891
|
)
|
|
(902
|
)
|
|
—
|
|
|||
Disposal of assets, net of cash transferred to the buyer
|
1,787
|
|
|
1,219
|
|
|
225
|
|
|||
Equity method investments - return of capital
|
64
|
|
|
55
|
|
|
77
|
|
|||
Purchases of short term investments
|
—
|
|
|
—
|
|
|
(925
|
)
|
|||
Maturities of short term investments
|
—
|
|
|
—
|
|
|
925
|
|
|||
All other investing, net
|
(30
|
)
|
|
(1
|
)
|
|
24
|
|
|||
Net cash used in investing activities from continuing operations
|
(2,044
|
)
|
|
(833
|
)
|
|
(3,159
|
)
|
|||
Financing activities:
|
|
|
|
|
|
||||||
Borrowings
|
988
|
|
|
—
|
|
|
1,996
|
|
|||
Debt repayments
|
(2,764
|
)
|
|
(1
|
)
|
|
(1,069
|
)
|
|||
Debt extinguishment costs
|
(46
|
)
|
|
—
|
|
|
—
|
|
|||
Common stock issuance
|
—
|
|
|
1,236
|
|
|
—
|
|
|||
Purchases of common stock
|
(11
|
)
|
|
(6
|
)
|
|
(11
|
)
|
|||
Dividends paid
|
(170
|
)
|
|
(162
|
)
|
|
(460
|
)
|
|||
All other financing, net
|
—
|
|
|
1
|
|
|
(5
|
)
|
|||
Net cash provided by (used in) financing activities
|
(2,003
|
)
|
|
1,068
|
|
|
451
|
|
|||
Cash Flow from Discontinued Operations:
|
|
|
|
|
|
||||||
Operating activities
|
141
|
|
|
177
|
|
|
39
|
|
|||
Investing activities
|
(13
|
)
|
|
(41
|
)
|
|
(43
|
)
|
|||
Changes in cash included in current assets held for sale
|
2
|
|
|
100
|
|
|
90
|
|
|||
Net increase in cash and cash equivalents of discontinued operations
|
130
|
|
|
236
|
|
|
86
|
|
|||
Effect of exchange rate changes on cash and cash equivalents:
|
4
|
|
|
(3
|
)
|
|
(3
|
)
|
|||
Net increase (decrease) in cash and cash equivalents
|
(1,925
|
)
|
|
1,369
|
|
|
(1,088
|
)
|
|||
Cash and cash equivalents at beginning of period
|
2,488
|
|
|
1,119
|
|
|
2,207
|
|
|||
Cash and cash equivalents at end of period
|
$
|
563
|
|
|
$
|
2,488
|
|
|
$
|
1,119
|
|
|
Total Equity of Marathon Oil Stockholders
|
|
|
||||||||||||||||||||||||
(In millions)
|
Preferred
Stock
|
|
Common
Stock
|
|
Treasury
Stock
|
|
Additional
Paid-in
Capital
|
|
Retained
Earnings
|
|
Accumulated
Other
Comprehensive
Loss
|
|
Total
Equity
|
||||||||||||||
December 31, 2014 Balance
|
$
|
—
|
|
|
$
|
770
|
|
|
$
|
(3,642
|
)
|
|
$
|
6,531
|
|
|
$
|
17,638
|
|
|
$
|
(277
|
)
|
|
$
|
21,020
|
|
Shares issued - stock-based
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
compensation
|
—
|
|
|
—
|
|
|
96
|
|
|
(32
|
)
|
|
—
|
|
|
—
|
|
|
64
|
|
|||||||
Shares repurchased
|
—
|
|
|
—
|
|
|
(8
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(8
|
)
|
|||||||
Stock-based compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|||||||
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,204
|
)
|
|
—
|
|
|
(2,204
|
)
|
|||||||
Other comprehensive loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
142
|
|
|
142
|
|
|||||||
Dividends paid
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(460
|
)
|
|
—
|
|
|
(460
|
)
|
|||||||
December 31, 2015 Balance
|
$
|
—
|
|
|
$
|
770
|
|
|
$
|
(3,554
|
)
|
|
$
|
6,498
|
|
|
$
|
14,974
|
|
|
$
|
(135
|
)
|
|
$
|
18,553
|
|
Shares issued - stock-based
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
compensation
|
—
|
|
|
—
|
|
|
128
|
|
|
(86
|
)
|
|
—
|
|
|
—
|
|
|
42
|
|
|||||||
Shares repurchased
|
—
|
|
|
—
|
|
|
(5
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(5
|
)
|
|||||||
Stock-based compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
(35
|
)
|
|
—
|
|
|
—
|
|
|
(35
|
)
|
|||||||
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,140
|
)
|
|
—
|
|
|
(2,140
|
)
|
|||||||
Other comprehensive income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
52
|
|
|
52
|
|
|||||||
Dividends paid
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(162
|
)
|
|
—
|
|
|
(162
|
)
|
|||||||
Common stock issuance
|
—
|
|
|
167
|
|
|
—
|
|
|
1,069
|
|
|
—
|
|
|
—
|
|
|
1,236
|
|
|||||||
December 31, 2016 Balance
|
$
|
—
|
|
|
$
|
937
|
|
|
$
|
(3,431
|
)
|
|
$
|
7,446
|
|
|
$
|
12,672
|
|
|
$
|
(83
|
)
|
|
$
|
17,541
|
|
Shares issued - stock-based
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
compensation
|
—
|
|
|
—
|
|
|
117
|
|
|
(50
|
)
|
|
—
|
|
|
—
|
|
|
67
|
|
|||||||
Shares repurchased
|
—
|
|
|
—
|
|
|
(11
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(11
|
)
|
|||||||
Stock-based compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
(17
|
)
|
|
—
|
|
|
—
|
|
|
(17
|
)
|
|||||||
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(5,723
|
)
|
|
—
|
|
|
(5,723
|
)
|
|||||||
Other comprehensive income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
21
|
|
|
21
|
|
|||||||
Dividends paid
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(170
|
)
|
|
—
|
|
|
(170
|
)
|
|||||||
Common stock issuance
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
December 31, 2017 Balance
|
$
|
—
|
|
|
$
|
937
|
|
|
$
|
(3,325
|
)
|
|
$
|
7,379
|
|
|
$
|
6,779
|
|
|
$
|
(62
|
)
|
|
$
|
11,708
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
(Shares in millions)
|
Preferred
Stock
|
|
Common
Stock
|
|
Treasury
Stock
|
|
|
|
|
|
|
|
|
||||||||||||||
December 31, 2014 Balance
|
—
|
|
|
770
|
|
|
95
|
|
|
|
|
|
|
|
|
|
|||||||||||
Shares issued - stock-based
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
compensation
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|||||||||||
Shares repurchased
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|||||||||||
December 31, 2015 Balance
|
—
|
|
|
770
|
|
|
93
|
|
|
|
|
|
|
|
|
|
|||||||||||
Shares issued - stock-based
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
compensation
|
—
|
|
|
—
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
|||||||||||
Shares repurchased
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|||||||||||
Common stock issuance
|
—
|
|
|
167
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|||||||||||
December 31, 2016 Balance
|
—
|
|
|
937
|
|
|
90
|
|
|
|
|
|
|
|
|
|
|||||||||||
Shares issued - stock-based
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
compensation
|
—
|
|
|
—
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
|||||||||||
Shares repurchased
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|||||||||||
Common stock issuance
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|||||||||||
December 31, 2017 Balance
|
—
|
|
|
937
|
|
|
87
|
|
|
|
|
|
|
|
|
|
Type of Asset
|
|
Range of Useful Lives
|
Office furniture, equipment and computer hardware
|
|
4 to 15 years
|
Pipelines
|
|
10 to 40 years
|
Plants, facilities and infrastructure
|
|
3 to 40 years
|
|
Year Ended December 31,
|
||||||||||
(In millions, except per share data)
|
2017
|
|
2016
|
|
2015
|
||||||
Income (loss) from continuing operations
|
$
|
(830
|
)
|
|
$
|
(2,087
|
)
|
|
$
|
(1,701
|
)
|
Income (loss) from discontinued operations
|
(4,893
|
)
|
|
(53
|
)
|
|
(503
|
)
|
|||
Net income (loss)
|
$
|
(5,723
|
)
|
|
$
|
(2,140
|
)
|
|
$
|
(2,204
|
)
|
|
|
|
|
|
|
||||||
Weighted average common shares outstanding
|
850
|
|
|
819
|
|
|
677
|
|
|||
Per basic share:
|
|
|
|
|
|
|
|
||||
Income (loss) from continuing operations
|
$
|
(0.97
|
)
|
|
$
|
(2.55
|
)
|
|
$
|
(2.51
|
)
|
Income (loss) from discontinued operations
|
$
|
(5.76
|
)
|
|
$
|
(0.06
|
)
|
|
$
|
(0.75
|
)
|
Net income (loss)
|
$
|
(6.73
|
)
|
|
$
|
(2.61
|
)
|
|
$
|
(3.26
|
)
|
Per diluted share:
|
|
|
|
|
|
||||||
Income (loss) from continuing operations
|
$
|
(0.97
|
)
|
|
$
|
(2.55
|
)
|
|
$
|
(2.51
|
)
|
Income (loss) from discontinued operations
|
$
|
(5.76
|
)
|
|
$
|
(0.06
|
)
|
|
$
|
(0.75
|
)
|
Net income (loss)
|
$
|
(6.73
|
)
|
|
$
|
(2.61
|
)
|
|
$
|
(3.26
|
)
|
|
|
Year Ended December 31,
|
||||||||||
(In millions)
|
|
2017
|
|
2016
|
|
2015
|
||||||
Total sales and other revenues and other income
|
|
$
|
431
|
|
|
$
|
863
|
|
|
$
|
908
|
|
Net gain (loss) on disposal of assets
|
|
(43
|
)
|
|
—
|
|
|
—
|
|
|||
Total revenues and other income
|
|
388
|
|
|
863
|
|
|
908
|
|
|||
Costs and expenses:
|
|
|
|
|
|
|
||||||
Production expenses
|
|
254
|
|
|
601
|
|
|
715
|
|
|||
Exploration expenses
|
|
—
|
|
|
7
|
|
|
347
|
|
|||
Depreciation, depletion and amortization
|
|
40
|
|
|
239
|
|
|
236
|
|
|||
Impairments
|
|
6,636
|
|
|
—
|
|
|
31
|
|
|||
Other
|
|
25
|
|
|
87
|
|
|
98
|
|
|||
Total costs and expenses
|
|
6,955
|
|
|
934
|
|
|
1,427
|
|
|||
Pretax income (loss) from discontinued operations
|
|
(6,567
|
)
|
|
(71
|
)
|
|
(519
|
)
|
|||
Provision (benefit) for income taxes
|
|
(1,674
|
)
|
|
(18
|
)
|
|
(16
|
)
|
|||
Income (loss) from discontinued operations
|
|
$
|
(4,893
|
)
|
|
$
|
(53
|
)
|
|
$
|
(503
|
)
|
|
|
December 31,
|
|
December 31,
|
||||
(In millions)
|
|
2017
|
|
2016
|
||||
Assets held for sale
|
|
|
|
|
||||
Current assets:
|
|
|
|
|
||||
Cash and cash equivalents
|
|
$
|
—
|
|
|
$
|
2
|
|
Accounts receivables
|
|
—
|
|
|
129
|
|
||
Inventories
|
|
—
|
|
|
91
|
|
||
Other
|
|
—
|
|
|
4
|
|
||
Total current assets held for sale—discontinued operations
|
|
—
|
|
|
226
|
|
||
Total current assets held for sale—continuing operations
|
|
11
|
|
|
1
|
|
||
Total current assets held for sale
|
|
$
|
11
|
|
|
$
|
227
|
|
|
|
|
|
|
||||
Noncurrent assets:
|
|
|
|
|
||||
Property, plant and equipment, net
|
|
$
|
—
|
|
|
$
|
8,991
|
|
Other
|
|
—
|
|
|
106
|
|
||
Total noncurrent assets held for sale—discontinued operations
|
|
—
|
|
|
9,097
|
|
||
Total noncurrent assets held for sale—continuing operations
|
|
55
|
|
|
1
|
|
||
Total noncurrent assets held for sale
|
|
$
|
55
|
|
|
$
|
9,098
|
|
|
|
|
|
|
||||
Liabilities associated with assets held for sale
|
|
|
|
|
||||
Current liabilities:
|
|
|
|
|
||||
Accounts payable
|
|
$
|
—
|
|
|
$
|
111
|
|
Other
|
|
—
|
|
|
10
|
|
||
Total current liabilities held for sale—discontinued operations
|
|
—
|
|
|
121
|
|
||
Total current liabilities held for sale—continuing operations
|
|
—
|
|
|
—
|
|
||
Total current liabilities held for sale
|
|
$
|
—
|
|
|
$
|
121
|
|
|
|
|
|
|
||||
Noncurrent liabilities:
|
|
|
|
|
||||
Asset retirement obligations
|
|
$
|
—
|
|
|
$
|
95
|
|
Deferred tax liabilities
|
|
—
|
|
|
1,669
|
|
||
Other
|
|
—
|
|
|
20
|
|
||
Total noncurrent liabilities held for sale—discontinued operations
|
|
—
|
|
|
1,784
|
|
||
Total noncurrent liabilities held for sale—continuing operations
|
|
2
|
|
|
7
|
|
||
Total noncurrent liabilities held for sale
|
|
$
|
2
|
|
|
$
|
1,791
|
|
•
|
United States E&P ("U.S. E&P") – explores for, produces and markets crude oil and condensate, NGLs and natural gas in the United States
|
•
|
International E&P ("Int'l E&P") – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of the United States and produces and markets products manufactured from natural gas, such as LNG and methanol, in E.G.
|
Year Ended December 31, 2017
|
|
Not Allocated
|
|
|
|||||||||||
(In millions)
|
U.S. E&P
|
|
Int'l E&P
|
|
to Segments
|
|
Total
|
||||||||
Sales and other operating revenues
|
$
|
3,138
|
|
|
$
|
1,154
|
|
|
$
|
(81
|
)
|
(b)
|
$
|
4,211
|
|
Marketing revenues
|
29
|
|
|
133
|
|
|
—
|
|
|
162
|
|
||||
Total revenues
|
3,167
|
|
|
1,287
|
|
|
(81
|
)
|
|
4,373
|
|
||||
Income from equity method investments
|
—
|
|
|
256
|
|
|
—
|
|
|
256
|
|
||||
Net gain on disposal of assets and other income
|
13
|
|
|
6
|
|
|
117
|
|
(c)
|
136
|
|
||||
Less:
|
|
|
|
|
|
|
|
||||||||
Production expenses
|
476
|
|
|
229
|
|
|
1
|
|
|
706
|
|
||||
Marketing costs
|
36
|
|
|
132
|
|
|
—
|
|
|
168
|
|
||||
Other operating
|
354
|
|
|
77
|
|
|
—
|
|
|
431
|
|
||||
Exploration
|
154
|
|
|
5
|
|
|
250
|
|
(d)
|
409
|
|
||||
Depreciation, depletion and amortization
|
2,011
|
|
|
328
|
|
|
33
|
|
|
2,372
|
|
||||
Impairments
|
4
|
|
|
—
|
|
|
225
|
|
(e)
|
229
|
|
||||
Taxes other than income
|
173
|
|
|
—
|
|
|
10
|
|
|
183
|
|
||||
General and administrative
|
119
|
|
|
32
|
|
|
249
|
|
(f)
|
400
|
|
||||
Net interest and other
|
—
|
|
|
—
|
|
|
270
|
|
(g)
|
270
|
|
||||
Loss on early extinguishment of debt
|
—
|
|
|
—
|
|
|
51
|
|
(h)
|
51
|
|
||||
Income tax provision (benefit)
|
1
|
|
|
372
|
|
|
3
|
|
|
376
|
|
||||
Segment income (loss) / Income (loss) from continuing operations
|
$
|
(148
|
)
|
|
$
|
374
|
|
|
$
|
(1,056
|
)
|
|
$
|
(830
|
)
|
Capital expenditures
(a)
|
$
|
2,081
|
|
|
$
|
42
|
|
|
$
|
27
|
|
|
$
|
2,150
|
|
(a)
|
Includes accruals.
|
(b)
|
Unrealized loss on commodity derivative instruments.
|
(c)
|
Primarily related to sale of certain conventional assets in Oklahoma and Colorado. (See Note
5
).
|
(e)
|
Primarily related to proved property impairments associated with certain non-core properties within our International E&P segment. (See Note
10
).
|
(f)
|
Includes pension settlement loss of
$32 million
(see Note
17
).
|
Year Ended December 31, 2016
|
|
Not Allocated
|
|
|
|||||||||||
(In millions)
|
U.S. E&P
|
|
Int'l E&P
|
|
to Segments
|
|
Total
|
||||||||
Sales and other operating revenues
|
$
|
2,375
|
|
|
$
|
665
|
|
|
$
|
(110
|
)
|
(b)
|
$
|
2,930
|
|
Marketing revenues
|
135
|
|
|
105
|
|
|
—
|
|
|
240
|
|
||||
Total revenues
|
2,510
|
|
|
770
|
|
|
(110
|
)
|
|
3,170
|
|
||||
Income (loss) from equity method investments
|
—
|
|
|
175
|
|
|
—
|
|
|
175
|
|
||||
Net gain on disposal of assets and other income
|
28
|
|
|
32
|
|
|
382
|
|
(c)
|
442
|
|
||||
Less:
|
|
|
|
|
|
|
|
||||||||
Production expenses
|
486
|
|
|
226
|
|
|
—
|
|
|
712
|
|
||||
Marketing costs
|
142
|
|
|
103
|
|
|
—
|
|
|
245
|
|
||||
Other operating
|
328
|
|
|
43
|
|
|
113
|
|
(d)
|
484
|
|
||||
Exploration
|
127
|
|
|
17
|
|
|
179
|
|
(e)
|
323
|
|
||||
Depreciation, depletion and amortization
|
1,835
|
|
|
276
|
|
|
45
|
|
|
2,156
|
|
||||
Impairments
|
20
|
|
|
—
|
|
|
47
|
|
(f)
|
67
|
|
||||
Taxes other than income
|
149
|
|
|
—
|
|
|
2
|
|
|
151
|
|
||||
General and administrative
|
94
|
|
|
35
|
|
|
352
|
|
(g)
|
481
|
|
||||
Net interest and other
|
—
|
|
|
—
|
|
|
332
|
|
|
332
|
|
||||
Income tax provision (benefit)
|
(228
|
)
|
|
49
|
|
|
1,102
|
|
(h)
|
923
|
|
||||
Segment income (loss) / Income (loss) from continuing operations
|
$
|
(415
|
)
|
|
$
|
228
|
|
|
$
|
(1,900
|
)
|
|
$
|
(2,087
|
)
|
Capital expenditures
(a)
|
$
|
936
|
|
|
$
|
82
|
|
|
$
|
18
|
|
|
$
|
1,036
|
|
(a)
|
Includes accruals.
|
(b)
|
Unrealized loss on commodity derivative instruments.
|
(c)
|
Primarily related to net gain on disposal of assets
(see Note
5
).
|
(d)
|
Includes termination payment on our Gulf of Mexico deepwater drilling rig commitment of
$113 million
.
|
(f)
|
Proved property impairments (see Note
10
).
|
(g)
|
Includes pension settlement loss of
$103 million
and severance related expenses associated with workforce reductions of
$8 million
(see Note
17
).
|
(h)
|
Increased valuation allowance on certain of our deferred tax assets
$1,346 million
(see Note
7
).
|
Year Ended December 31, 2015
|
|
Not Allocated
|
|
|
|||||||||||
(In millions)
|
U.S. E&P
|
|
Int'l E&P
|
|
to Segments
|
|
Total
|
||||||||
Sales and other operating revenues
|
$
|
3,358
|
|
|
$
|
728
|
|
|
$
|
50
|
|
(b)
|
$
|
4,136
|
|
Marketing revenues
|
396
|
|
|
103
|
|
|
—
|
|
|
499
|
|
||||
Total revenues
|
3,754
|
|
|
831
|
|
|
50
|
|
|
4,635
|
|
||||
Income from equity method investments
|
—
|
|
|
157
|
|
|
(12
|
)
|
(c)
|
145
|
|
||||
Net gain on disposal of assets and other income
|
24
|
|
|
27
|
|
|
122
|
|
(d)
|
173
|
|
||||
Less:
|
|
|
|
|
|
|
|
||||||||
Production expenses
|
724
|
|
|
255
|
|
|
—
|
|
|
979
|
|
||||
Marketing costs
|
401
|
|
|
99
|
|
|
—
|
|
|
500
|
|
||||
Other operating
|
335
|
|
|
48
|
|
|
27
|
|
|
410
|
|
||||
Exploration
|
314
|
|
|
101
|
|
|
556
|
|
(e)
|
971
|
|
||||
Depreciation, depletion and amortization
|
2,377
|
|
|
295
|
|
|
49
|
|
|
2,721
|
|
||||
Impairments
|
2
|
|
|
—
|
|
|
719
|
|
(f)
|
721
|
|
||||
Taxes other than income
|
215
|
|
|
—
|
|
|
1
|
|
|
216
|
|
||||
General and administrative
|
127
|
|
|
44
|
|
|
417
|
|
(g)
|
588
|
|
||||
Net interest and other
|
—
|
|
|
—
|
|
|
286
|
|
|
286
|
|
||||
Income tax provision (benefit)
|
(265
|
)
|
|
61
|
|
|
(534
|
)
|
|
(738
|
)
|
||||
Segment income (loss) / Income (loss) from continuing operations
|
$
|
(452
|
)
|
|
$
|
112
|
|
|
$
|
(1,361
|
)
|
|
$
|
(1,701
|
)
|
Capital expenditures
(a)
|
$
|
2,553
|
|
|
$
|
368
|
|
|
$
|
25
|
|
|
$
|
2,946
|
|
(a)
|
Includes accruals.
|
(b)
|
Unrealized gain on commodity derivative instruments.
|
(c)
|
Partial impairment of investment in equity method investee (See Note
14
).
|
(d)
|
Primarily related to gain on sale of our properties and interests in the Gulf of Mexico, partially offset by the loss on sale of East Africa exploration acreage
(see Note
5
).
|
(f)
|
Includes goodwill impairment (see Note
12
) and proved property impairments (see Note
10
).
|
(g)
|
Includes pension settlement loss of
$119 million
(see Note
17
) and severance related expenses associated with workforce reductions of
$55 million
.
|
|
Year Ended December 31,
|
||||||||||
(In millions)
|
2017
|
|
2016
|
|
2015
|
||||||
United States
|
$
|
3,086
|
|
|
$
|
2,400
|
|
|
$
|
3,804
|
|
Equatorial Guinea
|
530
|
|
|
444
|
|
|
444
|
|
|||
Libya
|
431
|
|
|
54
|
|
|
—
|
|
|||
U.K.
|
289
|
|
|
263
|
|
|
380
|
|
|||
Other international
|
37
|
|
|
9
|
|
|
7
|
|
|||
Total revenues
|
$
|
4,373
|
|
|
$
|
3,170
|
|
|
$
|
4,635
|
|
|
Year Ended December 31,
|
||||||||||
(In millions)
|
2017
|
|
2016
|
|
2015
|
||||||
Crude oil and condensate
|
$
|
3,477
|
|
|
$
|
2,605
|
|
|
$
|
3,963
|
|
Natural gas liquids
|
338
|
|
|
198
|
|
|
203
|
|
|||
Natural gas
|
510
|
|
|
356
|
|
|
464
|
|
|||
Other
|
48
|
|
|
11
|
|
|
5
|
|
|||
Total revenues
|
$
|
4,373
|
|
|
$
|
3,170
|
|
|
$
|
4,635
|
|
|
December 31,
|
||||||
(In millions)
|
2017
|
|
2016
|
||||
United States
|
$
|
15,971
|
|
|
$
|
14,272
|
|
Equatorial Guinea
|
1,582
|
|
|
1,794
|
|
||
Other international
|
959
|
|
|
1,592
|
|
||
Total long-lived assets
|
$
|
18,512
|
|
|
$
|
17,658
|
|
|
Year Ended December 31,
|
||||||||||||||||||||||||||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||||||||||||||||||||||||||
(In millions)
|
Current
|
|
Deferred
|
|
Total
|
|
Current
|
|
Deferred
|
|
Total
|
|
Current
|
|
Deferred
|
|
Total
|
||||||||||||||||||
Federal
|
$
|
(32
|
)
|
|
$
|
41
|
|
|
$
|
9
|
|
|
$
|
2
|
|
|
$
|
836
|
|
|
$
|
838
|
|
|
$
|
(41
|
)
|
|
$
|
(684
|
)
|
|
$
|
(725
|
)
|
State and local
|
(14
|
)
|
|
2
|
|
|
(12
|
)
|
|
2
|
|
|
8
|
|
|
10
|
|
|
(8
|
)
|
|
(18
|
)
|
|
(26
|
)
|
|||||||||
Foreign
|
483
|
|
|
(104
|
)
|
|
379
|
|
|
91
|
|
|
(16
|
)
|
|
75
|
|
|
115
|
|
|
(102
|
)
|
|
13
|
|
|||||||||
Total
|
$
|
437
|
|
|
$
|
(61
|
)
|
|
$
|
376
|
|
|
$
|
95
|
|
|
$
|
828
|
|
|
$
|
923
|
|
|
$
|
66
|
|
|
$
|
(804
|
)
|
|
$
|
(738
|
)
|
|
|
Year Ended December 31,
|
||||||||||
(In millions)
|
|
2017
|
|
2016
|
|
2015
|
||||||
Total pre-tax income (loss) from continuing operations
|
|
$
|
(454
|
)
|
|
$
|
(1,164
|
)
|
|
$
|
(2,439
|
)
|
Total income tax expense (benefit)
|
|
$
|
376
|
|
|
$
|
923
|
|
|
$
|
(738
|
)
|
Effective income tax expense (benefit) rate on continuing operations
|
|
83
|
%
|
|
79
|
%
|
|
(30
|
)%
|
|||
|
|
|
|
|
|
|
||||||
Income taxes at the statutory tax rate of 35%
(a)
|
|
$
|
(159
|
)
|
|
$
|
(407
|
)
|
|
$
|
(854
|
)
|
Effects of foreign operations
|
|
140
|
|
|
47
|
|
|
(55
|
)
|
|||
Adjustments to valuation allowances
|
|
446
|
|
|
1,270
|
|
|
95
|
|
|||
State income taxes
|
|
(19
|
)
|
|
9
|
|
|
(15
|
)
|
|||
Tax law change
|
|
(35
|
)
|
|
6
|
|
|
(3
|
)
|
|||
Goodwill impairment
|
|
—
|
|
|
—
|
|
|
94
|
|
|||
Other federal tax effects
|
|
3
|
|
|
(2
|
)
|
|
—
|
|
|||
Income tax expense (benefit) on continuing operations
|
|
$
|
376
|
|
|
$
|
923
|
|
|
$
|
(738
|
)
|
|
Year Ended December 31,
|
||||||
(In millions)
|
2017
|
|
2016
|
||||
Deferred tax assets:
|
|
|
|
||||
Employee benefits
|
$
|
111
|
|
|
$
|
228
|
|
Operating loss carryforwards
|
1,030
|
|
|
1,065
|
|
||
Capital loss carryforwards
|
3
|
|
|
4
|
|
||
Foreign tax credits
|
611
|
|
|
4,430
|
|
||
Other credit carryforwards
|
—
|
|
|
35
|
|
||
Investments in subsidiaries and affiliates
|
174
|
|
|
91
|
|
||
Other
|
69
|
|
|
86
|
|
||
Subtotal
|
1,998
|
|
|
5,939
|
|
||
Valuation Allowance
|
(926
|
)
|
|
(4,301
|
)
|
||
Total deferred tax assets
|
1,072
|
|
|
1,638
|
|
||
Deferred tax liabilities:
|
|
|
|
||||
Property, plant and equipment
|
1,332
|
|
|
3,672
|
|
||
Accrued revenue
|
81
|
|
|
75
|
|
||
Other
|
3
|
|
|
(7
|
)
|
||
Total deferred tax liabilities
|
1,416
|
|
|
3,740
|
|
||
Net deferred tax liabilities
|
$
|
344
|
|
|
$
|
2,102
|
|
|
December 31,
|
||||||
(In millions)
|
2017
|
|
2016
|
||||
Assets:
|
|
|
|
||||
Other noncurrent assets
|
$
|
489
|
|
|
$
|
336
|
|
Liabilities:
|
|
|
|
||||
Noncurrent deferred tax liabilities
|
833
|
|
|
769
|
|
||
Noncurrent liabilities held for sale
|
—
|
|
|
1,669
|
|
||
Net deferred tax liabilities
|
$
|
344
|
|
|
$
|
2,102
|
|
United States
(a)
|
2008-2016
|
Equatorial Guinea
|
2007-2016
|
Libya
|
2012-2016
|
United Kingdom
|
2008-2016
|
(a)
|
Includes federal and state jurisdictions.
|
(In millions)
|
2017
|
|
2016
|
|
2015
|
||||||
Beginning balance
|
$
|
66
|
|
|
$
|
65
|
|
|
$
|
80
|
|
Additions for tax positions of prior years
|
83
|
|
|
6
|
|
|
1
|
|
|||
Reductions for tax positions of prior years
|
(3
|
)
|
|
(5
|
)
|
|
—
|
|
|||
Settlements
|
(20
|
)
|
|
—
|
|
|
(7
|
)
|
|||
Statute of limitations
|
—
|
|
|
—
|
|
|
(9
|
)
|
|||
Ending balance
|
$
|
126
|
|
|
$
|
66
|
|
|
$
|
65
|
|
|
December 31,
|
||||||
(In millions)
|
2017
|
|
2016
|
||||
Crude oil and natural gas
|
$
|
9
|
|
|
$
|
6
|
|
Supplies and other items
|
117
|
|
|
130
|
|
||
Inventories
|
$
|
126
|
|
|
$
|
136
|
|
|
December 31,
|
||||||
(In millions)
|
2017
|
|
2016
|
||||
United States E&P
|
$
|
15,867
|
|
|
$
|
14,158
|
|
International E&P
|
1,710
|
|
|
2,470
|
|
||
Corporate
|
88
|
|
|
99
|
|
||
Net property, plant and equipment
|
$
|
17,665
|
|
|
$
|
16,727
|
|
|
December 31,
|
||||||||||
(In millions)
|
2017
|
|
2016
|
|
2015
|
||||||
Amounts capitalized less than one year after completion of drilling
|
$
|
263
|
|
|
$
|
131
|
|
|
$
|
352
|
|
Amounts capitalized greater than one year after completion of drilling
|
32
|
|
|
118
|
|
|
85
|
|
|||
Total deferred exploratory well costs
|
$
|
295
|
|
|
$
|
249
|
|
|
$
|
437
|
|
Number of projects with costs capitalized greater than one year after
|
|
|
|
|
|
||||||
completion of drilling
|
1
|
|
|
3
|
|
|
2
|
|
|||
|
|
||||||||||
|
|
|
|
|
|
||||||
(In millions)
|
2017
|
|
2016
|
|
2015
|
||||||
Beginning balance
|
$
|
249
|
|
|
$
|
437
|
|
|
$
|
573
|
|
Additions
|
212
|
|
|
299
|
|
|
610
|
|
|||
Charges to expense
(a)
|
(64
|
)
|
|
(23
|
)
|
|
(111
|
)
|
|||
Transfers to development
|
(102
|
)
|
|
(388
|
)
|
|
(635
|
)
|
|||
Dispositions
(b)
|
—
|
|
|
(76
|
)
|
|
—
|
|
|||
Ending balance
|
$
|
295
|
|
|
$
|
249
|
|
|
$
|
437
|
|
(a)
|
Includes
$64 million
in exploratory well costs being expensed as a result of our agreement to sell Diaba License G4-223 in the Republic of Gabon in August of 2017. See Note 10 for further detail.
|
(b)
|
Includes sale of GOM assets in 2016.
|
|
Year Ended December 31,
|
||||||||||
(in millions)
|
2017
|
|
2016
|
|
2015
|
||||||
Total impairments
|
$
|
229
|
|
|
$
|
67
|
|
|
$
|
721
|
|
•
|
2017
-
Impairments were primarily a result of lower forecasted long-term commodity prices and the anticipated sales of certain non-core proved properties in our International E&P segment of
$136 million
. Additionally, included in proved property impairments was
$89 million
relating to the Gulf of Mexico and certain conventional Oklahoma assets primarily as a result of lower forecasted long-term commodity prices.
|
•
|
2016
-
Impairments of
$67 million
consisted primarily of proved properties in Oklahoma and the Gulf of Mexico as a result of lower forecasted commodity prices and revisions to estimated abandonment costs.
|
•
|
2015
- Impairments included
$340 million
for the goodwill impairment of the United States E&P reporting unit, and
$335 million
related to proved properties (primarily in Colorado and the Gulf of Mexico) as a result of lower forecasted commodity prices, and
$44 million
associated with our disposition of natural gas assets in East Texas, North Louisiana and Wilburton, Oklahoma.
|
|
Year Ended December 31,
|
||||||||||
(In millions)
|
2017
|
|
2016
|
|
2015
|
||||||
Exploration Expenses
|
|
|
|
|
|
||||||
Unproved property impairments
|
$
|
246
|
|
|
$
|
195
|
|
|
$
|
655
|
|
Dry well costs
|
77
|
|
|
25
|
|
|
212
|
|
|||
Geological and geophysical
|
25
|
|
|
5
|
|
|
31
|
|
|||
Other
|
61
|
|
|
98
|
|
|
73
|
|
|||
Total exploration expenses
|
$
|
409
|
|
|
$
|
323
|
|
|
$
|
971
|
|
•
|
2017
-
As a result of lower forecasted long-term commodity prices and the anticipated sales of certain non-core properties in our International E&P segment, we recorded a non-cash charge of
$159 million
comprised of
$95 million
in unproved property impairments; and
$64 million
in dry well costs related to our Diaba License G4-223 in the Republic of Gabon. Also, because of our decision not to develop the Tchicuate offshore Block in the Republic of Gabon, we recorded a non-cash impairment charge of
$43 million
to unproved property.
|
•
|
2016
- Unproved property impairments recorded of
$195 million
were primarily a result of our decision to not drill any of our remaining Gulf of Mexico undeveloped leases and also includes certain other unproved properties in the United States. Lower dry well expense was a result of the strategic decision to transition out of our conventional exploration program during 2015.
|
•
|
2015
-
Primarily due to changes in our conventional exploration strategy (Gulf of Mexico, Canadian in-situ assets and Harir block in the Kurdistan Region of Iraq), relinquishment of certain properties in the Gulf of Mexico, the operated Solomon exploration well in the Gulf of Mexico and our unproved property in Colorado as a result of the proved property impairment mentioned above. Dry well costs include the operated Solomon exploration well in the Gulf of Mexico, and our operated Sodalita West #1 exploratory well in E.G.
|
|
For Year Ended December 31,
|
||||||
(In millions)
|
2017
|
|
2016
|
||||
Beginning balance
|
$
|
1,652
|
|
|
$
|
1,544
|
|
Incurred liabilities, including acquisitions
|
25
|
|
|
14
|
|
||
Settled liabilities, including dispositions
|
(50
|
)
|
|
(74
|
)
|
||
Accretion expense (included in depreciation, depletion and amortization)
|
85
|
|
|
79
|
|
||
Revisions of estimates
|
(227
|
)
|
|
96
|
|
||
Held for sale
|
(2
|
)
|
|
(7
|
)
|
||
Ending balance
|
$
|
1,483
|
|
|
$
|
1,652
|
|
•
|
Settled liabilities
include dispositions, primarily related to the sale of certain conventional assets in Oklahoma as well as retirements in the U.K. and the Gulf of Mexico.
|
•
|
Revisions of estimates
were primarily due to changes in U.K. estimated costs as well as timing of abandonment activities in the U.K.
|
•
|
Ending balance
includes
$55 million
classified as short-term at
December 31, 2017
.
|
•
|
Settled liabilities
include dispositions, primarily related to the Gulf of Mexico and Wyoming as well as retirements in the Gulf of Mexico.
|
•
|
Revisions of estimates
were primarily due to changes in timing of abandonment activities as well as changes in cost estimated in the U.K.
|
•
|
Ending balance
includes
$50 million
classified as short-term at
December 31, 2016
.
|
(In millions)
|
U.S. E&P
|
|
Int'l E&P
|
|
Total
|
||||||
2016
|
|
|
|
|
|
||||||
Beginning balance, gross
|
$
|
—
|
|
|
$
|
115
|
|
|
$
|
115
|
|
Less: accumulated impairments
|
—
|
|
|
—
|
|
|
—
|
|
|||
Beginning balance, net
|
—
|
|
|
115
|
|
|
115
|
|
|||
Dispositions
|
—
|
|
|
—
|
|
|
—
|
|
|||
Impairment
|
—
|
|
|
—
|
|
|
—
|
|
|||
Ending balance, net
|
$
|
—
|
|
|
$
|
115
|
|
|
$
|
115
|
|
2017
|
|
|
|
|
|
||||||
Beginning balance, gross
|
$
|
—
|
|
|
$
|
115
|
|
|
$
|
115
|
|
Less: accumulated impairments
|
—
|
|
|
—
|
|
|
—
|
|
|||
Beginning balance, net
|
—
|
|
|
115
|
|
|
115
|
|
|||
Dispositions
|
—
|
|
|
—
|
|
|
—
|
|
|||
Impairment
|
—
|
|
|
—
|
|
|
—
|
|
|||
Ending balance, net
|
$
|
—
|
|
|
$
|
115
|
|
|
$
|
115
|
|
|
December 31, 2017
|
|
|
||||||||||
(In millions)
|
Asset
|
|
Liability
|
|
Net Asset
|
|
Balance Sheet Location
|
||||||
Not Designated as Hedges
|
|
|
|
|
|
|
|
||||||
Commodity
|
$
|
—
|
|
|
$
|
138
|
|
|
$
|
(138
|
)
|
|
Other current liabilities
|
Commodity
|
—
|
|
|
2
|
|
|
(2
|
)
|
|
Deferred credits and other liabilities
|
|||
Total Not Designated as Hedges
|
$
|
—
|
|
|
$
|
140
|
|
|
$
|
(140
|
)
|
|
|
Total
|
$
|
—
|
|
|
$
|
140
|
|
|
$
|
(140
|
)
|
|
|
|
December 31, 2016
|
|
|
||||||||||
(In millions)
|
Asset
|
|
Liability
|
|
Net Asset
|
|
Balance Sheet Location
|
||||||
Fair Value Hedges
|
|
|
|
|
|
|
|
||||||
Interest rate
|
$
|
3
|
|
|
$
|
—
|
|
|
$
|
3
|
|
|
Other current assets
|
Interest rate
|
1
|
|
|
—
|
|
|
1
|
|
|
Other noncurrent assets
|
|||
Cash Flow Hedges
|
|
|
|
|
|
|
|
||||||
Interest rate
|
$
|
64
|
|
|
$
|
—
|
|
|
$
|
64
|
|
|
Other noncurrent assets
|
Total Designated Hedges
|
$
|
68
|
|
|
$
|
—
|
|
|
$
|
68
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Not Designated as Hedges
|
|
|
|
|
|
|
|
||||||
Commodity
|
$
|
—
|
|
|
$
|
60
|
|
|
$
|
(60
|
)
|
|
Other current liabilities
|
Total Not Designated as Hedges
|
$
|
—
|
|
|
$
|
60
|
|
|
$
|
(60
|
)
|
|
|
Total
|
$
|
68
|
|
|
$
|
60
|
|
|
$
|
8
|
|
|
|
|
December 31, 2017
|
|
December 31, 2016
|
||||||||
|
Aggregate Notional Amount
|
Weighted Average, LIBOR-Based,
|
|
Aggregate Notional Amount
|
Weighted Average, LIBOR-Based,
|
||||||
Maturity Dates
|
(in millions)
|
Floating Rate
|
|
(in millions)
|
Floating Rate
|
||||||
October 1, 2017
|
$
|
—
|
|
—
|
%
|
|
$
|
600
|
|
5.10
|
%
|
March 15, 2018
|
$
|
—
|
|
—
|
%
|
|
$
|
300
|
|
5.04
|
%
|
|
|
Gain (Loss)
|
||||||||||
|
|
Year Ended December 31,
|
||||||||||
(In millions)
|
Income Statement Location
|
2017
|
|
2016
|
|
2015
|
||||||
Derivative
|
|
|
|
|
|
|
||||||
Interest rate
|
Net interest and other
|
$
|
—
|
|
|
$
|
(4
|
)
|
|
$
|
—
|
|
Hedged Item
|
|
|
|
|
|
|
|
|
||||
Debt
|
Net interest and other
|
$
|
—
|
|
|
$
|
4
|
|
|
$
|
—
|
|
|
December 31, 2017
|
|
December 31, 2016
|
||||||||
|
Aggregate Notional Amount
|
Weighted Average, LIBOR
|
|
Aggregate Notional Amount
|
Weighted Average, LIBOR
|
||||||
Maturity Dates
|
(in millions)
|
Fixed Rate
|
|
(in millions)
|
Fixed Rate
|
||||||
March 15, 2018
|
$
|
—
|
|
—
|
%
|
|
$
|
750
|
|
1.57
|
%
|
|
|
Year Ended December 31,
|
||||||||||
(In millions)
|
|
2017
|
|
2016
|
|
2015
|
||||||
Interest Rate Swaps
|
|
|
|
|
|
|
||||||
Beginning balance
|
|
$
|
60
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Change in fair value recognized in other comprehensive income
|
|
(13
|
)
|
|
64
|
|
|
—
|
|
|||
Reclassification from other comprehensive income
|
|
(47
|
)
|
|
(4
|
)
|
|
—
|
|
|||
Ending balance
|
|
$
|
—
|
|
|
$
|
60
|
|
|
$
|
—
|
|
Crude Oil
|
|||||||||||
|
2018
|
|
2019
|
||||||||
|
First Quarter
|
|
Second Quarter
|
|
Third Quarter
|
|
Fourth Quarter
|
|
First Quarter
|
|
Second Quarter
|
Three-Way Collars
(a)
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbls/day)
|
85,000
|
|
85,000
|
|
85,000
|
|
85,000
|
|
10,000
|
|
10,000
|
Weighted average price per Bbl:
|
|
|
|
|
|
|
|
|
|
|
|
Ceiling
|
$56.38
|
|
$56.38
|
|
$56.96
|
|
$56.96
|
|
$60.00
|
|
$60.00
|
Floor
|
$51.65
|
|
$51.65
|
|
$51.53
|
|
$51.53
|
|
$55.00
|
|
$55.00
|
Sold put
|
$45.00
|
|
$45.00
|
|
$44.65
|
|
$44.65
|
|
$47.00
|
|
$47.00
|
Swaps
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbls/day)
|
20,000
|
|
20,000
|
|
—
|
|
—
|
|
—
|
|
—
|
Weighted average price per Bbl
|
$55.12
|
|
$55.12
|
|
$—
|
|
$—
|
|
$—
|
|
$—
|
Basis Swaps
(b)
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbls/day)
|
5,000
|
|
5,000
|
|
10,000
|
|
10,000
|
|
—
|
|
—
|
Weighted average price per Bbl
|
$(0.60)
|
|
$(0.60)
|
|
$(0.67)
|
|
$(0.67)
|
|
$—
|
|
$—
|
(a)
|
Between January 1, 2018 and February 12, 2018, we entered into
10,000
Bbls/day of three-way collars for July - December 2018 with an average ceiling price of
$63.51
, a floor price of
$57.00
, and a sold put price of
$50.00
and
20,000
Bbls/day of three-way collars for January - June 2019 with an average ceiling price of
$67.92
, a floor price of
$53.50
, and a sold put price of
$46.50
.
|
(b)
|
The basis differential price is between WTI Midland and WTI Cushing.
|
Natural Gas
|
||||
|
2018
|
|||
|
First Quarter
|
Second Quarter
|
Third Quarter
|
Fourth Quarter
|
Three-Way Collars
|
|
|
|
|
Volume (MMBtu/day)
|
200,000
|
160,000
|
160,000
|
160,000
|
Weighted average price per MMBtu
|
|
|
|
|
Ceiling
|
$3.79
|
$3.61
|
$3.61
|
$3.61
|
Floor
|
$3.08
|
$3.00
|
$3.00
|
$3.00
|
Sold put
|
$2.55
|
$2.50
|
$2.50
|
$2.50
|
|
December 31, 2017
|
||||||||||||||
(In millions)
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
Derivative instruments, assets
|
|
|
|
|
|
|
|
||||||||
Interest rate
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Derivative instruments, assets
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Derivative instruments, liabilities
|
|
|
|
|
|
|
|
||||||||
Commodity
(a)
|
$
|
(20
|
)
|
|
$
|
(120
|
)
|
|
$
|
—
|
|
|
$
|
(140
|
)
|
Derivative instruments, liabilities
|
$
|
(20
|
)
|
|
$
|
(120
|
)
|
|
$
|
—
|
|
|
$
|
(140
|
)
|
|
|
|
|
|
|
|
|
||||||||
|
December 31, 2016
|
||||||||||||||
(In millions)
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
Derivative instruments, assets
|
|
|
|
|
|
|
|
||||||||
Interest rate
|
$
|
—
|
|
|
$
|
68
|
|
|
$
|
—
|
|
|
$
|
68
|
|
Derivative instruments, assets
|
$
|
—
|
|
|
$
|
68
|
|
|
$
|
—
|
|
|
$
|
68
|
|
Derivative instruments, liabilities
|
|
|
|
|
|
|
|
||||||||
Commodity
(a)
|
$
|
—
|
|
|
$
|
60
|
|
|
$
|
—
|
|
|
$
|
60
|
|
Derivative instruments, liabilities
|
$
|
—
|
|
|
$
|
60
|
|
|
$
|
—
|
|
|
$
|
60
|
|
|
2017
|
|
2016
|
|
2015
|
||||||||||||||||||
(In millions)
|
Fair Value
|
|
Impairment
|
|
Fair Value
|
|
Impairment
|
|
Fair Value
|
|
Impairment
|
||||||||||||
Long-lived assets held for use
|
$
|
179
|
|
|
$
|
229
|
|
|
$
|
15
|
|
|
$
|
67
|
|
|
$
|
56
|
|
|
$
|
386
|
|
|
December 31,
|
||||||||||||||
|
2017
|
|
2016
|
||||||||||||
(In millions)
|
Fair
Value
|
|
Carrying
Amount
|
|
Fair
Value
|
|
Carrying
Amount
|
||||||||
Financial assets
|
|
|
|
|
|
|
|
||||||||
Other current assets
(a)
|
$
|
762
|
|
|
$
|
761
|
|
|
$
|
7
|
|
|
$
|
7
|
|
Other noncurrent assets
|
159
|
|
|
161
|
|
|
105
|
|
|
108
|
|
||||
Total financial assets
|
$
|
921
|
|
|
$
|
922
|
|
|
$
|
112
|
|
|
$
|
115
|
|
Financial liabilities
|
|
|
|
|
|
|
|
||||||||
Other current liabilities
|
$
|
32
|
|
|
$
|
43
|
|
|
$
|
68
|
|
|
$
|
75
|
|
Long-term debt, including current portion
(b)
|
5,976
|
|
|
5,526
|
|
|
7,449
|
|
|
7,292
|
|
||||
Deferred credits and other liabilities
|
110
|
|
|
103
|
|
|
114
|
|
|
107
|
|
||||
Total financial liabilities
|
$
|
6,118
|
|
|
$
|
5,672
|
|
|
$
|
7,631
|
|
|
$
|
7,474
|
|
(a)
|
Includes our
two
notes receivable relating to the sale of our Canadian business as of December 31, 2017, see note
5
for further information.
|
(b)
|
Excludes capital leases, debt issuance costs and historical interest rate swap adjustments.
|
|
December 31,
|
||||||
(In millions)
|
2017
|
|
2016
|
||||
Senior unsecured notes:
|
|
|
|
||||
6.000% notes due 2017
|
—
|
|
|
682
|
|
||
5.900% notes due 2018
|
—
|
|
|
854
|
|
||
7.500% notes due 2019
|
—
|
|
|
228
|
|
||
2.700% notes due 2020
(a)
|
600
|
|
|
600
|
|
||
2.800% notes due 2022
(a)
|
1,000
|
|
|
1,000
|
|
||
9.375% notes due 2022
(b)
|
32
|
|
|
32
|
|
||
Series A notes due 2022
(b)
|
3
|
|
|
3
|
|
||
8.500% notes due 2023
(b)
|
70
|
|
|
70
|
|
||
8.125% notes due 2023
(b)
|
131
|
|
|
131
|
|
||
3.850% notes due 2025
(a)
|
900
|
|
|
900
|
|
||
4.400% notes due 2027
(a)
|
1,000
|
|
|
—
|
|
||
6.800% notes due 2032
(a)
|
550
|
|
|
550
|
|
||
6.600% notes due 2037
(a)
|
750
|
|
|
750
|
|
||
5.200% notes due 2045
(a)
|
500
|
|
|
500
|
|
||
Capital leases:
|
|
|
|
||||
Capital lease obligation expiring in 2018
|
—
|
|
|
1
|
|
||
Other obligations:
|
|
|
|
||||
5.125% obligation relating to revenue bonds due 2037
|
—
|
|
|
1,000
|
|
||
Total
(b)
|
5,536
|
|
|
7,301
|
|
||
Unamortized discount
|
(10
|
)
|
|
(9
|
)
|
||
Fair value adjustments
(c)
|
—
|
|
|
7
|
|
||
Unamortized debt issuance cost
|
(32
|
)
|
|
(35
|
)
|
||
Amounts due within one year
|
—
|
|
|
(683
|
)
|
||
Total long-term debt
|
$
|
5,494
|
|
|
$
|
6,581
|
|
(a)
|
These notes contain a make-whole provision allowing us to repay the debt at a premium to market price.
|
(b)
|
In the event of a change in control, as defined in the related agreements, debt obligations totaling
$236 million
at
December 31, 2017
may be declared immediately due and payable.
|
(c)
|
See Notes
13
and
14
for information on historical interest rate swaps.
|
•
|
$682 million
6.0%
Notes Due in 2017
|
•
|
$854 million
5.9%
Notes Due in 2018
|
•
|
$228 million
7.5%
Notes Due in 2019
|
|
2017
|
|
2016
|
|
2015
|
|||
Exercise price per share
|
$15.80
|
|
$7.22
|
|
$29.06
|
|||
Expected annual dividend yield
|
1.3
|
%
|
|
2.8
|
%
|
|
2.9
|
%
|
Expected life in years
|
6.4
|
|
|
6.3
|
|
|
6.2
|
|
Expected volatility
|
42
|
%
|
|
36
|
%
|
|
32
|
%
|
Risk-free interest rate
|
2.1
|
%
|
|
1.4
|
%
|
|
1.7
|
%
|
Weighted average grant date fair value of stock option awards granted
|
$6.07
|
|
$1.97
|
|
$6.84
|
|
Number
|
|
Weighted Average
|
|
Weighted Average
Remaining
|
|
Aggregate Intrinsic Value
|
|||
|
of Shares
|
|
Exercise Price
|
|
Contractual Term
|
|
(in millions)
|
|||
Outstanding at beginning of year
|
11,915,533
|
|
$27.71
|
|
|
|
|
|||
Granted
|
799,591
|
|
$15.80
|
|
|
|
|
|||
Exercised
|
(8,666)
|
|
$7.22
|
|
|
|
|
|||
Canceled
|
(2,375,682)
|
|
$33.31
|
|
|
|
|
|||
Outstanding at end of year
|
10,330,776
|
|
$25.52
|
|
4 years
|
|
$
|
13
|
|
|
Exercisable at end of year
|
8,661,893
|
|
|
$27.91
|
|
3 years
|
|
$
|
5
|
|
Expected to vest
|
1,650,737
|
|
|
$13.08
|
|
9 years
|
|
$
|
8
|
|
|
Awards
|
|
Weighted Average
Grant Date
Fair Value
|
|
Unvested at beginning of year
|
6,933,533
|
|
|
$14.44
|
Granted
|
4,198,624
|
|
|
$16.13
|
Vested & Exercised
|
(2,472,367
|
)
|
|
$17.67
|
Canceled
|
(1,086,945
|
)
|
|
$15.03
|
Unvested at end of year
|
7,572,845
|
|
|
$14.24
|
|
2017
|
|
2016
|
|
2015
(a)
|
|||
Valuation date stock price
|
$16.93
|
|
$16.93
|
|
$16.93
|
|||
Expected annual dividend yield
|
1.2
|
%
|
|
1.2
|
%
|
|
1.2
|
%
|
Expected volatility
|
54
|
%
|
|
34
|
%
|
|
33
|
%
|
Risk-free interest rate
|
1.9
|
%
|
|
1.7
|
%
|
|
1.4
|
%
|
Fair value of stock-based performance units outstanding
|
$21.63
|
|
$19.86
|
|
$0.00
|
|
Pension Benefits
|
|
Other Benefits
|
||||||||||||||||||||
|
2017
|
|
2016
|
|
2017
|
|
2016
|
||||||||||||||||
(In millions)
|
U.S.
|
|
Int’l
|
|
U.S.
|
|
Int’l
|
|
U.S.
|
|
U.S.
|
||||||||||||
Accumulated benefit obligation
|
378
|
|
|
599
|
|
|
386
|
|
|
583
|
|
|
221
|
|
227
|
||||||||
Change in benefit obligations:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Beginning balance
|
$
|
397
|
|
|
$
|
583
|
|
|
$
|
525
|
|
|
$
|
579
|
|
|
$
|
227
|
|
|
$
|
260
|
|
Service cost
|
22
|
|
|
—
|
|
|
25
|
|
|
—
|
|
|
2
|
|
|
2
|
|
||||||
Interest cost
|
13
|
|
|
17
|
|
|
16
|
|
|
23
|
|
|
8
|
|
|
11
|
|
||||||
Plan amendment
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
(38
|
)
|
||||||
Actuarial loss (gain)
|
42
|
|
|
(7
|
)
|
|
78
|
|
|
139
|
|
|
5
|
|
|
11
|
|
||||||
Foreign currency exchange rate changes
|
—
|
|
|
52
|
|
|
—
|
|
|
(108
|
)
|
|
—
|
|
|
—
|
|
||||||
Divestiture
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Settlements paid
|
(84
|
)
|
|
(31
|
)
|
|
(240
|
)
|
|
(36
|
)
|
|
—
|
|
|
—
|
|
||||||
Benefits paid
|
(6
|
)
|
|
(15
|
)
|
|
(7
|
)
|
|
(15
|
)
|
|
(21
|
)
|
|
(19
|
)
|
||||||
Ending balance
|
$
|
384
|
|
|
$
|
599
|
|
|
$
|
397
|
|
|
$
|
583
|
|
|
$
|
221
|
|
|
$
|
227
|
|
Change in fair value of plan assets:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Beginning balance
|
$
|
227
|
|
|
$
|
595
|
|
|
$
|
354
|
|
|
$
|
608
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Actual return on plan assets
|
27
|
|
|
47
|
|
|
25
|
|
|
129
|
|
|
—
|
|
|
—
|
|
||||||
Employer contributions
|
52
|
|
|
17
|
|
|
95
|
|
|
18
|
|
|
21
|
|
|
20
|
|
||||||
Foreign currency exchange rate changes
|
—
|
|
|
57
|
|
|
—
|
|
|
(109
|
)
|
|
—
|
|
|
—
|
|
||||||
Divestiture
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Settlements paid
|
(84
|
)
|
|
(31
|
)
|
|
(240
|
)
|
|
(36
|
)
|
|
—
|
|
|
—
|
|
||||||
Benefits paid
|
(6
|
)
|
|
(15
|
)
|
|
(7
|
)
|
|
(15
|
)
|
|
(21
|
)
|
|
(20
|
)
|
||||||
Ending balance
|
$
|
216
|
|
|
$
|
670
|
|
|
$
|
227
|
|
|
$
|
595
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Funded status of plans at December 31
|
$
|
(168
|
)
|
|
$
|
71
|
|
|
$
|
(170
|
)
|
|
$
|
12
|
|
|
$
|
(221
|
)
|
|
$
|
(227
|
)
|
Amounts recognized in the consolidated balance sheets:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Noncurrent assets
|
—
|
|
|
71
|
|
|
—
|
|
|
12
|
|
|
—
|
|
|
—
|
|
||||||
Current liabilities
|
(6
|
)
|
|
—
|
|
|
(4
|
)
|
|
—
|
|
|
(21
|
)
|
|
(21
|
)
|
||||||
Noncurrent liabilities
|
(162
|
)
|
|
—
|
|
|
(166
|
)
|
|
—
|
|
|
(200
|
)
|
|
(206
|
)
|
||||||
Accrued benefit cost
|
$
|
(168
|
)
|
|
$
|
71
|
|
|
$
|
(170
|
)
|
|
$
|
12
|
|
|
$
|
(221
|
)
|
|
$
|
(227
|
)
|
Pretax amounts in accumulated other comprehensive loss:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net loss (gain)
|
$
|
122
|
|
|
$
|
58
|
|
|
$
|
130
|
|
|
$
|
81
|
|
|
$
|
30
|
|
|
$
|
25
|
|
Prior service cost (credit)
|
(45
|
)
|
|
3
|
|
|
(55
|
)
|
|
4
|
|
|
(56
|
)
|
|
(63
|
)
|
|
Pension Benefits
|
|
Other Benefits
|
||||||||||||||||||||||||||||||||
|
Year Ended December 31,
|
|
Year Ended December 31,
|
||||||||||||||||||||||||||||||||
|
2017
|
|
2016
|
|
2015
|
|
2017
|
|
2016
|
|
2015
|
||||||||||||||||||||||||
(In millions)
|
U.S.
|
|
Int’l
|
|
U.S.
|
|
Int’l
|
|
U.S.
|
|
Int’l
|
|
U.S.
|
|
U.S.
|
|
U.S.
|
||||||||||||||||||
Components of net periodic benefit cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||
Service cost
|
$
|
22
|
|
|
$
|
—
|
|
|
$
|
25
|
|
|
$
|
—
|
|
|
$
|
29
|
|
|
$
|
14
|
|
|
$
|
2
|
|
|
$
|
2
|
|
|
$
|
3
|
|
Interest cost
|
13
|
|
|
17
|
|
|
16
|
|
|
23
|
|
|
25
|
|
|
25
|
|
|
8
|
|
|
11
|
|
|
11
|
|
|||||||||
Expected return on plan assets
|
(13
|
)
|
|
(30
|
)
|
|
(18
|
)
|
|
(35
|
)
|
|
(30
|
)
|
|
(37
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Amortization:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||
- prior service cost (credit)
|
(10
|
)
|
|
—
|
|
|
(10
|
)
|
|
1
|
|
|
(7
|
)
|
|
1
|
|
|
(7
|
)
|
|
(3
|
)
|
|
(4
|
)
|
|||||||||
- actuarial loss
|
8
|
|
|
1
|
|
|
14
|
|
|
—
|
|
|
22
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|||||||||
Net curtailment loss (gain)
(a)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(5
|
)
|
|
4
|
|
|
—
|
|
|
—
|
|
|
(7
|
)
|
|||||||||
Net settlement loss
(b)
|
28
|
|
|
4
|
|
|
97
|
|
|
6
|
|
|
119
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Net periodic benefit cost
(c)
|
$
|
48
|
|
|
$
|
(8
|
)
|
|
$
|
124
|
|
|
$
|
(5
|
)
|
|
$
|
153
|
|
|
$
|
9
|
|
|
$
|
3
|
|
|
$
|
10
|
|
|
$
|
4
|
|
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss (pretax):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||
Actuarial loss (gain)
|
$
|
28
|
|
|
$
|
(26
|
)
|
|
$
|
70
|
|
|
$
|
41
|
|
|
$
|
30
|
|
|
$
|
(25
|
)
|
|
$
|
5
|
|
|
$
|
11
|
|
|
$
|
(21
|
)
|
Amortization of actuarial gain (loss)
|
(36
|
)
|
|
(4
|
)
|
|
(111
|
)
|
|
(6
|
)
|
|
(134
|
)
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|||||||||
Prior service cost (credit)
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
(89
|
)
|
|
1
|
|
|
—
|
|
|
(38
|
)
|
|
—
|
|
|||||||||
Amortization of prior service credit (cost)
|
10
|
|
|
—
|
|
|
10
|
|
|
(1
|
)
|
|
7
|
|
|
(5
|
)
|
|
7
|
|
|
3
|
|
|
13
|
|
|||||||||
Total recognized in other comprehensive (income) loss
|
$
|
2
|
|
|
$
|
(30
|
)
|
|
$
|
(31
|
)
|
|
$
|
35
|
|
|
$
|
(186
|
)
|
|
$
|
(31
|
)
|
|
$
|
12
|
|
|
$
|
(24
|
)
|
|
$
|
(9
|
)
|
Total recognized in net periodic benefit cost and other comprehensive (income) loss
|
$
|
50
|
|
|
$
|
(38
|
)
|
|
$
|
93
|
|
|
$
|
30
|
|
|
$
|
(33
|
)
|
|
$
|
(22
|
)
|
|
$
|
15
|
|
|
$
|
(14
|
)
|
|
$
|
(5
|
)
|
(a)
|
Related to workforce reductions, which reduced the future expected years of service for employees participating in the plans and the impact of discontinuing accruals for future benefits under the U.K. pension plan effective December 31, 2015.
|
(b)
|
Settlement losses are recorded when lump sum payments from a plan in a period exceed the plan’s total service and interest costs for the period.
|
(c)
|
Net periodic benefit cost reflects a calculated market-related value of plan assets which recognizes changes in fair value over three years.
|
|
Pension Benefits
|
|
Other Benefits
|
|||||||||||||||||||||||
|
2017
|
|
2016
|
|
2015
|
|
2017
|
|
2016
|
|
2015
|
|||||||||||||||
(In millions)
|
U.S.
|
|
Int’l
|
|
U.S.
|
|
Int’l
|
|
U.S.
|
|
Int’l
|
|
U.S.
|
|
U.S.
|
|
U.S.
|
|||||||||
Weighted average assumptions used to determine benefit obligation:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Discount rate
|
3.55
|
%
|
|
2.50
|
%
|
|
4.02
|
%
|
|
2.70
|
%
|
|
4.04
|
%
|
|
3.90
|
%
|
|
3.54
|
%
|
|
3.98
|
%
|
|
4.36
|
%
|
Rate of compensation increase
(a)
|
4.00
|
%
|
|
—
|
|
|
4.00
|
%
|
|
—
|
|
|
4.00
|
%
|
|
—
|
|
|
4.00
|
%
|
|
4.00
|
%
|
|
4.00
|
%
|
Weighted average assumptions used to determine net periodic benefit cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Discount rate
|
3.86
|
%
|
|
2.70
|
%
|
|
3.66
|
%
|
|
3.90
|
%
|
|
3.79
|
%
|
|
3.70
|
%
|
|
3.98
|
%
|
|
4.36
|
%
|
|
3.93
|
%
|
Expected long-term return on plan assets
|
6.50
|
%
|
|
4.50
|
%
|
|
6.75
|
%
|
|
5.50
|
%
|
|
6.75
|
%
|
|
5.70
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
Rate of compensation increase
(a)
|
4.00
|
%
|
|
—
|
|
|
4.00
|
%
|
|
—
|
%
|
|
4.00
|
%
|
|
3.60
|
%
|
|
4.00
|
%
|
|
4.00
|
%
|
|
4.00
|
%
|
(a)
|
No future benefits will be incurred for the U.K. plan after December 31, 2015. Therefore, rate of compensation increase is no longer applicable to this plan.
|
|
December 31, 2017
|
||||||||||||||||||||||||||||||
(In millions)
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||||||||||||||||||
|
U.S.
|
|
Int’l
|
|
U.S.
|
|
Int’l
|
|
U.S.
|
|
Int’l
|
|
U.S.
|
|
Int’l
|
||||||||||||||||
Cash and cash equivalents
|
$
|
6
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
6
|
|
|
$
|
1
|
|
Equity securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Common stock
|
81
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
81
|
|
|
—
|
|
||||||||
Private equity
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
16
|
|
|
—
|
|
|
16
|
|
|
—
|
|
||||||||
Mutual and pooled funds
|
—
|
|
|
151
|
|
|
—
|
|
|
115
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
266
|
|
||||||||
Fixed income securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Corporate
|
—
|
|
|
—
|
|
|
6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6
|
|
|
—
|
|
||||||||
Exchange traded funds
|
5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|
—
|
|
||||||||
Government
|
19
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
3
|
|
|
—
|
|
|
24
|
|
|
—
|
|
||||||||
Pooled funds
|
—
|
|
|
—
|
|
|
—
|
|
|
403
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
403
|
|
||||||||
Other
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
19
|
|
|
—
|
|
|
19
|
|
|
—
|
|
||||||||
Total investments, at fair value
|
111
|
|
|
152
|
|
|
8
|
|
|
518
|
|
|
38
|
|
|
—
|
|
|
157
|
|
|
670
|
|
||||||||
Commingled funds
(a)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
59
|
|
|
—
|
|
||||||||
Total investments
|
$
|
111
|
|
|
$
|
152
|
|
|
$
|
8
|
|
|
$
|
518
|
|
|
$
|
38
|
|
|
$
|
—
|
|
|
$
|
216
|
|
|
$
|
670
|
|
|
December 31, 2016
|
||||||||||||||||||||||||||||||
(In millions)
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||||||||||||||||||
|
U.S.
|
|
Int’l
|
|
U.S.
|
|
Int’l
|
|
U.S.
|
|
Int’l
|
|
U.S.
|
|
Int’l
|
||||||||||||||||
Cash and cash equivalents
|
$
|
8
|
|
|
$
|
5
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
8
|
|
|
$
|
5
|
|
Equity securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Common stock
|
82
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
82
|
|
|
—
|
|
||||||||
Private equity
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
20
|
|
|
—
|
|
|
20
|
|
|
—
|
|
||||||||
Mutual and pooled funds
|
—
|
|
|
201
|
|
|
—
|
|
|
159
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
360
|
|
||||||||
Fixed income securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Corporate
|
—
|
|
|
—
|
|
|
52
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
52
|
|
|
—
|
|
||||||||
Exchange traded funds
|
5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|
—
|
|
||||||||
Government
|
6
|
|
|
—
|
|
|
19
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
25
|
|
|
—
|
|
||||||||
Pooled funds
|
—
|
|
|
—
|
|
|
—
|
|
|
230
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
230
|
|
||||||||
Other
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
21
|
|
|
—
|
|
|
21
|
|
|
—
|
|
||||||||
Total investments, at fair value
|
101
|
|
|
206
|
|
|
71
|
|
|
389
|
|
|
41
|
|
|
—
|
|
|
213
|
|
|
595
|
|
||||||||
Commingled funds
(a)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
14
|
|
|
—
|
|
||||||||
Total investments
|
$
|
101
|
|
|
$
|
206
|
|
|
$
|
71
|
|
|
$
|
389
|
|
|
$
|
41
|
|
|
$
|
—
|
|
|
$
|
227
|
|
|
$
|
595
|
|
(a)
|
After the adoption of the FASB update for the fair value hierarchy, we separately report the investments for which fair value was measured using the net asset value per share as a practical expedient. Amounts presented in this table are intended to reconcile the fair value hierarchy to the pension plan assets. See Note 2 for further information on the FASB update.
|
|
Pension Benefits
|
|
Other Benefits
|
||||||||
(In millions)
|
U.S.
|
|
Int’l
|
|
U.S.
|
||||||
2018
|
$
|
43
|
|
|
$
|
17
|
|
|
$
|
21
|
|
2019
|
40
|
|
|
18
|
|
|
20
|
|
|||
2020
|
37
|
|
|
17
|
|
|
20
|
|
|||
2021
|
33
|
|
|
19
|
|
|
19
|
|
|||
2022
|
30
|
|
|
21
|
|
|
18
|
|
|||
2023 through 2027
|
123
|
|
|
118
|
|
|
74
|
|
|
Year Ended December 31,
|
|
|
||||||
(In millions)
|
2017
|
|
2016
|
|
Income Statement Line
|
||||
Postretirement and postemployment plans
|
|
|
|
|
|
||||
Amortization of actuarial loss
|
$
|
(9
|
)
|
|
$
|
(14
|
)
|
|
General and administrative
|
Net settlement loss
|
(32
|
)
|
|
(103
|
)
|
|
General and administrative
|
||
Derivative hedges
|
|
|
|
|
|
||||
Recognized gain on terminated derivative hedge
|
46
|
|
|
—
|
|
|
Net interest and other
|
||
Ineffective portion of derivative hedge
|
1
|
|
|
4
|
|
|
Net interest and other
|
||
|
6
|
|
|
(113
|
)
|
|
Income (loss) from operations
|
||
|
(40
|
)
|
|
41
|
|
|
(Provision) benefit for income taxes
|
||
Total reclassifications to expense, net of tax
|
$
|
(34
|
)
|
|
$
|
(72
|
)
|
|
Income (loss) from continuing operations
|
Foreign currency hedges
|
|
|
|
|
|
||||
Net recognized loss in discontinued operations, net of tax
|
(30
|
)
|
|
—
|
|
|
Income (loss) from discontinued operations
|
||
Total reclassifications to expense
|
$
|
(64
|
)
|
|
$
|
(72
|
)
|
|
|
|
Year Ended December 31,
|
||||||||||
(In millions)
|
2017
|
|
2016
|
|
2015
|
||||||
Net cash used in operating activities:
|
|
|
|
|
|
||||||
Interest paid (net of amounts capitalized)
|
$
|
(379
|
)
|
|
$
|
(375
|
)
|
|
$
|
(325
|
)
|
Income taxes paid to taxing authorities
(a)
|
(391
|
)
|
|
(84
|
)
|
|
(171
|
)
|
|||
Noncash investing activities, related to continuing operations:
|
|
|
|
|
|
||||||
Changes in asset retirement costs
|
$
|
(202
|
)
|
|
$
|
110
|
|
|
$
|
(95
|
)
|
Asset retirement obligations assumed by buyer
|
14
|
|
|
40
|
|
|
251
|
|
|||
Increase in capital expenditure accrual
|
176
|
|
|
—
|
|
|
—
|
|
|||
Notes receivable for disposition of assets
|
748
|
|
|
—
|
|
|
—
|
|
|
Year Ended December 31,
|
||||||||||
(In millions)
|
2017
|
|
2016
|
|
2015
|
||||||
Interest:
|
|
|
|
|
|
||||||
Interest income
|
$
|
34
|
|
|
$
|
14
|
|
|
$
|
9
|
|
Interest expense
|
(380
|
)
|
|
(398
|
)
|
|
(350
|
)
|
|||
Income on interest rate swaps
|
53
|
|
|
13
|
|
|
11
|
|
|||
Interest capitalized
|
3
|
|
|
18
|
|
|
19
|
|
|||
Total interest
|
(290
|
)
|
|
(353
|
)
|
|
(311
|
)
|
|||
Other:
|
|
|
|
|
|
||||||
Net foreign currency gain (loss)
|
8
|
|
|
6
|
|
|
4
|
|
|||
Other
|
12
|
|
|
15
|
|
|
21
|
|
|||
Total other
|
20
|
|
|
21
|
|
|
25
|
|
|||
Net interest and other
|
$
|
(270
|
)
|
|
$
|
(332
|
)
|
|
$
|
(286
|
)
|
|
Year Ended December 31,
|
||||||||||
(In millions)
|
2017
|
|
2016
|
|
2015
|
||||||
Net interest and other
|
$
|
8
|
|
|
$
|
6
|
|
|
$
|
4
|
|
Provision for income taxes
|
57
|
|
|
(32
|
)
|
|
(11
|
)
|
|||
Aggregate foreign currency gains (losses)
|
$
|
65
|
|
|
$
|
(26
|
)
|
|
$
|
(7
|
)
|
•
|
EGHoldings, in which we have a
60%
noncontrolling interest. EGHoldings is engaged in LNG production activity.
|
•
|
AMPCO, in which we have a
45%
interest. AMPCO is engaged in methanol production activity.
|
|
Ownership as of
|
|
December 31,
|
||||||
(In millions)
|
December 31, 2017
|
|
2017
|
|
2016
|
||||
EGHoldings
|
60%
|
|
$
|
456
|
|
|
$
|
550
|
|
Alba Plant LLC
|
52%
|
|
214
|
|
|
215
|
|
||
AMPCO
|
45%
|
|
177
|
|
|
165
|
|
||
Other investments
|
|
|
—
|
|
|
1
|
|
||
Total
|
|
|
$
|
847
|
|
|
$
|
931
|
|
(In millions)
|
2017
|
|
2016
|
|
2015
|
||||||
Income data – year
(a)
:
|
|
|
|
|
|
||||||
Revenues and other income
|
$
|
1,294
|
|
|
$
|
770
|
|
|
$
|
769
|
|
Income from operations
|
631
|
|
|
346
|
|
|
313
|
|
|||
Net income
|
508
|
|
|
313
|
|
|
280
|
|
|||
Balance sheet data – December 31:
|
|
|
|
|
|
||||||
Current assets
|
$
|
586
|
|
|
$
|
525
|
|
|
|
||
Noncurrent assets
|
1,044
|
|
|
1,173
|
|
|
|
||||
Current liabilities
|
221
|
|
|
218
|
|
|
|
||||
Noncurrent liabilities
|
94
|
|
|
47
|
|
|
|
(a)
|
See Item 15 Exhibits, Financial Statement Schedules which contains the Alba Plant LLC audited financial statements, which have been included pursuant to Rule 3-09 of Regulation S-X.
|
(In millions)
|
Operating Lease Obligations
|
||
2018
|
$
|
29
|
|
2019
|
28
|
|
|
2020
|
27
|
|
|
2021
|
26
|
|
|
2022
|
5
|
|
|
Later years
|
4
|
|
|
Sublease rentals
|
—
|
|
|
Total minimum lease payments
|
$
|
119
|
|
|
2017
|
|
2016
|
||||||||||||||||||||||||||||
(In millions, except per share data)
|
1st Qtr.
|
|
2nd Qtr.
|
|
3rd Qtr.
|
|
4th Qtr.
|
|
1st Qtr.
|
|
2nd Qtr.
|
|
3rd Qtr.
|
|
4th Qtr.
|
||||||||||||||||
Revenues
|
$
|
988
|
|
|
$
|
993
|
|
|
$
|
1,162
|
|
|
$
|
1,230
|
|
|
$
|
612
|
|
|
$
|
761
|
|
|
$
|
861
|
|
|
$
|
936
|
|
Income (loss) from continuing operations before income taxes
(a)
|
(16
|
)
|
|
(112
|
)
|
|
(458
|
)
|
|
132
|
|
|
(613
|
)
|
|
(192
|
)
|
|
(313
|
)
|
|
(46
|
)
|
||||||||
Income (loss) from continuing operations
|
(50
|
)
|
|
(153
|
)
|
|
(599
|
)
|
|
(28
|
)
|
|
(360
|
)
|
|
(138
|
)
|
|
(206
|
)
|
|
(1,383
|
)
|
||||||||
Discontinued operations
(b)
|
(4,907
|
)
|
|
14
|
|
|
—
|
|
|
—
|
|
|
(47
|
)
|
|
(32
|
)
|
|
14
|
|
|
12
|
|
||||||||
Net income (loss)
(c)
|
$
|
(4,957
|
)
|
|
$
|
(139
|
)
|
|
$
|
(599
|
)
|
|
$
|
(28
|
)
|
|
$
|
(407
|
)
|
|
$
|
(170
|
)
|
|
$
|
(192
|
)
|
|
$
|
(1,371
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Income (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Continuing operations
|
$
|
(0.06
|
)
|
|
$
|
(0.18
|
)
|
|
$
|
(0.70
|
)
|
|
$
|
(0.03
|
)
|
|
$
|
(0.49
|
)
|
|
$
|
(0.16
|
)
|
|
$
|
(0.24
|
)
|
|
$
|
(1.63
|
)
|
Discontinued operations
(b)
|
$
|
(5.78
|
)
|
|
$
|
0.02
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(0.07
|
)
|
|
$
|
(0.04
|
)
|
|
$
|
0.01
|
|
|
$
|
0.01
|
|
Basic net income (loss)
|
$
|
(5.84
|
)
|
|
$
|
(0.16
|
)
|
|
$
|
(0.70
|
)
|
|
$
|
(0.03
|
)
|
|
$
|
(0.56
|
)
|
|
$
|
(0.20
|
)
|
|
$
|
(0.23
|
)
|
|
$
|
(1.62
|
)
|
Dividends paid per share
|
$
|
0.05
|
|
|
$
|
0.05
|
|
|
$
|
0.05
|
|
|
$
|
0.05
|
|
|
$
|
0.05
|
|
|
$
|
0.05
|
|
|
$
|
0.05
|
|
|
$
|
0.05
|
|
(a)
|
Includes impairments to proved properties of $24 million and $201 million in the fourth and third quarter of 2017 and $47 million in the third quarter of 2016. Also includes unproved property impairments and exploratory dry well costs of $215 million in the third quarter of 2017 and $118 million in the second quarter of 2016. (See Item 8. Financial Statements and Supplementary Data – Note 13 to the consolidated financial statements).
|
(b)
|
We closed on the sale of our Canadian business in the second quarter of 2017. The Canadian business is reflected as discontinued operations in all periods presented. Included in the first quarter of 2017 is an after-tax non-cash impairment charge of $4.96 billion, primarily related to the property, plant, and equipment.
|
(c)
|
Includes the increase of a valuation allowance on certain of our deferred tax assets for $1,346 million in the fourth quarter of 2016 (see Item 8. Financial Statements and Supplementary Data – Note 9 to the consolidated financial statements).
|
|
SEC Pricing 2017
|
||
WTI Crude oil (per bbl)
|
$
|
51.34
|
|
Henry Hub natural gas (per mmbtu)
|
$
|
2.98
|
|
Brent crude oil (per bbl)
|
$
|
54.39
|
|
Mont Belvieu NGLs (per bbl)
|
$
|
22.03
|
|
(mmbbl)
|
U.S.
|
|
E.G.
(a)
|
|
Libya
|
|
Other Int'l
|
|
Cont Ops
|
|
Disc Ops
|
|
Total
|
|||||||
Crude oil and condensate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Proved developed and undeveloped reserves:
|
||||||||||||||||||||
Beginning of year - 2015
|
634
|
|
|
57
|
|
|
208
|
|
|
29
|
|
|
928
|
|
|
—
|
|
|
928
|
|
Revisions of previous estimates
|
(57
|
)
|
|
2
|
|
|
(7
|
)
|
|
(2
|
)
|
|
(64
|
)
|
|
—
|
|
|
(64
|
)
|
Improved recovery
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
Purchases of reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Extensions, discoveries and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
other additions
|
70
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
70
|
|
|
—
|
|
|
70
|
|
Production
|
(62
|
)
|
|
(7
|
)
|
|
—
|
|
|
(5
|
)
|
|
(74
|
)
|
|
—
|
|
|
(74
|
)
|
Sales of reserves in place
|
(6
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6
|
)
|
|
—
|
|
|
(6
|
)
|
End of year - 2015
|
580
|
|
|
52
|
|
|
201
|
|
|
22
|
|
|
855
|
|
|
—
|
|
|
855
|
|
Revisions of previous estimates
|
55
|
|
|
1
|
|
|
(28
|
)
|
|
3
|
|
|
31
|
|
|
—
|
|
|
31
|
|
Improved recovery
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
—
|
|
|
4
|
|
Purchases of reserves in place
|
12
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
12
|
|
|
—
|
|
|
12
|
|
Extensions, discoveries and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
other additions
|
37
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
38
|
|
|
—
|
|
|
38
|
|
Production
|
(48
|
)
|
|
(8
|
)
|
|
(1
|
)
|
|
(4
|
)
|
|
(61
|
)
|
|
—
|
|
|
(61
|
)
|
Sales of reserves in place
|
(77
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(77
|
)
|
|
—
|
|
|
(77
|
)
|
End of year - 2016
|
563
|
|
|
45
|
|
|
172
|
|
|
22
|
|
|
802
|
|
|
—
|
|
|
802
|
|
Revisions of previous estimates
|
9
|
|
|
(2
|
)
|
|
—
|
|
|
8
|
|
|
15
|
|
|
—
|
|
|
15
|
|
Improved recovery
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Purchases of reserves in place
|
18
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
18
|
|
|
—
|
|
|
18
|
|
Extensions, discoveries and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
other additions
|
30
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
34
|
|
|
—
|
|
|
34
|
|
Production
|
(49
|
)
|
|
(8
|
)
|
|
(7
|
)
|
|
(4
|
)
|
|
(68
|
)
|
|
—
|
|
|
(68
|
)
|
Sales of reserves in place
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
End of year - 2017
|
570
|
|
|
39
|
|
|
165
|
|
|
26
|
|
|
800
|
|
|
—
|
|
|
800
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Beginning of year - 2015
|
294
|
|
|
30
|
|
|
175
|
|
|
19
|
|
|
518
|
|
|
—
|
|
|
518
|
|
End of year - 2015
|
327
|
|
|
25
|
|
|
173
|
|
|
16
|
|
|
541
|
|
|
—
|
|
|
541
|
|
End of year - 2016
|
238
|
|
|
45
|
|
|
172
|
|
|
13
|
|
|
468
|
|
|
—
|
|
|
468
|
|
End of year - 2017
|
263
|
|
|
39
|
|
|
165
|
|
|
17
|
|
|
484
|
|
|
—
|
|
|
484
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Beginning of year - 2015
|
340
|
|
|
27
|
|
|
33
|
|
|
10
|
|
|
410
|
|
|
—
|
|
|
410
|
|
End of year - 2015
|
253
|
|
|
27
|
|
|
28
|
|
|
6
|
|
|
314
|
|
|
—
|
|
|
314
|
|
End of year - 2016
|
325
|
|
|
—
|
|
|
—
|
|
|
9
|
|
|
334
|
|
|
—
|
|
|
334
|
|
End of year - 2017
|
307
|
|
|
—
|
|
|
—
|
|
|
9
|
|
|
316
|
|
|
—
|
|
|
316
|
|
(mmbbl)
|
U.S.
|
|
E.G.
(a)
|
|
Libya
|
|
Other Int'l
|
|
Cont Ops
|
|
Disc Ops
|
|
Total
|
|||||||
Natural gas liquids
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Proved developed and undeveloped reserves:
|
||||||||||||||||||||
Beginning of year - 2015
|
161
|
|
|
30
|
|
|
—
|
|
|
1
|
|
|
192
|
|
|
—
|
|
|
192
|
|
Revisions of previous estimates
|
(7
|
)
|
|
2
|
|
|
—
|
|
|
(1
|
)
|
|
(6
|
)
|
|
—
|
|
|
(6
|
)
|
Improved recovery
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Purchases of reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Extensions, discoveries and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
other additions
|
33
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
33
|
|
|
—
|
|
|
33
|
|
Production
|
(14
|
)
|
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
(18
|
)
|
|
—
|
|
|
(18
|
)
|
Sales of reserves in place
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
End of year - 2015
|
172
|
|
|
28
|
|
|
—
|
|
|
—
|
|
|
200
|
|
|
—
|
|
|
200
|
|
Revisions of previous estimates
|
(8
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(8
|
)
|
|
—
|
|
|
(8
|
)
|
Improved recovery
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Purchases of reserves in place
|
12
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
12
|
|
|
—
|
|
|
12
|
|
Extensions, discoveries and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
other additions
|
11
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11
|
|
|
—
|
|
|
11
|
|
Production
|
(14
|
)
|
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
(18
|
)
|
|
—
|
|
|
(18
|
)
|
Sales of reserves in place
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3
|
)
|
|
—
|
|
|
(3
|
)
|
End of year - 2016
|
170
|
|
|
24
|
|
|
—
|
|
|
—
|
|
|
194
|
|
|
—
|
|
|
194
|
|
Revisions of previous estimates
|
37
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
40
|
|
|
—
|
|
|
40
|
|
Improved recovery
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Purchases of reserves in place
|
5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|
—
|
|
|
5
|
|
Extensions, discoveries and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
other additions
|
34
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
36
|
|
|
—
|
|
|
36
|
|
Production
|
(16
|
)
|
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
(20
|
)
|
|
—
|
|
|
(20
|
)
|
Sales of reserves in place
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
End of year - 2017
|
229
|
|
|
25
|
|
|
—
|
|
|
—
|
|
|
254
|
|
|
—
|
|
|
254
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Beginning of year - 2015
|
68
|
|
|
15
|
|
|
—
|
|
|
—
|
|
|
83
|
|
|
—
|
|
|
83
|
|
End of year - 2015
|
92
|
|
|
12
|
|
|
—
|
|
|
—
|
|
|
104
|
|
|
—
|
|
|
104
|
|
End of year - 2016
|
78
|
|
|
24
|
|
|
—
|
|
|
—
|
|
|
102
|
|
|
—
|
|
|
102
|
|
End of year - 2017
|
118
|
|
|
25
|
|
|
—
|
|
|
—
|
|
|
143
|
|
|
—
|
|
|
143
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Beginning of year - 2015
|
93
|
|
|
15
|
|
|
—
|
|
|
1
|
|
|
109
|
|
|
—
|
|
|
109
|
|
End of year - 2015
|
80
|
|
|
16
|
|
|
—
|
|
|
—
|
|
|
96
|
|
|
—
|
|
|
96
|
|
End of year - 2016
|
92
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
92
|
|
|
—
|
|
|
92
|
|
End of year - 2017
|
111
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
111
|
|
|
—
|
|
|
111
|
|
(bcf)
|
U.S.
|
|
E.G.
(a)
|
|
Libya
|
|
Other Int'l
|
|
Cont Ops
|
|
Disc Ops
|
|
Total
|
|||||||
Natural gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Proved developed and undeveloped reserves:
|
||||||||||||||||||||
Beginning of year - 2015
|
1,144
|
|
|
1,205
|
|
|
209
|
|
|
22
|
|
|
2,580
|
|
|
—
|
|
|
2,580
|
|
Revisions of previous estimates
|
(22
|
)
|
|
35
|
|
|
(3
|
)
|
|
1
|
|
|
11
|
|
|
—
|
|
|
11
|
|
Improved recovery
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Purchases of reserves in place
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
Extensions, discoveries and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
other additions
|
225
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
225
|
|
|
—
|
|
|
225
|
|
Production
(b)
|
(128
|
)
|
|
(150
|
)
|
|
—
|
|
|
(8
|
)
|
|
(286
|
)
|
|
—
|
|
|
(286
|
)
|
Sales of reserves in place
|
(69
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(69
|
)
|
|
—
|
|
|
(69
|
)
|
End of year - 2015
|
1,151
|
|
|
1,090
|
|
|
206
|
|
|
15
|
|
|
2,462
|
|
|
—
|
|
|
2,462
|
|
Revisions of previous estimates
|
145
|
|
|
8
|
|
|
(1
|
)
|
|
3
|
|
|
155
|
|
|
—
|
|
|
155
|
|
Improved recovery
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Purchases of reserves in place
|
61
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
61
|
|
|
—
|
|
|
61
|
|
Extensions, discoveries and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
other additions
|
71
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
71
|
|
|
—
|
|
|
71
|
|
Production
(b)
|
(115
|
)
|
|
(155
|
)
|
|
—
|
|
|
(8
|
)
|
|
(278
|
)
|
|
—
|
|
|
(278
|
)
|
Sales of reserves in place
|
(25
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(25
|
)
|
|
—
|
|
|
(25
|
)
|
End of year - 2016
|
1,288
|
|
|
943
|
|
|
205
|
|
|
10
|
|
|
2,446
|
|
|
—
|
|
|
2,446
|
|
Revisions of previous estimates
|
(33
|
)
|
|
(18
|
)
|
|
—
|
|
|
4
|
|
|
(47
|
)
|
|
—
|
|
|
(47
|
)
|
Improved recovery
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Purchases of reserves in place
|
36
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
36
|
|
|
—
|
|
|
36
|
|
Extensions, discoveries and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
other additions
|
204
|
|
|
76
|
|
|
—
|
|
|
—
|
|
|
280
|
|
|
—
|
|
|
280
|
|
Production
(b)
|
(127
|
)
|
|
(168
|
)
|
|
(1
|
)
|
|
(6
|
)
|
|
(302
|
)
|
|
—
|
|
|
(302
|
)
|
Sales of reserves in place
|
(44
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(44
|
)
|
|
—
|
|
|
(44
|
)
|
End of year - 2017
|
1,324
|
|
|
833
|
|
|
204
|
|
|
8
|
|
|
2,369
|
|
|
—
|
|
|
2,369
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Beginning of year - 2015
|
575
|
|
|
664
|
|
|
94
|
|
|
17
|
|
|
1,350
|
|
|
—
|
|
|
1,350
|
|
End of year - 2015
|
640
|
|
|
552
|
|
|
94
|
|
|
11
|
|
|
1,297
|
|
|
—
|
|
|
1,297
|
|
End of year - 2016
|
648
|
|
|
943
|
|
|
95
|
|
|
5
|
|
|
1,691
|
|
|
—
|
|
|
1,691
|
|
End of year - 2017
|
726
|
|
|
833
|
|
|
94
|
|
|
2
|
|
|
1,655
|
|
|
—
|
|
|
1,655
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Beginning of year - 2015
|
569
|
|
|
541
|
|
|
115
|
|
|
5
|
|
|
1,230
|
|
|
—
|
|
|
1,230
|
|
End of year - 2015
|
511
|
|
|
538
|
|
|
112
|
|
|
4
|
|
|
1,165
|
|
|
—
|
|
|
1,165
|
|
End of year - 2016
|
640
|
|
|
—
|
|
|
110
|
|
|
5
|
|
|
755
|
|
|
—
|
|
|
755
|
|
End of year - 2017
|
598
|
|
|
—
|
|
|
110
|
|
|
6
|
|
|
714
|
|
|
—
|
|
|
714
|
|
(mmbbl)
|
U.S.
|
|
E.G.
(a)
|
|
Libya
|
|
Other Int'l
|
|
Cont Ops
|
|
Disc Ops
|
|
Total
|
|||||||
Synthetic crude oil
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Proved developed and undeveloped reserves:
|
||||||||||||||||||||
Beginning of year - 2015
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
648
|
|
|
648
|
|
Revisions of previous estimates
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
67
|
|
|
67
|
|
Improved recovery
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Purchases of reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Extensions, discoveries and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
other additions
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Production
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(17
|
)
|
|
(17
|
)
|
Sales of reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
End of year - 2015
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
698
|
|
|
698
|
|
Revisions of previous estimates
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
12
|
|
|
12
|
|
Improved recovery
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Purchases of reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Extensions, discoveries and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
other additions
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Production
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(18
|
)
|
|
(18
|
)
|
Sales of reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
End of year - 2016
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
692
|
|
|
692
|
|
Revisions of previous estimates
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Improved recovery
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Purchases of reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Extensions, discoveries and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
other additions
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Production
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(7
|
)
|
|
(7
|
)
|
Sales of reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(685
|
)
|
|
(685
|
)
|
End of year - 2017
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Beginning of year - 2015
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
644
|
|
|
644
|
|
End of year - 2015
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
698
|
|
|
698
|
|
End of year - 2016
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
692
|
|
|
692
|
|
End of year - 2017
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Beginning of year - 2015
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
4
|
|
End of year - 2015
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
End of year - 2016
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
End of year - 2017
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
(mmboe)
|
U.S.
|
|
E.G.
(a)
|
|
Libya
|
|
Other Int'l
|
|
Cont Ops
|
|
Disc Ops
|
|
Total
|
|||||||
Total Proved Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Proved developed and undeveloped reserves:
|
||||||||||||||||||||
Beginning of year - 2015
|
986
|
|
|
288
|
|
|
243
|
|
|
33
|
|
|
1,550
|
|
|
648
|
|
|
2,198
|
|
Revisions of previous estimates
|
(67
|
)
|
|
8
|
|
|
(8
|
)
|
|
(2
|
)
|
|
(69
|
)
|
|
67
|
|
|
(2
|
)
|
Improved recovery
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
Purchases of reserves in place
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
Extensions, discoveries and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
other additions
|
139
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
140
|
|
|
—
|
|
|
140
|
|
Production
(b)
|
(98
|
)
|
|
(36
|
)
|
|
—
|
|
|
(6
|
)
|
|
(140
|
)
|
|
(17
|
)
|
|
(157
|
)
|
Sales of reserves in place
|
(18
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(18
|
)
|
|
—
|
|
|
(18
|
)
|
End of year - 2015
|
944
|
|
|
261
|
|
|
235
|
|
|
25
|
|
|
1,465
|
|
|
698
|
|
|
2,163
|
|
Revisions of previous estimates
|
73
|
|
|
2
|
|
|
(28
|
)
|
|
4
|
|
|
51
|
|
|
12
|
|
|
63
|
|
Improved recovery
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
—
|
|
|
4
|
|
Purchases of reserves in place
|
34
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
34
|
|
|
—
|
|
|
34
|
|
Extensions, discoveries and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
other additions
|
59
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
60
|
|
|
—
|
|
|
60
|
|
Production
(b)
|
(82
|
)
|
|
(37
|
)
|
|
(1
|
)
|
|
(6
|
)
|
|
(126
|
)
|
|
(18
|
)
|
|
(144
|
)
|
Sales of reserves in place
|
(84
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(84
|
)
|
|
—
|
|
|
(84
|
)
|
End of year - 2016
|
948
|
|
|
226
|
|
|
206
|
|
|
24
|
|
|
1,404
|
|
|
692
|
|
|
2,096
|
|
Revisions of previous estimates
|
42
|
|
|
(1
|
)
|
|
—
|
|
|
8
|
|
|
49
|
|
|
—
|
|
|
49
|
|
Improved recovery
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Purchases of reserves in place
|
28
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
28
|
|
|
—
|
|
|
28
|
|
Extensions, discoveries and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
other additions
|
98
|
|
|
18
|
|
|
—
|
|
|
—
|
|
|
116
|
|
|
—
|
|
|
116
|
|
Production
(b)
|
(86
|
)
|
|
(40
|
)
|
|
(7
|
)
|
|
(5
|
)
|
|
(138
|
)
|
|
(7
|
)
|
|
(145
|
)
|
Sales of reserves in place
|
(10
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(10
|
)
|
|
(685
|
)
|
|
(695
|
)
|
End of year - 2017
|
1,020
|
|
|
203
|
|
|
199
|
|
|
27
|
|
|
1,449
|
|
|
—
|
|
|
1,449
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Beginning of year - 2015
|
458
|
|
|
155
|
|
|
191
|
|
|
22
|
|
|
826
|
|
|
644
|
|
|
1,470
|
|
End of year - 2015
|
526
|
|
|
129
|
|
|
189
|
|
|
18
|
|
|
862
|
|
|
698
|
|
|
1,560
|
|
End of year - 2016
|
424
|
|
|
226
|
|
|
188
|
|
|
14
|
|
|
852
|
|
|
692
|
|
|
1,544
|
|
End of year - 2017
|
502
|
|
|
203
|
|
|
181
|
|
|
17
|
|
|
903
|
|
|
—
|
|
|
903
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Beginning of year - 2015
|
528
|
|
|
133
|
|
|
52
|
|
|
11
|
|
|
724
|
|
|
4
|
|
|
728
|
|
End of year - 2015
|
418
|
|
|
132
|
|
|
46
|
|
|
7
|
|
|
603
|
|
|
—
|
|
|
603
|
|
End of year - 2016
|
524
|
|
|
—
|
|
|
18
|
|
|
10
|
|
|
552
|
|
|
—
|
|
|
552
|
|
End of year - 2017
|
518
|
|
|
—
|
|
|
18
|
|
|
10
|
|
|
546
|
|
|
—
|
|
|
546
|
|
(a)
|
Consists of estimated reserves from properties governed by production sharing contracts.
|
(b)
|
Excludes the resale of purchased natural gas used in reservoir management.
|
•
|
Revisions of previous estimates:
Increased by 49 mmboe primarily due to the acceleration of higher economic wells in the Bakken into the 5-year plan resulting in an increase of 44 mmboe, with the remainder being due to revisions across the business.
|
•
|
Extensions, discoveries, and other additions:
Increased by 116 mmboe primarily due to an increase of 97 mmboe associated with the expansion of proved areas and wells to sales from unproved categories in Oklahoma.
|
•
|
Purchases of reserves in place:
Increased by 28 mmboe from acquisitions of assets in the Northern Delaware Basin in New Mexico.
|
•
|
Production:
Decreased by 145 mmboe.
|
•
|
Sales of reserves in place:
Decreased by 695 mmboe including 685 mmboe associated with the sale of our Canadian business and 10 mmboe associated with divestitures of certain conventional assets in Oklahoma and Colorado. See Item 8. Financial Statements and Supplementary Data - Note
5
to the consolidated financial statements for information regarding these dispositions.
|
•
|
Revisions of previous estimates:
Increased by 63 mmboe primarily due to an increase of 151 mmboe associated with the acceleration of higher economic wells in the U.S. resource plays into the 5-year plan and a decrease of 64 mmboe due to U.S. technical revisions.
|
•
|
Extensions, discoveries, and other additions:
Increased by 60 mmboe primarily associated with the expansion of proved areas and new wells to sales from unproven categories in Oklahoma.
|
•
|
Purchases of reserves in place:
Increased by 34 mmboe from acquisition of STACK assets in Oklahoma.
|
•
|
Production:
Decreased by 144 mmboe.
|
•
|
Sales of reserves in place:
Decreased by 84 mmboe associated with the divestitures of certain Wyoming and Gulf of Mexico assets.
|
•
|
Revisions of previous estimates:
Decreased by 2 mmboe primarily resulting from an increase of 105 mmboe associated with drilling programs in U.S. resource plays and an increase of 67 mmboe in discontinued operations due to technical reevaluation and lower royalty percentages related to lower realized prices, offset by a decrease of 173 mmboe which was largely due to reductions to our capital development program and adherence to the SEC 5-year rule.
|
•
|
Extensions, discoveries, and other additions:
Increased by140 mmboe as a result of drilling programs in our U.S. resource plays.
|
•
|
Production:
Decreased by 157 mmboe.
|
•
|
Sales of reserves in place:
U.S. conventional assets sales contributed to a decrease of 18 mmboe.
|
(mmboe)
|
|
|
Beginning of year
|
552
|
|
Revisions of previous estimates
|
5
|
|
Improved recovery
|
—
|
|
Purchases of reserves in place
|
15
|
|
Extensions, discoveries, and other additions
|
57
|
|
Dispositions
|
—
|
|
Transfers to proved developed
|
(83
|
)
|
End of year
|
546
|
|
|
Year Ended December 31,
|
||||||||||||||||||||||
(In millions)
|
U.S.
|
|
E.G.
|
|
Libya
|
|
Other Africa
|
|
Other Int'l
|
|
Total
|
||||||||||||
2017 Capitalized Costs:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Proved properties
|
$
|
27,477
|
|
|
$
|
1,990
|
|
|
830
|
|
|
$
|
—
|
|
|
$
|
5,050
|
|
|
$
|
35,347
|
|
|
Unproved properties
|
2,755
|
|
|
110
|
|
|
217
|
|
|
43
|
|
|
33
|
|
|
3,158
|
|
||||||
Total
|
30,232
|
|
|
2,100
|
|
|
1,047
|
|
|
43
|
|
|
5,083
|
|
|
38,505
|
|
||||||
Accumulated depreciation,
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
depletion and amortization:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Proved properties
|
14,254
|
|
|
1,348
|
|
|
289
|
|
|
—
|
|
|
4,850
|
|
|
20,741
|
|
||||||
Unproved properties
(a)
|
206
|
|
|
—
|
|
|
—
|
|
|
43
|
|
|
33
|
|
|
282
|
|
||||||
Total
|
14,460
|
|
|
1,348
|
|
|
289
|
|
|
43
|
|
|
4,883
|
|
|
21,023
|
|
||||||
Net capitalized costs
|
$
|
15,772
|
|
|
$
|
752
|
|
|
$
|
758
|
|
|
$
|
—
|
|
|
$
|
200
|
|
|
$
|
17,482
|
|
2016 Capitalized Costs:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Proved properties
|
$
|
25,497
|
|
|
$
|
1,978
|
|
|
$
|
756
|
|
|
$
|
—
|
|
|
$
|
5,864
|
|
|
$
|
34,095
|
|
Unproved properties
|
1,473
|
|
|
119
|
|
|
281
|
|
|
136
|
|
|
183
|
|
|
2,192
|
|
||||||
Total
|
26,970
|
|
|
2,097
|
|
|
1,037
|
|
|
136
|
|
|
6,047
|
|
|
36,287
|
|
||||||
Accumulated depreciation,
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
depletion and amortization:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Proved properties
|
12,526
|
|
|
1,216
|
|
|
268
|
|
|
1
|
|
|
5,246
|
|
|
19,257
|
|
||||||
Unproved properties
(a)
|
382
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
113
|
|
|
497
|
|
||||||
Total
|
12,908
|
|
|
1,218
|
|
|
268
|
|
|
1
|
|
|
5,359
|
|
|
19,754
|
|
||||||
Net capitalized costs
|
$
|
14,062
|
|
|
$
|
879
|
|
|
$
|
769
|
|
|
$
|
135
|
|
|
$
|
688
|
|
|
$
|
16,533
|
|
(In millions)
|
U.S.
|
|
E.G.
|
|
Libya
|
|
Other
Africa
|
|
Other Int'l
|
|
Cont Ops
|
|
Disc Ops
|
|
Total
|
||||||||||||||||
December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Property acquisition:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Proved
|
$
|
191
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
192
|
|
|
$
|
—
|
|
|
$
|
192
|
|
Unproved
|
1,746
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1,747
|
|
|
—
|
|
|
1,747
|
|
||||||||
Exploration
|
882
|
|
|
1
|
|
|
—
|
|
|
37
|
|
|
3
|
|
|
923
|
|
|
—
|
|
|
923
|
|
||||||||
Development
|
1,122
|
|
|
5
|
|
|
10
|
|
|
—
|
|
|
(144
|
)
|
(b)
|
993
|
|
|
6
|
|
|
999
|
|
||||||||
Total
|
$
|
3,941
|
|
|
$
|
7
|
|
|
$
|
10
|
|
|
$
|
38
|
|
|
$
|
(141
|
)
|
|
$
|
3,855
|
|
|
$
|
6
|
|
|
$
|
3,861
|
|
December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Property acquisition:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Proved
|
$
|
276
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
276
|
|
|
$
|
—
|
|
|
$
|
276
|
|
Unproved
|
642
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
(11
|
)
|
|
632
|
|
|
—
|
|
|
632
|
|
||||||||
Exploration
|
525
|
|
|
1
|
|
|
—
|
|
|
10
|
|
|
3
|
|
|
539
|
|
|
—
|
|
|
539
|
|
||||||||
Development
|
456
|
|
|
55
|
|
|
3
|
|
|
—
|
|
|
121
|
|
(b)
|
635
|
|
|
31
|
|
|
666
|
|
||||||||
Total
|
$
|
1,899
|
|
|
$
|
56
|
|
|
$
|
3
|
|
|
$
|
11
|
|
|
$
|
113
|
|
|
$
|
2,082
|
|
|
$
|
31
|
|
|
$
|
2,113
|
|
December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Property acquisition:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Proved
|
$
|
4
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
4
|
|
|
$
|
—
|
|
|
$
|
4
|
|
Unproved
|
61
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
62
|
|
|
—
|
|
|
62
|
|
||||||||
Exploration
|
959
|
|
|
60
|
|
|
1
|
|
|
37
|
|
|
50
|
|
|
1,107
|
|
|
1
|
|
|
1,108
|
|
||||||||
Development
|
1,477
|
|
|
150
|
|
|
13
|
|
|
—
|
|
|
31
|
|
|
1,671
|
|
|
—
|
|
|
1,671
|
|
||||||||
Total
|
$
|
2,501
|
|
|
$
|
210
|
|
|
$
|
14
|
|
|
$
|
38
|
|
|
$
|
81
|
|
|
$
|
2,844
|
|
|
$
|
1
|
|
|
$
|
2,845
|
|
(a)
|
Includes costs incurred whether capitalized or expensed.
|
(b)
|
Includes revisions to asset retirement costs primarily due to changes in U.K. estimated costs as well as timing of abandonment activities in the U.K.
|
|
U.S.
|
|
E.G.
|
|
Libya
|
|
Other
Africa
|
|
Other Int'l
|
|
Cont Ops
|
|
Disc Ops
|
|
Total
|
||||||||||||||||
Year Ended December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Revenues and other income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Sales
|
$
|
3,050
|
|
|
$
|
45
|
|
|
$
|
431
|
|
|
$
|
—
|
|
|
$
|
282
|
|
|
$
|
3,808
|
|
|
$
|
423
|
|
|
$
|
4,231
|
|
Transfers
|
—
|
|
|
344
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
344
|
|
|
—
|
|
|
344
|
|
||||||||
Other income
(a)
|
74
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
38
|
|
|
112
|
|
|
(43
|
)
|
|
69
|
|
||||||||
Total revenues and other income
|
3,124
|
|
|
389
|
|
|
431
|
|
|
—
|
|
|
320
|
|
|
4,264
|
|
|
380
|
|
|
4,644
|
|
||||||||
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Production costs
|
(985
|
)
|
|
(84
|
)
|
|
(44
|
)
|
|
—
|
|
|
(152
|
)
|
|
(1,265
|
)
|
|
(272
|
)
|
|
(1,537
|
)
|
||||||||
Exploration expenses
(b)
|
(153
|
)
|
|
—
|
|
|
—
|
|
|
(171
|
)
|
|
(83
|
)
|
|
(407
|
)
|
|
—
|
|
|
(407
|
)
|
||||||||
Depreciation, depletion and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
amortization
(c)
|
(2,105
|
)
|
|
(134
|
)
|
|
(21
|
)
|
|
—
|
|
|
(273
|
)
|
|
(2,533
|
)
|
|
(6,676
|
)
|
|
(9,209
|
)
|
||||||||
Technical support and other
|
(28
|
)
|
|
(4
|
)
|
|
(4
|
)
|
|
(7
|
)
|
|
(18
|
)
|
|
(61
|
)
|
|
—
|
|
|
(61
|
)
|
||||||||
Total expenses
|
(3,271
|
)
|
|
(222
|
)
|
|
(69
|
)
|
|
(178
|
)
|
|
(526
|
)
|
|
(4,266
|
)
|
|
(6,948
|
)
|
|
(11,214
|
)
|
||||||||
Results before income taxes
|
(147
|
)
|
|
167
|
|
|
362
|
|
|
(178
|
)
|
|
(206
|
)
|
|
(2
|
)
|
|
(6,568
|
)
|
|
(6,570
|
)
|
||||||||
Income tax provision
|
(1
|
)
|
|
(50
|
)
|
|
(333
|
)
|
|
—
|
|
|
13
|
|
|
(371
|
)
|
|
1,674
|
|
|
1,303
|
|
||||||||
Results of operations
|
$
|
(148
|
)
|
|
$
|
117
|
|
|
$
|
29
|
|
|
$
|
(178
|
)
|
|
$
|
(193
|
)
|
|
$
|
(373
|
)
|
|
$
|
(4,894
|
)
|
|
$
|
(5,267
|
)
|
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Revenues and other income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Sales
|
$
|
2,249
|
|
|
$
|
42
|
|
|
$
|
54
|
|
|
$
|
—
|
|
|
$
|
237
|
|
|
$
|
2,582
|
|
|
$
|
724
|
|
|
$
|
3,306
|
|
Transfers
|
—
|
|
|
291
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
291
|
|
|
—
|
|
|
291
|
|
||||||||
Other income
(a)
|
387
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
389
|
|
|
—
|
|
|
389
|
|
||||||||
Total revenues and other income
|
2,636
|
|
|
333
|
|
|
54
|
|
|
—
|
|
|
239
|
|
|
3,262
|
|
|
724
|
|
|
3,986
|
|
||||||||
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Production costs
|
(952
|
)
|
|
(81
|
)
|
|
(36
|
)
|
|
—
|
|
|
(140
|
)
|
|
(1,209
|
)
|
|
(544
|
)
|
|
(1,753
|
)
|
||||||||
Exploration expenses
(b)
|
(306
|
)
|
|
(1
|
)
|
|
(6
|
)
|
|
(8
|
)
|
|
(2
|
)
|
|
(323
|
)
|
|
(7
|
)
|
|
(330
|
)
|
||||||||
Depreciation, depletion and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
amortization
(c)
|
(1,901
|
)
|
|
(114
|
)
|
|
(7
|
)
|
|
—
|
|
|
(132
|
)
|
|
(2,154
|
)
|
|
(239
|
)
|
|
(2,393
|
)
|
||||||||
Technical support and other
|
(21
|
)
|
|
(4
|
)
|
|
—
|
|
|
(3
|
)
|
|
(2
|
)
|
|
(30
|
)
|
|
(1
|
)
|
|
(31
|
)
|
||||||||
Total expenses
|
(3,180
|
)
|
|
(200
|
)
|
|
(49
|
)
|
|
(11
|
)
|
|
(276
|
)
|
|
(3,716
|
)
|
|
(791
|
)
|
|
(4,507
|
)
|
||||||||
Results before income taxes
|
(544
|
)
|
|
133
|
|
|
5
|
|
|
(11
|
)
|
|
(37
|
)
|
|
(454
|
)
|
|
(67
|
)
|
|
(521
|
)
|
||||||||
Income tax provision
(d)
|
195
|
|
|
(26
|
)
|
|
(2
|
)
|
|
—
|
|
|
57
|
|
|
224
|
|
|
15
|
|
|
239
|
|
||||||||
Results of operations
|
$
|
(349
|
)
|
|
$
|
107
|
|
|
$
|
3
|
|
|
$
|
(11
|
)
|
|
$
|
20
|
|
|
$
|
(230
|
)
|
|
$
|
(52
|
)
|
|
$
|
(282
|
)
|
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Revenues and other income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Sales
|
$
|
3,374
|
|
|
$
|
40
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
329
|
|
|
$
|
3,743
|
|
|
$
|
700
|
|
|
$
|
4,443
|
|
Transfers
|
—
|
|
|
296
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
296
|
|
|
—
|
|
|
296
|
|
||||||||
Other income
(a)
|
230
|
|
|
—
|
|
|
—
|
|
|
(109
|
)
|
|
1
|
|
|
122
|
|
|
—
|
|
|
122
|
|
||||||||
Total revenues and other income
|
3,604
|
|
|
336
|
|
|
—
|
|
|
(109
|
)
|
|
330
|
|
|
4,161
|
|
|
700
|
|
|
4,861
|
|
||||||||
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Production costs
|
(1,259
|
)
|
|
(84
|
)
|
|
(31
|
)
|
|
—
|
|
|
(177
|
)
|
|
(1,551
|
)
|
|
(660
|
)
|
|
(2,211
|
)
|
||||||||
Exploration expenses
(b)
|
(750
|
)
|
|
(41
|
)
|
|
—
|
|
|
(36
|
)
|
|
(143
|
)
|
|
(970
|
)
|
|
(348
|
)
|
|
(1,318
|
)
|
||||||||
Depreciation, depletion and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
amortization
(c)
|
(2,758
|
)
|
|
(92
|
)
|
|
(5
|
)
|
|
—
|
|
|
(163
|
)
|
|
(3,018
|
)
|
|
(266
|
)
|
|
(3,284
|
)
|
||||||||
Technical support and other
|
(47
|
)
|
|
(6
|
)
|
|
(1
|
)
|
|
(1
|
)
|
|
(3
|
)
|
|
(58
|
)
|
|
(2
|
)
|
|
(60
|
)
|
||||||||
Total expenses
|
(4,814
|
)
|
|
(223
|
)
|
|
(37
|
)
|
|
(37
|
)
|
|
(486
|
)
|
|
(5,597
|
)
|
|
(1,276
|
)
|
|
(6,873
|
)
|
||||||||
Results before income taxes
|
(1,210
|
)
|
|
113
|
|
|
(37
|
)
|
|
(146
|
)
|
|
(156
|
)
|
|
(1,436
|
)
|
|
(576
|
)
|
|
(2,012
|
)
|
||||||||
Income tax provision
|
437
|
|
|
(33
|
)
|
|
37
|
|
|
50
|
|
|
86
|
|
|
577
|
|
|
31
|
|
|
608
|
|
||||||||
Results of operations
|
$
|
(773
|
)
|
|
$
|
80
|
|
|
$
|
—
|
|
|
$
|
(96
|
)
|
|
$
|
(70
|
)
|
|
$
|
(859
|
)
|
|
$
|
(545
|
)
|
|
$
|
(1,404
|
)
|
(a)
|
Includes net gain (loss) on dispositions (see Note
5
) and revisions to asset retirement costs primarily due to changes in U.K. estimated costs as well as timing of abandonment activities in the U.K.
|
(b)
|
Includes exploratory dry well costs, unproved property impairments, and other (see Note
10
).
|
(c)
|
Includes long-lived asset impairments (see Note
10
).
|
|
Year Ended December 31,
|
||||||||||
(In millions)
|
2017
|
|
2016
|
|
2015
|
||||||
Results of operations
|
$
|
(5,267
|
)
|
|
$
|
(282
|
)
|
|
$
|
(1,404
|
)
|
Discontinued operations
|
4,894
|
|
|
52
|
|
|
545
|
|
|||
Results of continuing operations
|
(373
|
)
|
|
(230
|
)
|
|
(859
|
)
|
|||
Items not included in results of oil and gas operations, net of tax:
|
|
|
|
|
|
||||||
Marketing income and other non-oil and gas producing related activities
|
(107
|
)
|
|
(39
|
)
|
|
(102
|
)
|
|||
Income from equity method investments
|
229
|
|
|
142
|
|
|
127
|
|
|||
Items not allocated to segment income, net of tax:
|
|
|
|
|
|
||||||
Loss (gain) on asset dispositions and other income
|
(79
|
)
|
|
(248
|
)
|
|
(76
|
)
|
|||
Long-lived asset impairments
|
475
|
|
|
148
|
|
|
602
|
|
|||
Unrealized loss (gain) on derivatives
|
81
|
|
|
72
|
|
|
(32
|
)
|
|||
Deferred tax valuation allowance increase
|
—
|
|
|
(32
|
)
|
|
—
|
|
|||
Segment income
|
$
|
226
|
|
|
$
|
(187
|
)
|
|
$
|
(340
|
)
|
(In millions)
|
U.S.
|
|
E.G.
|
|
Libya
|
|
Other Int'l
|
|
Total
|
||||||||||
Year Ended December 31, 2017
|
|
|
|
|
|
|
|
|
|
||||||||||
Future cash inflows
|
$
|
36,480
|
|
|
$
|
1,966
|
|
|
$
|
10,303
|
|
|
$
|
1,403
|
|
|
$
|
50,152
|
|
Future production and support costs
|
(14,796
|
)
|
|
(748
|
)
|
|
(931
|
)
|
|
(821
|
)
|
|
(17,296
|
)
|
|||||
Future development costs
|
(6,987
|
)
|
|
(7
|
)
|
|
(501
|
)
|
|
(1,247
|
)
|
|
(8,742
|
)
|
|||||
Future income tax expenses
|
(786
|
)
|
|
(274
|
)
|
|
(8,387
|
)
|
|
496
|
|
|
(8,951
|
)
|
|||||
Future net cash flows
|
$
|
13,911
|
|
|
$
|
937
|
|
|
$
|
484
|
|
|
$
|
(169
|
)
|
(a)
|
$
|
15,163
|
|
10% annual discount for timing of cash flows
|
(7,009
|
)
|
|
(235
|
)
|
|
(224
|
)
|
|
168
|
|
|
(7,300
|
)
|
|||||
Standardized measure of discounted future net cash flows-
related to continuing operations
|
$
|
6,902
|
|
|
$
|
702
|
|
|
$
|
260
|
|
|
$
|
(1
|
)
|
|
$
|
7,863
|
|
Standardized measure of discounted future net cash flows-
related to discontinued operations
|
|
|
|
|
|
|
|
|
|
—
|
|
||||||||
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
||||||||||
Future cash inflows
|
$
|
27,610
|
|
|
$
|
1,977
|
|
|
$
|
8,511
|
|
|
$
|
921
|
|
|
$
|
39,019
|
|
Future production and support costs
|
(12,758
|
)
|
|
(824
|
)
|
|
(930
|
)
|
|
(673
|
)
|
|
(15,185
|
)
|
|||||
Future development costs
|
(7,233
|
)
|
|
(13
|
)
|
|
(296
|
)
|
|
(1,345
|
)
|
|
(8,887
|
)
|
|||||
Future income tax expenses
|
—
|
|
|
(251
|
)
|
|
(6,884
|
)
|
|
514
|
|
|
(6,621
|
)
|
|||||
Future net cash flows
|
$
|
7,619
|
|
|
$
|
889
|
|
|
$
|
401
|
|
|
$
|
(583
|
)
|
(a)
|
$
|
8,326
|
|
10% annual discount for timing of cash flows
|
(4,355
|
)
|
|
(264
|
)
|
|
(143
|
)
|
|
313
|
|
|
(4,449
|
)
|
|||||
Standardized measure of discounted future net cash flows-
related to continuing operations
|
$
|
3,264
|
|
|
$
|
625
|
|
|
$
|
258
|
|
|
$
|
(270
|
)
|
|
$
|
3,877
|
|
Standardized measure of discounted future net cash flows-
related to discontinued operations
|
|
|
|
|
|
|
|
|
|
$
|
1,076
|
|
|||||||
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
|
|
||||||||||
Future cash inflows
|
$
|
31,026
|
|
|
$
|
2,671
|
|
|
$
|
12,157
|
|
|
$
|
1,281
|
|
|
$
|
47,135
|
|
Future production and support costs
|
(12,270
|
)
|
|
(1,095
|
)
|
|
(901
|
)
|
|
(902
|
)
|
|
(15,168
|
)
|
|||||
Future development costs
|
(6,637
|
)
|
|
(94
|
)
|
|
(689
|
)
|
|
(1,537
|
)
|
|
(8,957
|
)
|
|||||
Future income tax expenses
|
(778
|
)
|
|
(369
|
)
|
|
(9,857
|
)
|
|
602
|
|
|
(10,402
|
)
|
|||||
Future net cash flows
|
$
|
11,341
|
|
|
$
|
1,113
|
|
|
$
|
710
|
|
|
$
|
(556
|
)
|
(a)
|
$
|
12,608
|
|
10% annual discount for timing of cash flows
|
(6,082
|
)
|
|
(380
|
)
|
|
(441
|
)
|
|
352
|
|
|
(6,551
|
)
|
|||||
Standardized measure of discounted future net cash flows-
related to continuing operations
|
$
|
5,259
|
|
|
$
|
733
|
|
|
$
|
269
|
|
|
$
|
(204
|
)
|
|
$
|
6,057
|
|
Standardized measure of discounted future net cash flows-
related to discontinued operations
|
|
|
|
|
|
|
|
|
|
$
|
165
|
|
(a)
|
Future cash flows for Other International reflects the impact of future abandonment costs related to the U.K.
|
|
Year Ended December 31,
|
|
||||||||||
(In millions)
|
2017
|
|
2016
|
|
2015
|
|
||||||
Sales and transfers of oil and gas produced, net of production and support costs
|
$
|
(2,853
|
)
|
|
$
|
(1,634
|
)
|
|
$
|
(2,422
|
)
|
|
Net changes in prices and production and support costs related to future production
|
4,916
|
|
|
(3,621
|
)
|
(b)
|
(21,309
|
)
|
(b)
|
|||
Extensions, discoveries and improved recovery, less related costs
|
661
|
|
|
(2,174
|
)
|
|
6
|
|
|
|||
Development costs incurred during the period
|
1,027
|
|
|
669
|
|
|
1,693
|
|
|
|||
Changes in estimated future development costs
|
183
|
|
|
2,534
|
|
|
7,247
|
|
|
|||
Revisions of previous quantity estimates
(a)
|
497
|
|
|
654
|
|
|
(5,682
|
)
|
|
|||
Net changes in purchases and sales of minerals in place
|
102
|
|
|
(651
|
)
|
|
(460
|
)
|
|
|||
Accretion of discount
|
698
|
|
|
1,005
|
|
|
2,719
|
|
|
|||
Net change in income taxes
|
(1,245
|
)
|
|
1,038
|
|
|
9,989
|
|
|
|||
Net change for the year
|
3,986
|
|
|
(2,180
|
)
|
|
(8,219
|
)
|
|
|||
Beginning of the year related to continuing operations
|
3,877
|
|
|
6,057
|
|
|
14,276
|
|
|
|||
End of the year related to continuing operations
|
$
|
7,863
|
|
|
$
|
3,877
|
|
|
$
|
6,057
|
|
|
Net change for the year related to discontinued operations
|
$
|
—
|
|
|
$
|
911
|
|
|
$
|
(2,115
|
)
|
|
(a)
|
Includes amounts resulting from changes in the timing of production.
|
(b)
|
Decrease primarily due to lower realized prices.
|
•
|
Marathon Oil Corporation 2016 Incentive Compensation Plan (the "2016 Plan")
|
•
|
Marathon Oil Corporation 2012 Incentive Compensation Plan (the "2012 Plan") – No additional awards will be granted under this plan.
|
•
|
Marathon Oil Corporation 2007 Incentive Compensation Plan (the "2007 Plan") – No additional awards will be granted under this plan.
|
•
|
Marathon Oil Corporation 2003 Incentive Compensation Plan (the "2003 Plan") – No additional awards will be granted under this plan.
|
•
|
Deferred Compensation Plan for Non-Employee Directors – No additional awards will be granted under this plan.
|
Plan category
|
Number of securities to be issued upon
exercise of outstanding options, warrants and rights
|
|
Weighted-average
exercise price of
outstanding options,
warrants and rights
(c)
|
|
Number of securities
remaining available for future issuance
under equity compensation plans
|
|
||
Equity compensation plans approved by stockholders
|
11,915,472
|
|
(a)
|
$25.52
|
|
43,840,884
|
|
(d)
|
Equity compensation plans not approved by stockholders
|
12,291
|
|
(b)
|
N/A
|
|
—
|
|
|
Total
|
11,927,763
|
|
|
N/A
|
|
43,840,884
|
|
|
(a)
|
Includes the following:
|
•
|
736,199
stock options outstanding under the 2016 Plan;
3,991,905
stock options outstanding under the 2012 Plan;
5,591,708
stock options outstanding under the 2007 Plan;
|
•
|
399,114
common stock units that have been credited to non-employee directors pursuant to the non-employee director deferred compensation program and the annual director stock award program established under the 2016 Plan, 2012 Plan, 2007 Plan and 2003 Plan. Common stock units credited under the 2016 Plan, 2012 Plan, 2007 Plan and 2003 Plan were
69,556
,
142,724
,
152,839
and
33,995
, respectively;
|
•
|
1,196,546
restricted stock units granted to non-officers under the 2012 Plan and 2016 Plan and outstanding as of
December 31, 2017
.
|
•
|
In addition to the awards reported above, 2,850,798 and 3,525,501 shares of restricted stock were issued and outstanding as of December 31, 2017, but subject to forfeiture restrictions under the 2012 and 2016 Plans, respectively.
|
(b)
|
Reflects awards of common stock units made to non-employee directors under the Deferred Compensation Plan for Non-Employee Directors prior to April 30, 2003. When a non-employee director leaves the Board, he or she will be issued actual shares of Marathon Oil common stock in place of the common stock units.
|
(c)
|
The weighted-average exercise prices do not take the restricted stock units or common stock units into account as these awards have no exercise price.
|
(d)
|
Reflects the shares available for issuance under the 2016 Plan. No more than
18,496,714
of these shares may be issued for awards other than stock options or stock appreciation rights. In addition, shares related to grants that are forfeited, terminated, canceled or expire unexercised shall again immediately become available for issuance.
|
February 22, 2018
|
|
MARATHON OIL CORPORATION
|
|
|
|
|
|
By: /s/ GARY E. WILSON
|
|
|
Gary E. Wilson
|
|
|
Vice President, Controller and Chief Accounting Officer
|
Signature
|
|
Title
|
|
|
|
/
S
/ LEE M. TILLMAN
|
|
President and Chief Executive Officer and Director
|
Lee M. Tillman
|
|
|
|
|
|
/
S
/ Dane E. Whitehead
|
|
Executive Vice President and Chief Financial Officer
|
Dane E. Whitehead
|
|
|
|
|
|
/s/ GARY E. WILSON
|
|
Vice President, Controller and Chief Accounting Officer
|
Gary E. Wilson
|
|
|
|
|
|
/
S
/ DENNIS H. REILLEY
|
|
Chairman of the Board
|
Dennis H. Reilley
|
|
|
|
|
|
/s/ GAURDIE E. BANISTER, JR.
|
|
Director
|
Gaurdie E. Banister, Jr.
|
|
|
|
|
|
/
S
/ GREGORY H. BOYCE
|
|
Director
|
Gregory H. Boyce
|
|
|
|
|
|
/S/ CHADWICK C. DEATON
|
|
Director
|
Chadwick C. Deaton
|
|
|
|
|
|
/
S
/ MARCELA E. DONADIO
|
|
Director
|
Marcela E. Donadio
|
|
|
|
|
|
/
S
/ PHILIP LADER
|
|
Director
|
Philip Lader
|
|
|
|
|
|
/
S
/ MICHAEL E. J. PHELPS
|
|
Director
|
Michael E. J. Phelps
|
|
|
Exhibit
|
|
|
|
Incorporated by Reference (File No. 001-05153, unless otherwise indicated)
|
||||
Number
|
|
Exhibit Description
|
|
Form
|
|
Exhibit
|
|
Filing Date
|
1
|
|
Underwriting Agreement
|
|
|
|
|
|
|
1.1*
|
|
|
|
|
|
|
|
|
2
|
|
Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession
|
|
|
|
|
|
|
2.1
|
|
|
10-Q
|
|
10.1
|
|
5/5/2017
|
|
3
|
|
Articles of Incorporation and By-laws
|
||||||
3.1
|
|
|
10-Q
|
|
3.1
|
|
8/8/2013
|
|
3.2
|
|
|
8-K
|
|
3.1
|
|
3/1/2016
|
|
3.3
|
|
|
10-K
|
|
3.3
|
|
2/28/2014
|
|
4
|
|
Instruments Defining the Rights of Security Holders, Including Indentures
|
||||||
4.1
|
|
|
10-K
|
|
4.2
|
|
2/28/2014
|
|
10
|
|
Material Contracts
|
|
|
|
|
|
|
10.1
|
|
|
8-K
|
|
4.1
|
|
6/2/2014
|
|
10.2
|
|
|
10-Q
|
|
10.1
|
|
5/7/2015
|
|
10.3
|
|
|
8-K
|
|
99.1
|
|
3/8/2016
|
Exhibit
|
|
|
|
Incorporated by Reference (File No. 001-05153, unless otherwise indicated)
|
||||
Number
|
|
Exhibit Description
|
|
Form
|
|
Exhibit
|
|
Filing Date
|
10.4
|
|
|
8-K
|
|
99.1
|
|
6/23/2017
|
|
10.5
|
|
|
10-Q
|
|
10.2
|
|
8/3/2017
|
|
10.6
†
|
|
|
DEF 14A
|
|
App. A
|
|
4/7/2016
|
|
10.7†
|
|
|
8-K/A
|
|
10.1
|
|
10/6/2016
|
|
10.8†
|
|
|
10-K
|
|
10.6
|
|
2/24/2017
|
|
10.9†
|
|
|
10-K
|
|
10.7
|
|
2/24/2017
|
|
10.10†
|
|
|
10-K
|
|
10.8
|
|
2/24/2017
|
|
10.11†
|
|
|
10-K
|
|
10.9
|
|
2/24/2017
|
|
10.12*
|
|
|
|
|
|
|
|
|
10.13*
|
|
|
|
|
|
|
|
|
10.14
†
|
|
|
DEF 14A
|
|
App. III
|
|
3/8/2012
|
|
10.15
†
|
|
|
8-K
|
|
10.1
|
|
8/1/2014
|
|
10.16†
|
|
|
10-Q
|
|
10.1
|
|
5/7/2014
|
|
10.17
†
|
|
|
10-Q
|
|
10.2
|
|
5/7/2014
|
|
10.18†
|
|
|
10-Q
|
|
10.1
|
|
11/6/2013
|
Exhibit
|
|
|
|
Incorporated by Reference (File No. 001-05153, unless otherwise indicated)
|
||||
Number
|
|
Exhibit Description
|
|
Form
|
|
Exhibit
|
|
Filing Date
|
10.19†
|
|
|
10-K
|
|
10.5
|
|
2/22/2013
|
|
10.20†
|
|
|
10-K
|
|
10.6
|
|
2/22/2013
|
|
10.21†
|
|
|
10-K
|
|
10.7
|
|
2/22/2013
|
|
10.22†
|
|
|
10-K
|
|
10.8
|
|
2/22/2013
|
|
10.23
†
|
|
|
10-K
|
|
10.9
|
|
2/22/2013
|
|
10.24
†
|
|
|
10-K
|
|
10.10
|
|
2/22/2013
|
|
10.25
†
|
|
|
10-K
|
|
10.5
|
|
2/29/2012
|
|
10.26†
|
|
|
10-K
|
|
10.6
|
|
2/29/2012
|
|
10.27
†
|
|
|
10-K
|
|
10.5
|
|
2/28/2011
|
|
10.28†
|
|
|
10-K
|
|
10.26
|
|
2/26/2010
|
|
10.29†
|
|
|
10-K
|
|
10.9
|
|
2/26/2010
|
|
10.30†
|
|
|
10-K
|
|
10.29
|
|
2/24/2017
|
|
10.31†
|
|
|
10-K
|
|
10.32
|
|
2/29/2012
|
|
10.32†
|
|
|
10-K
|
|
10.31
|
|
2/29/2012
|
|
10.33†*
|
|
|
|
|
|
|
|
|
10.34
†
|
|
|
10-K
|
|
10.10
|
|
2/28/2011
|
|
10.35
†
|
|
|
10-K
|
|
10.32
|
|
2/27/2009
|
|
10.36
|
|
|
8-K
|
|
10.1
|
|
5/26/2011
|
|
12.1*
|
|
|
|
|
|
|
|
|
21.1*
|
|
|
|
|
|
|
|
|
23.1*
|
|
|
|
|
|
|
|
|
23.2*
|
|
|
|
|
|
|
|
|
23.3*
|
|
|
|
|
|
|
|
|
The Underwriter:
|
|
|
|
Morgan Stanley & Co. LLC
|
|
1585 Broadway, 16
th
Floor
|
|
New York, New York 10036
|
|
Attention: Mr. Francis J. Sweeney
|
|
Telecopier: (212) 507-2375
|
|
|
|
The Corporation:
|
|
|
|
Marathon Oil Corporation
|
|
5555 San Felipe, Suite 1828
|
|
Houston, Texas 77056
|
|
Attention: Vice President and Treasurer
|
|
Telecopier: (713) 499-8413
|
|
|
|
The Issuer:
|
|
|
|
Parish of St. John the Baptist, State of Louisiana
|
|
1801 W. Airline Highway
|
|
LaPlace, Louisiana 70068
|
|
Attention: Parish President
|
|
Telecopier: (985) 652-1700
|
|
|
|
|
|
PARISH OF ST. JOHN THE BAPTIST, STATE OF LOUISIANA
|
|
|
|
|
|
By:
/s/ Natalie Robottom
|
|
Parish President
|
Attest:
By:
/s/ Jackie Landeche
|
|
Secretary, St. John the Baptist Parish
Council
|
|
|
MARATHON OIL CORPORATION
|
|
|
|
|
|
By:
/s/ Morris R. Clark
|
|
Name: Morris R. Clark
Title: Vice President and Treasurer |
|
|
|
|
|
MORGAN STANLEY & CO. LLC
|
|
|
|
|
|
By:
/s/ Francis J. Sweeney
|
|
Name: Francis J. Sweeney
Title: Managing Director |
|
|
|
|
(a)
|
“Maturity” means Bonds with the same credit and payment terms. Bonds with different maturity dates, or Bonds with the same maturity date but different stated interest rates, are treated as separate maturities.
|
(b)
|
“Public” means any person (including an individual, trust, estate, partnership, association, company, or corporation) other than an Underwriter or a related party to an Underwriter and, for these purposes, including Marathon Oil Corporation. The term “related party” for purposes of this certificate generally means any two or more persons who have greater than 50 percent common ownership, directly or indirectly.
|
(c)
|
“Sale Date” means the first day on which there is a binding contract in writing for the sale of a Maturity of the Bonds. The Sale Date of the Bonds is November 28, 2017.
|
(d)
|
“Tax Compliance Certificate” means the No-Arbitrage Certificate for the Bonds to which this certificate is attached.
|
(e)
|
“Underwriter” means, collectively, (i) any person that agrees pursuant to a written contract with the Issuer (or with the lead underwriter to form an underwriting syndicate) to participate in the initial sale of the Bonds to the Public, and (ii) any person that agrees pursuant to a written contract directly or indirectly with a person described in clause (i) of this paragraph to participate in the initial sale of the Bonds to the Public (including a member of a selling group or a party to a retail distribution agreement participating in the initial sale of the Bonds to the Public).
|
|
||||
|
|
|
|
|
TSR
Ranking of
|
|
TSR
Percentile
|
|
Vesting
|
Corporation
|
|
Ranking
|
|
Percentage
|
1st
|
|
100%
|
|
200%
|
2nd
|
|
90.9%
|
|
182%
|
3rd
|
|
81.8%
|
|
164%
|
4th
|
|
72.7%
|
|
145%
|
5th
|
|
63.6%
|
|
127%
|
6th
|
|
54.5%
|
|
109%
|
7th
|
|
45.4%
|
|
91%
|
8th
|
|
36.3%
|
|
73%
|
9th
|
|
27.2%
|
|
54%
|
10th
|
|
18.1%
|
|
0%
|
11th
|
|
9%
|
|
0%
|
12th
|
|
0%
|
|
0%
|
|
||||
|
|
|
|
|
TSR
Ranking of
|
|
TSR
Percentile
|
|
Vesting
|
Corporation
|
|
Ranking
|
|
Percentage
|
1st
|
|
100%
|
|
200%
|
2nd
|
|
90.9%
|
|
182%
|
3rd
|
|
81.8%
|
|
164%
|
4th
|
|
72.7%
|
|
145%
|
5th
|
|
63.6%
|
|
127%
|
6th
|
|
54.5%
|
|
109%
|
7th
|
|
45.4%
|
|
91%
|
8th
|
|
36.3%
|
|
73%
|
9th
|
|
27.2%
|
|
54%
|
10th
|
|
18.1%
|
|
0%
|
11th
|
|
9%
|
|
0%
|
12th
|
|
0%
|
|
0%
|
7.
|
Successors
.
|
|
|
Year Ended
|
||||||||||||||||||
|
|
December 31,
|
||||||||||||||||||
(In millions)
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Income (loss) from continuing operations before income taxes
|
|
$
|
(454
|
)
|
|
$
|
(1,164
|
)
|
|
$
|
(2,439
|
)
|
|
$
|
1,021
|
|
|
$
|
2,104
|
|
Income from equity method investments
|
|
256
|
|
|
175
|
|
|
145
|
|
|
424
|
|
|
423
|
|
|||||
Income (loss) from continuing operations before income taxes and income from equity method investments
|
|
(710
|
)
|
|
(1,339
|
)
|
|
(2,584
|
)
|
|
597
|
|
|
1,681
|
|
|||||
Add (deduct)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed charges
|
|
357
|
|
|
421
|
|
|
382
|
|
|
352
|
|
|
360
|
|
|||||
Capitalized interest
|
|
(4
|
)
|
|
(23
|
)
|
|
(26
|
)
|
|
(33
|
)
|
|
(27
|
)
|
|||||
Amortization of capitalized interest
|
|
9
|
|
|
7
|
|
|
5
|
|
|
8
|
|
|
21
|
|
|||||
Distributed income from equity investees
|
|
276
|
|
|
192
|
|
|
178
|
|
|
454
|
|
|
430
|
|
|||||
Earnings as defined
|
|
(72
|
)
|
|
(742
|
)
|
|
(2,045
|
)
|
|
1,378
|
|
|
2,465
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net interest expense (including discontinued operations)
|
|
323
|
|
|
367
|
|
|
321
|
|
|
277
|
|
|
297
|
|
|||||
Capitalized interest (including discontinued operations)
|
|
4
|
|
|
23
|
|
|
26
|
|
|
33
|
|
|
27
|
|
|||||
Interest portion of rental expense (including discontinued operations)
|
|
30
|
|
|
31
|
|
|
35
|
|
|
42
|
|
|
36
|
|
|||||
Fixed charges as defined
|
|
357
|
|
|
421
|
|
|
382
|
|
|
352
|
|
|
360
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Ratio of earnings to fixed charges
|
|
(0.20
|
)
|
|
(1.76
|
)
|
|
(5.35
|
)
|
|
3.91
|
|
|
6.85
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Amount by which earnings were insufficient to cover fixed charges
|
|
$
|
429
|
|
|
$
|
1,163
|
|
|
$
|
2,427
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Subsidiaries of Marathon Oil
|
Exhibit 21.1
|
Company Name
|
Country
|
Country Region
|
Alba Associates LLC
|
Cayman Islands
|
|
Alba Equatorial Guinea Partnership, L.P.
|
United States
|
Delaware
|
Alba Plant LLC
|
Cayman Islands
|
|
AMPCO Marketing, L.L.C.
|
United States
|
Michigan
|
AMPCO Services, L.L.C.
|
United States
|
Michigan
|
Atlantic Methanol Associates LLC
|
Cayman Islands
|
|
Atlantic Methanol Production Company LLC
|
Cayman Islands
|
|
E.G. Global LNG Services, Ltd.
|
United States
|
Delaware
|
Equatorial Guinea LNG Company, S.A.
|
Equatorial Guinea
|
|
Equatorial Guinea LNG Holdings Limited
|
Bahamas
|
|
Equatorial Guinea LNG Operations, S.A.
|
Equatorial Guinea
|
|
Equatorial Guinea LNG Train 1, S.A.
|
Equatorial Guinea
|
|
Marathon E.G. Alba Limited
|
Cayman Islands
|
|
Marathon E.G. Holding Limited
|
Cayman Islands
|
|
Marathon E.G. International Limited
|
Cayman Islands
|
|
Marathon E.G. LNG Holding Limited
|
Cayman Islands
|
|
Marathon E.G. LPG Limited
|
Cayman Islands
|
|
Marathon E.G. Offshore Limited
|
Cayman Islands
|
|
Marathon E.G. Production Limited
|
Cayman Islands
|
|
Marathon Eagle Ford Midstream LLC
|
United States
|
Delaware
|
Marathon East Texas Holdings LLC
|
United States
|
Delaware
|
Marathon International Oil Company
|
United States
|
Delaware
|
Marathon International Oil Holdings LLC
|
United States
|
Delaware
|
Marathon International Oil Libya Limited
|
Cayman Islands
|
|
Marathon Offshore Alpha Limited
|
Cayman Islands
|
|
Marathon Oil (East Texas) L.P.
|
United States
|
Texas
|
Marathon Oil (West Texas) L.P.
|
United States
|
Texas
|
Marathon Oil Company
|
United States
|
Ohio
|
Marathon Oil Corporation
|
United States
|
Delaware
|
Marathon Oil Dutch Holdings Coöperatief U.A.
|
Netherlands
|
|
Marathon Oil EF LLC
|
United States
|
Delaware
|
Marathon Oil EF II LLC
|
United States
|
Delaware
|
Marathon Oil Holdings (Barbados) Inc.
|
Barbados
|
|
Marathon Oil International Holding C.V.
|
Netherlands
|
|
Marathon Oil Investment LLC
|
United States
|
Delaware
|
Marathon Oil Permian LLC
|
United States
|
New Mexico
|
Marathon Oil U.K. LLC
|
United States
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Delaware
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Marathon West Texas Holdings LLC
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United States
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Delaware
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MOC Portfolio Delaware, Inc.
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United States
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Delaware
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Pan Ocean Energy LLC
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United States
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Delaware
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Form S-3ASR:
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Relating to:
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Reg. No.
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333-215733
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Marathon Oil Corporation Debt Securities, Common Stock, Preferred Stock, Warrants and Stock Purchase Contracts/Units
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Form S-8:
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Relating to:
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Reg. No.
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33-56828
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Marathon Oil Company Thrift Plan
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333-29709
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Marathon Oil Company Thrift Plan
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333-104910
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Marathon Oil Corporation 2003 Incentive Compensation Plan
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333-143010
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Marathon Oil Corporation 2007 Incentive Compensation Plan
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333-181301
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Marathon Oil Corporation 2012 Incentive Compensation Plan
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333-211611
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Marathon Oil Corporation 2016 Incentive Compensation Plan
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TBPE REGISTERED ENGINEERING FIRM F-1580
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FAX (713) 651-0849
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1100 LOUISIANA SUITE 4600
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HOUSTON, TEXAS 77002-5294
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TELEPHONE (713) 651-9191
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Form S-3ASR:
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Relating to:
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Reg. No.
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333-215733
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Marathon Oil Corporation Debt Securities, Common Stock, Preferred Stock, Warrants and Stock Purchase Contracts/Units
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Form S-8:
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Relating to:
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Reg. No.
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33-56828
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Marathon Oil Company Thrift Plan
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333-29709
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Marathon Oil Company Thrift Plan
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333-104910
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Marathon Oil Corporation 2003 Incentive Compensation Plan
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333-143010
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Marathon Oil Corporation 2007 Incentive Compensation Plan
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333-181301
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Marathon Oil Corporation 2012 Incentive Compensation Plan
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333-211611
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Marathon Oil Corporation 2016 Incentive Compensation Plan
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Form S-3ASR:
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Relating to:
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Reg. No.
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333-215733
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Marathon Oil Corporation Debt Securities, Common Stock, Preferred Stock, Warrants and Stock Purchase Contracts/Units
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Form S-8:
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Relating to:
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Reg. No.
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33-56828
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Marathon Oil Company Thrift Plan
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Reg. No.
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333-29709
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Marathon Oil Company Thrift Plan
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Reg. No.
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333-104910
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Marathon Oil Corporation 2003 Incentive Compensation Plan
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Reg. No.
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333-143010
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Marathon Oil Corporation 2007 Incentive Compensation Plan
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Reg. No.
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333-181301
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Marathon Oil Corporation 2012 Incentive Compensation Plan
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Reg. No.
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333-211611
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Marathon Oil Corporation 2016 Incentive Compensation Plan
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1.
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I have reviewed this report on Form 10-K of Marathon Oil Corporation;
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2.
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Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
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3.
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Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
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4.
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The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
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(a)
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Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
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(b)
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Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
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(c)
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Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
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(d)
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Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
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5.
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The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
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(a)
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All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
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(b)
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Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
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Date:
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February 22, 2018
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/s/ Lee M. Tillman
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Lee M. Tillman
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President and Chief Executive Officer
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1.
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I have reviewed this report on Form 10-K of Marathon Oil Corporation;
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2.
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Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
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3.
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Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
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4.
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The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
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(a)
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Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
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(b)
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Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
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(c)
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Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
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(d)
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Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
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5.
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The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
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(a)
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All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
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(b)
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Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
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Date:
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February 22, 2018
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/s/ Dane E. Whitehead
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Dane E. Whitehead
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Executive Vice President and Chief Financial Officer
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(1)
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The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
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(2)
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The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
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February 22, 2018
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/s/ Lee M. Tillman
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Lee M. Tillman
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President and Chief Executive Officer
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(1)
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The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
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(2)
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The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
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February 22, 2018
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/s/ Dane E. Whitehead
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Dane E. Whitehead
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Executive Vice President and Chief Financial Officer
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/s/ Scott J. Wilson
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Scott J. Wilson, P.E., M.B.A.
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Colorado License No. 36112
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Senior Vice President
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TBPE REGISTERED ENGINEERING FIRM F-1580
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FAX (303) 623-4258
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621 SEVENTEENTH STREET SUITE 1550
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DENVER, COLORADO 80293
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TELEPHONE (303) 623-9147
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As of December 31, 2016
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Proved
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Developed Producing
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Undeveloped
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Total Proved
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Audited by Ryder Scott
Net Reserves
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Oil/Condensate – MBarrels
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13,469
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22,636
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36,105
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Plant Products – MBarrels
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20,873
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30,674
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51,547
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Gas – MMCF
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220,163
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278,333
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498,496
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Geographic Area
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Product
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Price
Reference
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Average
Benchmark
Prices
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Average Realized
Prices
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North America
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Oil/Condensate
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WTI Cushing
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$42.75/Bbl
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$41.04/Bbl
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United States
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NGLs
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WTI Cushing
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$42.75/Bbl
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$15.22/Bbl
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Gas
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Henry Hub
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$2.49/MMBTU
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$2.50/MCF
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/s/ Daniel R. Olds
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/s/ Syed R. Rizvi
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Daniel R. Olds, P.E.
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Syed R. Rizvi
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TBPE License No. 60996
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Petroleum Engineer
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Managing Senior Vice President
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TBPE REGISTERED ENGINEERING FIRM F-1580
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FAX (713) 651-0849
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1100 LOUISIANA SUITE 4600
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HOUSTON, TEXAS 77002-5294
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TELEPHONE (713) 651-9191
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As of December 31, 2016
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Proved
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Developed Producing
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Undeveloped
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Total Proved
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Audited by Ryder Scott
Net Reserves
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Oil/Condensate – MBarrels
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103,971
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146,306
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250,277
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Plant Products – MBarrels
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42,450
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45,623
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88,073
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Gas – MMCF
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235,405
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264,827
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500,232
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Geographic Area
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Product
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Price
Reference
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Average
Benchmark
Prices
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Average Realized
Prices
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North America
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Oil/Condensate
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WTI Cushing
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$42.75/Bbl
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$38.75/Bbl
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United States
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NGLs
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Mont Belvieu, TX
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$19.97/Bbl
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$28.89/Bbl
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Gas
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Henry Hub
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$2.49/MMBTU
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$2.09/MCF
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(1)
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completion intervals which are open at the time of the estimate, but which have not started producing;
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(2)
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wells which were shut-in for market conditions or pipeline connections; or
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(3)
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wells not capable of production for mechanical reasons.
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(i)
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Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
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/s/ James L. Baird
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/s/ Clark D. Parrott
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James L. Baird, P.E.
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Clark D. Parrott, P.E.
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Colorado License No. 41521
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Colorado License No. 35262
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Managing Senior Vice President
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Senior Petroleum Engineer
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TBPE REGISTERED ENGINEERING FIRM F-1580
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FAX (303) 623-4258
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621 SEVENTEENTH STREET SUITE 1550
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DENVER, COLORADO 80293
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TELEPHONE (303) 623-9147
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As of December 31, 2016
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Proved
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Developed Producing
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Undeveloped
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Total Proved
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Audited by Ryder Scott
Net Reserves
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Oil/Condensate – MBarrels
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108,707
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154,983
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263,690
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Plant Products – MBarrels
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11,247
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15,564
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26,811
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Gas – MMCF
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70,913
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96,536
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167,449
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Geographic Area
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Product
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Price
Reference
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Average
Benchmark
Prices
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Average Realized
Prices
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North America
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Oil/Condensate
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WTI Cushing
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$42.75/Bbl
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$38.75/Bbl
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United States
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NGLs
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WTI Cushing
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$42.75/Bbl
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$28.89/Bbl
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Gas
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Henry Hub
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$2.49/MMBTU
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$2.09/MCF
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NETHERLAND, SEWELL & ASSOCIATES, INC.
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Texas Registered Engineering Firm F-2699
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By:
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/s/ C.H. (Scott) Rees III
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C.H. (Scott) Rees III, P.E.
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Chairman and Chief Executive Officer
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By:
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/s/ John R. Cliver
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By:
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/s/ Zachary R. Long
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John R. Cliver, P.E. 107216
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Zachary R. Long, P.G. 11792
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Vice President
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Vice President
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Date Signed: November 20, 2017
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Date Signed: November 20, 2017
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(i)
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Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
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(ii)
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Same environment of deposition;
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(iii)
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Similar geological structure; and
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(iv)
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Same drive mechanism.
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(i)
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Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
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(ii)
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Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
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(i)
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Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.
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(ii)
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Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
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(iii)
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Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.
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(iv)
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Provide improved recovery systems.
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(i)
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Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.
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(ii)
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Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.
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(iii)
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Dry hole contributions and bottom hole contributions.
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(iv)
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Costs of drilling and equipping exploratory wells.
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(v)
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Costs of drilling exploratory-type stratigraphic test wells.
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(i)
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Oil and gas producing activities include:
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(A)
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The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;
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(B)
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The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;
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(C)
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The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:
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(1)
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Lifting the oil and gas to the surface; and
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(2)
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Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and
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(D)
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Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.
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a.
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The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and
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b.
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In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.
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(ii)
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Oil and gas producing activities do not include:
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(A)
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Transporting, refining, or marketing oil and gas;
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(B)
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Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;
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(C)
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Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or
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(D)
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Production of geothermal steam.
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(i)
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When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods
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(ii)
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Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
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(iii)
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Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
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(iv)
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The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
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(v)
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Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
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(vi)
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Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.
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(i)
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When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
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(ii)
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Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
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(iii)
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Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
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(iv)
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See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.
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(i)
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Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:
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(A)
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Costs of labor to operate the wells and related equipment and facilities.
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(B)
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Repairs and maintenance.
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(C)
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Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.
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(D)
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Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.
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(E)
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Severance taxes.
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(ii)
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Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.
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(i)
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The area of the reservoir considered as proved includes:
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(A)
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The area identified by drilling and limited by fluid contacts, if any, and
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(B)
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Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
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(ii)
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In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
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(iii)
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Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
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(iv)
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Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
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(A)
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Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
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(B)
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The project has been approved for development by all necessary parties and entities, including governmental entities.
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(v)
|
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
|
(i)
|
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
|
(ii)
|
Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
|
•
|
The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);
|
•
|
The company's historical record at completing development of comparable long-term projects;
|
•
|
The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;
|
•
|
The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and
|
•
|
The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).
|
(iii)
|
Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
|
|
|
|
|
Page(s)
|
Independent Auditor’s Report
|
|
|
1
|
Financial Statements
|
|
|
|
Balance Sheets
|
|
|
2
|
Statements of Income
|
|
|
3
|
Statements of Stockholders’ Equity
|
|
|
4
|
Statements of Cash Flows
|
|
|
5
|
Notes to Financial Statements
|
|
|
6-11
|
|
|
|
|
|
|
|
|
|
(in thousands of dollars)
|
|
2017
|
|
2016
|
||||
|
|
|
|
|
||||
Assets
|
|
|
|
|
||||
Cash and cash equivalents
|
|
$
|
142,449
|
|
|
$
|
77,459
|
|
Accounts receivable
|
|
29,607
|
|
|
30,512
|
|
||
Accounts receivable–related parties
|
|
14,731
|
|
|
10,858
|
|
||
Inventory
|
|
37,693
|
|
|
37,037
|
|
||
Total current assets
|
|
224,480
|
|
|
155,866
|
|
||
Facility cost
|
|
567,667
|
|
|
567,615
|
|
||
Less: Accumulated depreciation
|
|
335,096
|
|
|
323,863
|
|
||
Net facility cost
|
|
232,571
|
|
|
243,752
|
|
||
Total assets
|
|
$
|
457,051
|
|
|
$
|
399,618
|
|
|
|
|
|
|
||||
Liabilities and Stockholders' Equity
|
|
|
|
|
||||
Accounts payable and accrued liabilities–related parties
|
|
7,053
|
|
|
6,991
|
|
||
Accrued government royalty–net profit interest
|
|
28,377
|
|
|
17,536
|
|
||
Foreign income taxes payable
|
|
74,322
|
|
|
35,935
|
|
||
Total current liabilities
|
|
109,752
|
|
|
60,462
|
|
||
Net Deferred tax liability
|
|
46,845
|
|
|
40,018
|
|
||
Stockholders' equity
|
|
|
|
|
||||
Common stock - 1,000 shares issued and outstanding
|
|
1
|
|
|
1
|
|
||
(par value $1.00 per share, 50,000 shares authorized)
|
|
|
|
|
||||
Retained earnings
|
|
300,453
|
|
|
299,137
|
|
||
Total stockholders' equity
|
|
300,454
|
|
|
299,138
|
|
||
Total liabilities and stockholders' equity
|
|
$
|
457,051
|
|
|
$
|
399,618
|
|
|
(in thousands of dollars)
|
|
2017
|
|
2016
|
||||
|
|
|
|
|
||||
Revenues
|
|
|
|
|
||||
Plant products
|
|
$
|
298,923
|
|
|
$
|
186,754
|
|
Plant products–related parties
|
|
799
|
|
|
931
|
|
||
Condensate–related parties
|
|
131,923
|
|
|
102,687
|
|
||
Other income
|
|
962
|
|
|
850
|
|
||
Other income–related parties
|
|
286
|
|
|
271
|
|
||
Total revenues
|
|
432,893
|
|
|
291,493
|
|
||
|
|
|
|
|
||||
Expenses
|
|
|
|
|
||||
Direct operating–related parties
|
|
37,331
|
|
|
47,929
|
|
||
Depreciation and amortization
|
|
11,233
|
|
|
26,555
|
|
||
General and administrative–related parties
|
|
28,165
|
|
|
28,770
|
|
||
Government royalty–net profit interest
|
|
28,380
|
|
|
17,536
|
|
||
Shipping and handling–related parties
|
|
3,543
|
|
|
4,088
|
|
||
Total expenses
|
|
108,652
|
|
|
124,878
|
|
||
Income from operations
|
|
324,241
|
|
|
166,615
|
|
||
Interest income
|
|
227
|
|
|
—
|
|
||
Income before income taxes
|
|
324,468
|
|
|
166,615
|
|
||
Income tax expense
|
|
81,152
|
|
|
41,637
|
|
||
Net income
|
|
$
|
243,316
|
|
|
$
|
124,978
|
|
|
|
|
|
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|||||||
|
|
Common Stock
|
|
Retained
|
|
Stockholders'
|
|||||||||
(in thousands)
|
|
Shares
|
|
Amount
|
|
Earnings
|
|
Equity
|
|||||||
|
|
|
|
|
|
|
|
|
|||||||
Balances at December 31, 2015
|
|
1
|
|
|
$
|
1
|
|
|
$
|
316,159
|
|
|
$
|
316,160
|
|
Net income
|
|
|
|
|
|
124,978
|
|
|
124,978
|
|
|||||
Dividends
|
|
|
|
|
|
(142,000
|
)
|
|
(142,000
|
)
|
|||||
Balances at December 31, 2016
|
|
1
|
|
|
1
|
|
|
299,137
|
|
|
299,138
|
|
|||
Net income
|
|
|
|
|
|
243,316
|
|
|
243,316
|
|
|||||
Dividends
|
|
|
|
|
|
(242,000
|
)
|
|
(242,000
|
)
|
|||||
Balances at December 31, 2017
|
|
1
|
|
|
$
|
1
|
|
|
$
|
300,453
|
|
|
$
|
300,454
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands of dollars)
|
|
2017
|
|
2016
|
||||
|
|
|
|
|
||||
Operating activities
|
|
|
|
|
||||
Net income
|
|
$
|
243,316
|
|
|
$
|
124,978
|
|
Adjustments to reconcile net income to net cash provided by operating activities
|
|
|
|
|
||||
Depreciation and amortization
|
|
11,233
|
|
|
26,555
|
|
||
Deferred income tax
|
|
6,827
|
|
|
5,723
|
|
||
Changes in:
|
|
|
|
|
||||
Accounts receivable and accounts receivable-related parties
|
|
(2,968
|
)
|
|
(16,518
|
)
|
||
Prepayments
|
|
—
|
|
|
1,299
|
|
||
Inventory
|
|
(656
|
)
|
|
5,883
|
|
||
Accounts payable and accrued liabilities-related parties
|
|
75
|
|
|
(5,668
|
)
|
||
Accrued government royalty–net profit interest
|
|
10,841
|
|
|
804
|
|
||
Foreign income taxes payable
|
|
38,387
|
|
|
6,618
|
|
||
Net cash provided by operating activities
|
|
307,055
|
|
|
149,674
|
|
||
Investing activities
|
|
|
|
|
||||
Capital expenditures
|
|
(65
|
)
|
|
(120
|
)
|
||
Net cash used in investing activities
|
|
(65
|
)
|
|
(120
|
)
|
||
Financing activities
|
|
|
|
|
||||
Dividends
|
|
(242,000
|
)
|
|
(142,000
|
)
|
||
Net cash used in financing activities
|
|
(242,000
|
)
|
|
(142,000
|
)
|
||
Net increase (decrease) in cash and cash equivalents
|
|
64,990
|
|
|
7,554
|
|
||
Cash and cash equivalents at beginning of period
|
|
$
|
77,459
|
|
|
$
|
69,905
|
|
Cash and cash equivalents at end of period
|
|
$
|
142,449
|
|
|
$
|
77,459
|
|
Supplemental disclosure
|
|
|
|
|
||||
Income taxes paid
|
|
$
|
35,939
|
|
|
$
|
29,296
|
|
Change in Capital expenditure accrual
|
|
$
|
(13
|
)
|
|
$
|
(79
|
)
|
|
|
|
|
|
|
1.
|
Organization and Nature of Business
|
Samedan of North Africa, LLC ("Samedan")
|
|
34.79166%
|
Marathon E.G. LPG Limited ("EG LPG")
|
|
23.45834
|
Marathon E.G. Alba Limited ("EG Alba")
|
|
19.08334
|
Marathon E.G. Production Limited ("MEGPL")
|
|
11.45833
|
Marathon E.G. Offshore Limited ("EG Offshore")
|
|
11.20833
|
|
|
100.00000%
|
2.
|
Summary of Significant Accounting Policies
|
|
|
3.
|
Accounting Standards
|
|
4.
|
Inventory
|
(in thousands of dollars)
|
|
2017
|
|
2016
|
||||
|
|
|
|
|
||||
Materials and supplies
|
|
$
|
37,074
|
|
|
$
|
36,381
|
|
Liquid hydrocarbon products
|
|
619
|
|
|
656
|
|
||
|
|
$
|
37,693
|
|
|
$
|
37,037
|
|
|
|
|
|
|
5.
|
Income Taxes
|
(in thousands of dollars)
|
|
2017
|
|
2016
|
||||
|
|
|
|
|
||||
Current tax expense
|
|
$
|
74,325
|
|
|
$
|
35,914
|
|
Deferred tax expense
|
|
6,827
|
|
|
5,723
|
|
||
|
|
$
|
81,152
|
|
|
$
|
41,637
|
|
(in thousands of dollars)
|
|
2017
|
|
2016
|
||||
|
|
|
|
|
||||
Deferred tax assets
|
|
|
|
|
||||
Government royalty - net profit interest
|
|
$
|
7,094
|
|
|
$
|
4,384
|
|
|
|
$
|
7,094
|
|
|
$
|
4,384
|
|
Deferred tax liability
|
|
|
|
|
||||
Facility cost
|
|
$
|
53,939
|
|
|
$
|
44,402
|
|
|
|
$
|
53,939
|
|
|
$
|
44,402
|
|
|
|
|
|
|
||||
|
|
|
|
|
||||
Net deferred tax liabilities
|
|
$
|
46,845
|
|
|
$
|
40,018
|
|
|
6.
|
Related Party Transactions
|
•
|
Alba Associates LLC and Sonagas, the Company’s owners;
|
•
|
Samedan, EG LPG, EG Alba, MEGPL, and EG Offshore, the owners in Alba Associates LLC; and
|
•
|
Marathon Oil Marketing, Ltd. (“MOM”), Marathon International Oil (G.B.) Limited (“MIOGB”), Equatorial Guinea LNG Train1, S.A. (“EG LNG”) and other affiliates of Marathon Oil Corporation (“Marathon”), which is one of the ultimate owners of Alba Associates LLC.
|
|
|
2017
|
|
2016
|
||||||||||||
(in thousands of dollars)
|
|
Receivable from
|
|
Payable to
|
|
Receivable from
|
|
Payable to
|
||||||||
|
|
|
|
|
|
|
|
|
||||||||
Sonagas
|
|
$
|
1,538
|
|
|
$
|
—
|
|
|
$
|
681
|
|
|
$
|
—
|
|
MOM
|
|
13,174
|
|
|
10
|
|
|
10,126
|
|
|
—
|
|
||||
MIOGB
|
|
—
|
|
|
4
|
|
|
—
|
|
|
—
|
|
||||
MEGPL
|
|
17
|
|
|
7,026
|
|
|
18
|
|
|
6,979
|
|
||||
Marathon
|
|
2
|
|
|
13
|
|
|
—
|
|
|
12
|
|
||||
EG LNG
|
|
—
|
|
|
—
|
|
|
33
|
|
|
—
|
|
||||
|
|
$
|
14,731
|
|
|
$
|
7,053
|
|
|
$
|
10,858
|
|
|
$
|
6,991
|
|
|
7.
|
Fair Value of Financial Instruments
|
8.
|
Dividends
|
9.
|
Contingencies
|
10.
|
Subsequent Events
|