Delaware
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73-0785597
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(State of incorporation)
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(I.R.S. employer identification number)
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1001 Noble Energy Way
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|
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Houston, Texas
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77070
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(Address of principal executive offices)
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(Zip Code)
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Title of each class
|
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Name of each exchange on which registered
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Common Stock, $0.01 par value
|
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New York Stock Exchange
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Large accelerated filer
x
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Accelerated filer
o
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Non-accelerated filer
o
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Smaller reporting company
o
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(Do not check if a smaller reporting company)
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PART I
|
||
Items 1. and 2.
|
||
Item 1A.
|
||
Item 1B.
|
||
Item 3.
|
||
Item 4.
|
||
PART II
|
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Item 5.
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||
Item 6.
|
||
Item 7.
|
||
Item 7A.
|
||
Item 8.
|
||
Item 9.
|
||
Item 9A.
|
||
Item 9B.
|
||
PART III
|
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Item 10.
|
||
Item 11.
|
||
Item 12.
|
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Item 13.
|
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Item 14.
|
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PART IV
|
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Item 15.
|
||
Item 16.
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•
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our growth strategies;
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•
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our future results of operations;
|
•
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our liquidity and ability to finance our exploration, development, and acquisition activities;
|
•
|
our ability to make and integrate acquisitions;
|
•
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our ability to successfully and economically explore for and develop crude oil, natural gas and natural gas liquids (NGLs) resources;
|
•
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anticipated trends in our business;
|
•
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market conditions in the oil and gas industry;
|
•
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the impact of governmental fiscal regulation, including federal, state, local, and foreign host tax regulations, and/or terms, such as that involving the protection of the environment or marketing of production, as well as other regulations; and
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•
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access to resources.
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•
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United States, including the onshore DJ Basin, Permian Basin, Eagle Ford Shale, Marcellus Shale, and offshore deepwater Gulf of Mexico, as well as the consolidated accounts of Noble Midstream Partners LP (Noble Midstream Partners), which completed its initial public offering of common units in 2016;
|
•
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Eastern Mediterranean, including offshore Israel and Cyprus;
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•
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West Africa, including offshore Equatorial Guinea, Cameroon, and Gabon; and
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•
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Other International and Corporate, including new ventures such as offshore the Falkland Islands, Suriname, and Newfoundland.
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|
December 31, 2016
|
||||||||||
|
|
Proved Reserves
|
||||||||||
|
|
Crude Oil and
Condensate
|
|
Natural Gas
|
|
NGLs
|
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Total
|
||||
Reserves Category
|
|
(MMBbls)
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(Bcf)
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(MMBbls)
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(MMBoe)
(1)
|
||||
Proved Developed
|
|
|
|
|
|
|
|
|
||||
United States
|
|
138
|
|
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1,817
|
|
|
113
|
|
|
554
|
|
Israel
|
|
3
|
|
|
1,600
|
|
|
—
|
|
|
270
|
|
Equatorial Guinea
|
|
34
|
|
|
486
|
|
|
12
|
|
|
127
|
|
Total Proved Developed Reserves
|
|
175
|
|
|
3,903
|
|
|
125
|
|
|
951
|
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Proved Undeveloped
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
158
|
|
|
1,021
|
|
|
94
|
|
|
422
|
|
Israel
|
|
—
|
|
|
384
|
|
|
—
|
|
|
64
|
|
Total Proved Undeveloped Reserves
|
|
158
|
|
|
1,405
|
|
|
94
|
|
|
486
|
|
Total Proved Reserves
|
|
333
|
|
|
5,308
|
|
|
219
|
|
|
1,437
|
|
•
|
positive revisions of 117 MMBoe related to our onshore US horizontal drilling programs and Alba field, offshore Equatorial Guinea, driven by increased well performance and/or lower operating or development costs in onshore US and the startup of the Alba B3 compression platform; and
|
•
|
extensions and other additions of
179
MMBoe related to our onshore US horizontal drilling programs due to
successful expansion of our extended reach lateral well programs;
|
•
|
production volumes of
154
MMBoe;
|
•
|
negative revisions of
53
MMBoe that were commodity price driven; and
|
•
|
reduction of
77
MMBoe primarily due to our 3.5% reduction in ownership in Tamar, the impact of the Marcellus Shale acreage exchange, and other smaller onshore US divestitures.
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|
|
Year Ended December 31, 2016
|
|
December 31, 2016
|
|||||||||||||||||||||||
|
|
Sales Volumes
|
|
Proved Reserves
|
|||||||||||||||||||||||
|
|
Crude Oil &
Condensate
|
|
Natural
Gas
|
|
NGLs
|
|
Total
|
|
Crude Oil &
Condensate
|
|
Natural
Gas
|
|
NGLs
|
|
Total
|
|||||||||||
|
|
(MBbl/d)
|
|
(MMcf/d)
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|
(MBbl/d)
|
|
(MBoe/d)
|
|
(MMBbls)
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(Bcf)
|
|
(MMBbls)
|
|
(MMBoe)
|
|||||||||||
DJ Basin
|
|
56
|
|
|
225
|
|
|
21
|
|
|
114
|
|
|
177
|
|
|
981
|
|
|
80
|
|
|
421
|
|
|||
Eagle Ford Shale
|
|
10
|
|
|
129
|
|
|
22
|
|
|
54
|
|
|
30
|
|
|
453
|
|
|
76
|
|
|
181
|
|
|||
Permian Basin
|
|
6
|
|
|
9
|
|
|
2
|
|
|
9
|
|
|
56
|
|
|
75
|
|
|
13
|
|
|
82
|
|
|||
Marcellus Shale
|
|
1
|
|
|
486
|
|
|
8
|
|
|
91
|
|
|
5
|
|
|
1,275
|
|
|
36
|
|
|
253
|
|
|||
Deepwater Gulf of Mexico
|
|
25
|
|
|
20
|
|
|
1
|
|
|
30
|
|
|
24
|
|
|
30
|
|
|
2
|
|
|
31
|
|
|||
Other Onshore US
|
|
1
|
|
—
|
|
12
|
|
—
|
|
—
|
|
—
|
|
3
|
|
|
4
|
|
|
24
|
|
|
—
|
|
|
8
|
|
Total
|
|
99
|
|
|
881
|
|
|
54
|
|
|
301
|
|
|
296
|
|
|
2,838
|
|
|
207
|
|
|
976
|
|
|
|
Year Ended December 31, 2016
|
|
December 31, 2016
|
||
|
|
Gross Wells Drilled
or Participated in
(1)
|
|
Gross Productive
Wells
|
||
DJ Basin
|
|
134
|
|
|
6,961
|
|
Eagle Ford Shale
|
|
22
|
|
|
318
|
|
Permian Basin
|
|
19
|
|
|
242
|
|
Marcellus Shale
|
|
17
|
|
|
238
|
|
Deepwater Gulf of Mexico
|
|
2
|
|
|
15
|
|
Other Onshore US
|
|
—
|
|
|
21
|
|
Total
|
|
194
|
|
|
7,795
|
|
(1)
|
Excludes exploratory wells drilled and suspended awaiting a sanctioned development plan or being assessed for economic viability. See Drilling Activity, below.
|
•
|
closed an acreage exchange agreement to receive approximately 11,700 net acres within our Wells Ranch development area in exchange for approximately 13,500 net acres primarily from our Bronco development area, located southwest of Wells Ranch. The exchange enhances our ability to develop the field by improving our contiguous acreage position, increasing our lateral length potential and optimizing our access to central gathering facilities;
|
•
|
entered into an agreement to divest approximately 33,100 producing and undeveloped net acres in the Greeley Crescent area of Weld County, Colorado for $505 million, representing approximately 8% of our total DJ Basin acreage. We received proceeds of $486 million in
2016
and expect to receive the remaining proceeds in mid-2017. Proceeds received were applied to the field's basis with no recognition of gain or loss. As part of the transaction, all of the acreage in the Greeley Crescent IDP remains subject to dedications to Noble Midstream Partners for crude oil gathering, produced water services and fresh water services; and
|
•
|
sold certain other producing and non-producing assets, generating net proceeds of $20 million, which were applied to the field basis, with no recognition of gain or loss.
|
|
|
Year Ended December 31, 2016
|
|
December 31, 2016
|
||
|
|
Gross Wells Drilled
or Participated in
|
|
Gross Productive
Wells
|
||
International
|
|
|
|
|
||
Israel
|
|
—
|
|
|
8
|
|
Equatorial Guinea
|
|
—
|
|
|
26
|
|
Total International
|
|
—
|
|
|
34
|
|
•
|
the Audit Committee of our Board of Directors reviews significant reserves changes on an annual basis;
|
•
|
fields that meet a minimum reserve quantity threshold, newly sanctioned development projects, and certain fields selected on a rotational basis, which combined represent over 80% of our proved reserves, are audited by Netherland, Sewell & Associates, Inc. (NSAI), a third-party petroleum consulting firm, on an annual basis; and
|
•
|
NSAI is engaged by, and has direct access to, the Audit Committee. See Third-Party Reserves Audit, below.
|
|
|
Year Ended December 31,
|
|||||||
|
|
2016
|
|
2015
|
|
2014
|
|||
(MMBoe)
|
|
|
|
|
|
|
|||
Proved Reserves Beginning of Year
|
|
1,421
|
|
|
1,404
|
|
|
1,406
|
|
Revisions of Previous Estimates
|
|
64
|
|
|
(216
|
)
|
|
21
|
|
Extensions, Discoveries and Other Additions
|
|
179
|
|
|
100
|
|
|
120
|
|
Purchase of Minerals in Place
|
|
4
|
|
|
269
|
|
|
—
|
|
Sale of Minerals in Place
|
|
(77
|
)
|
|
(6
|
)
|
|
(33
|
)
|
Production
|
|
(154
|
)
|
|
(130
|
)
|
|
(110
|
)
|
Proved Reserves End of Year
|
|
1,437
|
|
|
1,421
|
|
|
1,404
|
|
•
|
changes for the year ended
December 31, 2016
include positive revisions of 43 MMBoe for the DJ Basin, 42 MMBoe for the Marcellus Shale, 11 MMBoe for the Permian Basin, 6 MMBoe for deepwater Gulf of Mexico, 5 MMBoe for other onshore US and 10 MMBoe for Alba field, offshore Equatorial Guinea, due to increased performance and/or lower development or operating costs; partially offset by negative revisions of
53
MMBoe due to lower commodity prices;
|
•
|
changes for the year ended
December 31, 2015
include negative revisions of 307 MMBoe due to lower commodity prices, downward revisions of 9 MMBoe and 5 MMBoe for the DJ Basin and Eagle Ford Shale, respectively, primarily due to current drilling and development plans in the DJ Basin and expected reserve recovery from existing producing wells in the Eagle Ford Shale, and downward revisions of 3 MMBoe due to natural field decline from the Mari-B field,
|
•
|
changes for the year ended
December 31, 2014
included positive performance revisions of 18 MMBoe for the Marcellus Shale, 4 MMBoe for deepwater Gulf of Mexico, 4 MMBoe for Alba field, and 3 MMBoe for the Tamar field; offset by a downward revision of 8 MMBoe for the DJ Basin primarily due to planned reduction in pace of drilling activity due to lower commodity prices.
|
•
|
changes for the year ended
December 31, 2016
include increases of 83 MMBoe in the DJ Basin, 42 MMBoe in the Marcellus Shale, 33 MMBoe in the Permian Basin and 21 MMBoe in the Eagle Ford Shale, all associated with our horizontal drilling programs;
|
•
|
changes for the year ended December 31, 2015 include increases of 86 MMBoe in the DJ Basin and 14 MMBoe in the Marcellus Shale associated with our horizontal drilling programs; and
|
•
|
changes for the year ended December 31, 2014 included increases of 48 MMBoe in the DJ Basin, 62 MMBoe in the Marcellus Shale, and 10 MMBoe deepwater Gulf of Mexico primarily attributable to sanction of the Dantzler development.
|
•
|
an increase of
4
MMBoe of NGL reserves primarily resulting from our Marcellus Shale acreage exchange in 2016; and
|
•
|
the acquisition of additional acreage, primarily in the Eagle Ford Shale and Permian Basin in Texas in 2015 in connection with the Rosetta Merger.
|
•
|
a reduction of
36
MMBoe in Israel driven by our 3.5% sale of Tamar working interest, divestment of
29
MMBoe in the Marcellus Shale driven by our asset exchange, and other smaller divestments in onshore US resulting in a reduction of
12
MMBoe in 2016;
|
•
|
the sale of onshore US assets in 2015; and
|
•
|
the sale of onshore US and China assets in 2014.
|
|
|
United
States
|
|
Israel
|
|
Equatorial
Guinea
|
|
Total
|
||||
(MMBoe)
|
|
|
|
|
|
|
|
|
||||
Proved Undeveloped Reserves Beginning of Year
|
|
344
|
|
|
71
|
|
|
70
|
|
|
485
|
|
Revisions of Previous Estimates
|
|
32
|
|
|
—
|
|
|
—
|
|
|
32
|
|
Extensions, Discoveries and Other Additions
|
|
166
|
|
|
—
|
|
|
—
|
|
|
166
|
|
Purchase of Minerals in Place
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Sale of Minerals in Place
|
|
(22
|
)
|
|
(7
|
)
|
|
—
|
|
|
(29
|
)
|
Conversion to Proved Developed
|
|
(98
|
)
|
|
—
|
|
|
(70
|
)
|
|
(168
|
)
|
Proved Undeveloped Reserves End of Year
|
|
422
|
|
|
64
|
|
|
—
|
|
|
486
|
|
•
|
53 MMBoe positive revisions primarily in the DJ Basin, Marcellus Shale and Permian Basin due to current drilling and development plans;
|
•
|
negative revisions of 21 MMBoe due to lower commodity prices.
|
•
|
76 MMBoe in the DJ Basin;
|
•
|
31 MMBoe in the Permian Basin;
|
•
|
19 MMBoe in the Eagle Ford Shale; and
|
•
|
40 MMBoe in the Marcellus Shale.
|
•
|
26 MMBoe in the DJ Basin;
|
•
|
1 MMBoe in the Permian;
|
•
|
25 MMBoe in the Eagle Ford Shale;
|
•
|
33 MMBoe in the Marcellus Shale;
|
•
|
13 MMBoe in deepwater Gulf of Mexico; and
|
•
|
70 MMBoe in the Alba Field, offshore Equatorial Guinea.
|
•
|
199
MMBoe in the DJ Basin;
|
•
|
70 MMBoe in the Permian Basin;
|
•
|
92 MMBoe in the Eagle Ford Shale; and
|
•
|
61 MMBoe in the Marcellus Shale.
|
•
|
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies and Estimates – Reserves
for further discussion of our reserves estimation process; and
|
•
|
Item 8. Financial Statements and Supplementary Data – Supplementary Oil and Gas Information (Unaudited)
for additional information regarding estimates of crude oil, natural gas and NGL reserves, including estimates of proved, proved developed, and proved undeveloped reserves, the standardized measure of discounted future net cash flows, and the changes in the standardized measure of discounted future net cash flows.
|
|
|
Sales Volumes
|
|
Average Sales Price
|
|
Production
Cost
(1)
|
|||||||||||||||||||
|
|
Crude Oil &
Condensate
MBbl
|
|
Natural Gas
MMcf
|
|
NGLs
MBbl
|
|
Crude Oil &
Condensate
Per Bbl
|
|
Natural Gas
Per Mcf
|
|
NGLs Per
Bbl
|
|
Per BOE
|
|||||||||||
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
DJ Basin
|
|
20,342
|
|
|
82,431
|
|
|
7,651
|
|
|
$
|
40.85
|
|
|
$
|
2.80
|
|
|
$
|
14.66
|
|
|
$
|
3.43
|
|
Marcellus Shale
|
|
431
|
|
|
177,872
|
|
|
3,094
|
|
|
28.25
|
|
|
1.68
|
|
|
16.34
|
|
|
0.90
|
|
||||
Other US
|
|
15,572
|
|
|
62,017
|
|
|
9,087
|
|
|
38.26
|
|
|
2.42
|
|
|
14.65
|
|
|
6.26
|
|
||||
Total US
|
|
36,345
|
|
|
322,320
|
|
|
19,832
|
|
|
39.59
|
|
|
2.11
|
|
|
14.92
|
|
|
3.57
|
|
||||
Israel
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Tamar Field
|
|
140
|
|
|
102,280
|
|
|
—
|
|
|
36.67
|
|
|
5.22
|
|
|
—
|
|
|
2.58
|
|
||||
Other Israel
|
|
—
|
|
|
528
|
|
|
—
|
|
|
—
|
|
|
3.20
|
|
|
—
|
|
|
N/M
|
|
||||
Total Israel
|
|
140
|
|
|
102,808
|
|
|
—
|
|
|
36.67
|
|
|
5.21
|
|
|
—
|
|
|
2.60
|
|
||||
Equatorial Guinea
(2)
|
|
9,415
|
|
|
85,987
|
|
|
—
|
|
|
43.54
|
|
|
0.27
|
|
|
—
|
|
|
4.40
|
|
||||
Total Consolidated Operations
|
|
45,900
|
|
|
511,115
|
|
|
19,832
|
|
|
40.39
|
|
|
2.42
|
|
|
14.92
|
|
|
$
|
3.59
|
|
|||
Equity Investee
(3)
|
|
629
|
|
|
—
|
|
|
1,993
|
|
|
45.44
|
|
|
—
|
|
|
26.30
|
|
|
N/M
|
|
||||
Total
|
|
46,529
|
|
|
511,115
|
|
|
21,825
|
|
|
$
|
40.46
|
|
|
$
|
2.42
|
|
|
$
|
15.96
|
|
|
N/M
|
|
|
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
DJ Basin
|
|
20,909
|
|
|
85,369
|
|
|
6,910
|
|
|
$
|
44.37
|
|
|
$
|
2.53
|
|
|
$
|
14.21
|
|
|
$
|
5.51
|
|
Marcellus Shale
|
|
673
|
|
|
143,465
|
|
|
3,480
|
|
|
22.39
|
|
|
1.75
|
|
|
14.04
|
|
|
1.40
|
|
||||
Other US
|
|
7,680
|
|
|
29,806
|
|
|
3,705
|
|
|
42.83
|
|
|
2.56
|
|
|
13.25
|
|
|
6.07
|
|
||||
Total US
|
|
29,262
|
|
|
258,640
|
|
|
14,095
|
|
|
43.46
|
|
|
2.10
|
|
|
13.91
|
|
|
4.28
|
|
||||
Israel
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Tamar Field
|
|
121
|
|
|
91,884
|
|
|
—
|
|
|
46.91
|
|
|
5.34
|
|
|
—
|
|
|
3.12
|
|
||||
Other Israel
|
|
—
|
|
|
136
|
|
|
—
|
|
|
—
|
|
|
3.01
|
|
|
—
|
|
|
N/M
|
|
||||
Total Israel
|
|
121
|
|
|
92,020
|
|
|
—
|
|
|
46.91
|
|
|
5.34
|
|
|
—
|
|
|
3.15
|
|
||||
Equatorial Guinea
(2)
|
|
11,416
|
|
|
82,729
|
|
|
—
|
|
|
48.85
|
|
|
0.27
|
|
|
—
|
|
|
5.22
|
|
||||
United Kingdom
|
|
88
|
|
|
49
|
|
|
—
|
|
|
55.52
|
|
|
6.32
|
|
|
—
|
|
|
N/M
|
|
||||
Total Consolidated Operations
|
|
40,887
|
|
|
433,438
|
|
|
14,095
|
|
|
45.00
|
|
|
2.44
|
|
|
13.91
|
|
|
$
|
4.43
|
|
|||
Equity Investee
(3)
|
|
554
|
|
|
—
|
|
|
1,850
|
|
|
48.85
|
|
|
—
|
|
|
28.40
|
|
|
N/M
|
|
||||
Total
|
|
41,441
|
|
|
433,438
|
|
|
15,945
|
|
|
$
|
45.05
|
|
|
$
|
2.44
|
|
|
$
|
15.59
|
|
|
N/M
|
|
|
Year Ended December 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
DJ Basin
|
|
18,209
|
|
|
75,039
|
|
|
6,072
|
|
|
$
|
87.86
|
|
|
$
|
4.11
|
|
|
$
|
34.51
|
|
|
$
|
6.00
|
|
Marcellus Shale
|
|
239
|
|
|
95,564
|
|
|
1,812
|
|
|
69.50
|
|
|
3.57
|
|
|
31.67
|
|
|
1.55
|
|
||||
Other US
|
|
5,845
|
|
|
18,211
|
|
|
532
|
|
|
95.84
|
|
|
4.35
|
|
|
32.14
|
|
|
7.40
|
|
||||
Total US
|
|
24,293
|
|
|
188,814
|
|
|
8,416
|
|
|
89.60
|
|
|
3.86
|
|
|
33.75
|
|
|
5.33
|
|
||||
Israel
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Tamar Field
|
|
109
|
|
|
79,828
|
|
|
—
|
|
|
89.62
|
|
|
5.68
|
|
|
—
|
|
|
2.81
|
|
||||
Other Israel
|
|
—
|
|
|
4,539
|
|
|
—
|
|
|
—
|
|
|
3.52
|
|
|
—
|
|
|
N/M
|
|
||||
Total Israel
|
|
109
|
|
|
84,367
|
|
|
—
|
|
|
89.62
|
|
|
5.57
|
|
|
—
|
|
|
3.84
|
|
||||
Equatorial Guinea
(2)
|
|
12,191
|
|
|
88,833
|
|
|
—
|
|
|
94.61
|
|
|
0.27
|
|
|
—
|
|
|
5.44
|
|
||||
China
|
|
788
|
|
|
—
|
|
|
—
|
|
|
103.74
|
|
|
—
|
|
|
—
|
|
|
8.53
|
|
||||
United Kingdom
|
|
159
|
|
|
56
|
|
|
—
|
|
|
102.02
|
|
|
16.26
|
|
|
—
|
|
|
N/M
|
|
||||
Total Consolidated Operations
|
|
37,540
|
|
|
362,070
|
|
|
8,416
|
|
|
91.58
|
|
|
3.38
|
|
|
33.75
|
|
|
$
|
5.31
|
|
|||
Equity Investee
(3)
|
|
605
|
|
|
—
|
|
|
1,934
|
|
|
96.53
|
|
|
—
|
|
|
62.89
|
|
|
N/M
|
|
||||
Total
|
|
38,145
|
|
|
362,070
|
|
|
10,350
|
|
|
$
|
91.65
|
|
|
$
|
3.38
|
|
|
$
|
39.19
|
|
|
N/M
|
|
(1)
|
Average production cost includes crude oil and natural gas operating costs and workover and repair expense and excludes production and ad valorem taxes and transportation expense.
|
(2)
|
Natural gas from the Alba field is under contract for $0.25 per MMBtu to a methanol plant, an LPG plant, an LNG plant and a power generation plant. The methanol and LPG plants are owned by affiliated entities accounted for under the equity method.
|
(3)
|
Volumes represent sales of condensate and LPG from the LPG plant in Equatorial Guinea.
|
|
|
Crude Oil Wells
|
|
Natural Gas Wells
|
|
Total
|
||||||||||||
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
United States
|
|
3,974
|
|
|
3,628
|
|
|
3,821
|
|
|
3,501
|
|
|
7,795
|
|
|
7,129
|
|
Israel
|
|
—
|
|
|
—
|
|
|
8
|
|
|
3
|
|
|
8
|
|
|
3
|
|
Equatorial Guinea
|
|
5
|
|
|
2
|
|
|
21
|
|
|
8
|
|
|
26
|
|
|
10
|
|
Total
|
|
3,979
|
|
|
3,630
|
|
|
3,850
|
|
|
3,512
|
|
|
7,829
|
|
|
7,142
|
|
|
|
Developed Acreage
|
|
Undeveloped Acreage
|
||||||||
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||
(thousands of acres)
|
|
|
|
|
|
|
|
|
||||
United States
|
|
|
|
|
|
|
|
|
||||
Onshore
|
|
902
|
|
|
768
|
|
|
694
|
|
|
430
|
|
Deepwater Gulf of Mexico
|
|
100
|
|
|
51
|
|
|
282
|
|
|
192
|
|
Total United States
|
|
1,002
|
|
|
819
|
|
|
976
|
|
|
622
|
|
International
|
|
|
|
|
|
|
|
|
|
|
|
|
Israel
|
|
185
|
|
|
78
|
|
|
284
|
|
|
116
|
|
Equatorial Guinea
(1)
|
|
284
|
|
|
118
|
|
|
26
|
|
|
10
|
|
Suriname
|
|
—
|
|
|
—
|
|
|
2,095
|
|
|
419
|
|
Newfoundland
|
|
—
|
|
|
—
|
|
|
1,942
|
|
|
525
|
|
Gabon
|
|
—
|
|
|
—
|
|
|
671
|
|
|
403
|
|
Cyprus
|
|
—
|
|
|
—
|
|
|
95
|
|
|
33
|
|
Falkland Islands
(2)
|
|
—
|
|
|
—
|
|
|
280
|
|
|
210
|
|
Cameroon
|
|
—
|
|
|
—
|
|
|
168
|
|
|
168
|
|
United Kingdom
|
|
2
|
|
|
—
|
|
|
4
|
|
|
1
|
|
Total International
|
|
471
|
|
|
196
|
|
|
5,565
|
|
|
1,885
|
|
Total
|
|
1,473
|
|
|
1,015
|
|
|
6,541
|
|
|
2,507
|
|
(1)
|
Undeveloped acreage excludes an exploration lease totaling approximately 55,000 gross (19,000 net) acres which expired in 2016. We are negotiating with the government of Equatorial Guinea to extend the lease.
|
(2)
|
Following completion of our geological assessment in 2016, we exited all licenses in the Falklands Islands, outside of License PL-001, which contains the Rhea prospect, thereby reducing our acreage position by approximately 10 million, gross, and 3 million, net, acres.
|
|
|
Year Ended December 31,
|
||||||||||||||||
|
|
2017
|
|
2018
|
|
2019
|
||||||||||||
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
(thousands of acres)
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Onshore US
|
|
156
|
|
|
103
|
|
|
143
|
|
|
41
|
|
|
113
|
|
|
73
|
|
Deepwater Gulf of Mexico
|
|
1
|
|
|
1
|
|
|
76
|
|
|
55
|
|
|
36
|
|
|
25
|
|
Falkland Islands
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
280
|
|
|
210
|
|
Suriname
|
|
—
|
|
|
—
|
|
|
2,095
|
|
|
419
|
|
|
—
|
|
|
—
|
|
Gabon
|
|
—
|
|
|
—
|
|
|
671
|
|
|
403
|
|
|
—
|
|
|
—
|
|
Total
|
|
157
|
|
|
104
|
|
|
2,985
|
|
|
918
|
|
|
429
|
|
|
308
|
|
|
|
Net Exploratory Wells
|
|
Net Development Wells
|
|
|
|||||||||||||||
|
|
Productive
|
|
Dry
|
|
Total
|
|
Productive
|
|
Dry
|
|
Total
|
|
Total
|
|||||||
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
United States
|
|
0.4
|
|
|
0.5
|
|
|
0.9
|
|
|
156.7
|
|
|
—
|
|
|
156.7
|
|
|
157.6
|
|
Total
|
|
0.4
|
|
|
0.5
|
|
|
0.9
|
|
|
156.7
|
|
|
—
|
|
|
156.7
|
|
|
157.6
|
|
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
United States
|
|
1.5
|
|
|
4.0
|
|
|
5.5
|
|
|
212.5
|
|
|
—
|
|
|
212.5
|
|
|
218.0
|
|
Equatorial Guinea
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.3
|
|
|
—
|
|
|
0.3
|
|
|
0.3
|
|
Falkland Islands
|
|
—
|
|
|
0.4
|
|
|
0.4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.4
|
|
Cameroon
|
|
—
|
|
|
0.5
|
|
|
0.5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.5
|
|
Total
|
|
1.5
|
|
|
4.9
|
|
|
6.4
|
|
|
212.8
|
|
|
—
|
|
|
212.8
|
|
|
219.2
|
|
Year Ended December 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
1.5
|
|
|
3.1
|
|
|
4.6
|
|
|
319.1
|
|
|
0.7
|
|
|
319.8
|
|
|
324.4
|
|
Total
|
|
1.5
|
|
|
3.1
|
|
|
4.6
|
|
|
319.1
|
|
|
0.7
|
|
|
319.8
|
|
|
324.4
|
|
|
|
Exploratory
(1)
|
|
Development
(2)
|
|
Total
|
||||||||||||
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
United States
|
|
5
|
|
|
4.0
|
|
|
142
|
|
|
128.9
|
|
|
147
|
|
|
132.9
|
|
Israel
|
|
4
|
|
|
1.5
|
|
|
1
|
|
|
0.3
|
|
|
5
|
|
|
1.8
|
|
Equatorial Guinea
|
|
2
|
|
|
0.9
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
0.9
|
|
Cameroon
|
|
1
|
|
|
1.0
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
1.0
|
|
Cyprus
|
|
2
|
|
|
0.7
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
0.7
|
|
Total
|
|
14
|
|
|
8.1
|
|
|
143
|
|
|
129.2
|
|
|
157
|
|
|
137.3
|
|
(1)
|
Includes exploratory wells drilled and suspended awaiting a sanctioned development plan or being evaluated to assess the economic viability of the well.
|
(2)
|
Includes wells pending completion activities.
|
•
|
the Ministry of Mines and Hydrocarbons, which, under such laws as the hydrocarbons law enacted in 2006 by the government of Equatorial Guinea, regulates our exploration, development and production activities offshore Equatorial Guinea;
|
•
|
the Ministry of National Infrastructures, Energy and Water Resources which regulates our exploration and development activities offshore Israel and the Israeli electricity market into which we sell our natural gas production;
|
•
|
the Israeli Antitrust Commission which reviews Israel's domestic natural gas sales and ownership in offshore blocks and leases;
|
•
|
the Ministry of Energy, Commerce, Industry and Tourism which regulates our exploration and development activities offshore Cyprus; and
|
•
|
the Department of Mineral Resources which regulates our exploration activities offshore the Falkland Islands.
|
•
|
the Bureau of Land Management (BLM), the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE), which under laws such as the Federal Land Policy and Management Act, Endangered Species Act, National Environmental Policy Act and Outer Continental Shelf Lands Act, have certain authority over our operations on federal lands and waters, particularly in the Rocky Mountains and deepwater Gulf of Mexico;
|
•
|
the Office of Natural Resources Revenue, which under the Federal Oil and Gas Royalty Management Act of 1982, has certain authority over our payment of royalties, rentals, bonuses, fines, penalties, assessments, and other revenue;
|
•
|
the US Environmental Protection Agency (EPA) and the Occupational Safety and Health Administration (OSHA), which under laws such as the Comprehensive Environmental Response, Compensation and Liability Act, the Resource Conservation and Recovery Act (RCRA), the Oil Pollution Act of 1990, the Clean Air Act, the Clean Water Act, the Safe Drinking Water Act, and the Occupational Safety and Health Act have certain authority over environmental, health and safety matters affecting our operations;
|
•
|
the US Fish and Wildlife Service (FWS) and US National Marine Fisheries Service, which under the Endangered Species Act have authority over activities that may result in the take of any endangered or threatened species or its habitat;
|
•
|
the US Army Corps of Engineers, which under the Clean Water Act has authority to regulate the construction of structures involving the fill of certain waters and wetlands subject to federal jurisdiction, including well pads, pipelines and roads;
|
•
|
the Federal Energy Regulatory Commission (FERC), which under laws such as the Energy Policy Act of 2005 has certain authority over the marketing and transportation of crude oil, natural gas and NGLs we produce onshore and from the deepwater Gulf of Mexico; and
|
•
|
the Department of Transportation (DOT), which has certain authority over the transportation of products, equipment and personnel necessary to our onshore US and deepwater Gulf of Mexico operations.
|
•
|
documentation of environmental changes that are coincident with shale gas production;
|
•
|
development of technology or management practices that mitigate any unintended environmental changes; and
|
•
|
development of monitoring technologies to (1) assess the impact of shale gas production on air quality and (2) determine if zonal isolation between producing formations and drinking water aquifers is maintained after hydraulic fracturing.
|
•
|
•
|
Item 1A. Risk Factors
; and
|
•
|
•
|
further significant reductions of our revenues, profit margins, operating income and cash flows;
|
•
|
reduction in the amount of crude oil, natural gas and NGLs that we can produce economically, leading to shut-in or early abandonment of producing wells and increased capital requirements for abandonment operations;
|
•
|
certain properties in our portfolio becoming economically unviable;
|
•
|
additional impairments of proved or unproved properties or other long-lived assets;
|
•
|
loss of undeveloped acreage if our production is shut-in or we are unable to make scheduled delay rental payments;
|
•
|
use of cash flow to satisfy minimum obligations under throughput agreements if production is suspended;
|
•
|
reduction, or suspension, of our 2017 capital investment program, or significant reductions in future capital investment programs, resulting in a reduced ability to develop our reserves;
|
•
|
delay, postponement or cancellation of some of our exploration or development projects;
|
•
|
inability to meet exploration commitments, leading to loss of leases or exploration rights;
|
•
|
divestments of properties to generate funds to meet cash flow or liquidity requirements;
|
•
|
limitations on our financial condition, liquidity, and/or ability to finance planned capital expenditures and operations;
|
•
|
inability to meet scheduled interest and/or debt payments or payments due under operating or capital leases;
|
•
|
a series of credit rating downgrades or other negative rating actions could increase our cost of financing, and may increase our requirements to post collateral as financial assurance of performance under certain other contracts which, in turn, could have a negative impact on our liquidity;
|
•
|
changes in corporate structure that could lead to loss of key personnel and interrupt our business activities;
|
•
|
limitations on our access to sources of capital, such as debt and equity; and
|
•
|
reduction or suspension of dividends on our common stock.
|
•
|
declines in our stock price; and
|
•
|
additional counterparty credit risk exposure on commodity hedges and joint venture receivables.
|
•
|
global demand for crude oil, natural gas and NGLs as impacted by economic factors that affect gross domestic product growth rates of countries around the world;
|
•
|
global supply for crude oil, natural gas and NGLs as impacted by OPEC and Non-OPEC countries (e.g. US, Russia, Canada);
|
•
|
technology advances that increase crude oil, natural gas and NGL production;
|
•
|
new technologies that promote fuel efficiency and reduce energy consumption;
|
•
|
developments in the global liquified natural gas (LNG) market, including exports from the US;
|
•
|
geopolitical conditions and events, including generational leadership or regime changes, changes in government energy policies, including imposed price controls and/or product subsidies, or instability/armed conflict in hydrocarbon-producing regions;
|
•
|
fluctuations in US dollar exchange rates, the currency in which the world's crude oil trade is generally denominated;
|
•
|
the price and availability of alternative fuels, including coal, solar, wind, nuclear energy and biofuels;
|
•
|
the long-term impact on the crude oil market of the use of natural gas as an alternative fuel for road transportation;
|
•
|
the availability of pipeline capacity/infrastructure as well as refining capacity;
|
•
|
the level and effect of trading in commodity futures markets, including by commodity price speculators and others;
|
•
|
the effectiveness of worldwide conservation measures;
|
•
|
weather conditions;
|
•
|
demand for electricity as well as natural gas used as fuel for electricity generation;
|
•
|
fuel efficiency regulations, such as the Corporate Average Fuel Economy (CAFE) standards, and its impacts on crude oil demand as a transportation fuel;
|
•
|
access to government-owned and other lands for exploration and production activities; and
|
•
|
domestic and foreign governmental regulations and taxes.
|
•
|
delay or reduce the profitability of our Tamar and/or Leviathan development projects;
|
•
|
delay or preclude closing of financing arrangements for our partners; and/or
|
•
|
render future exploration and development projects uneconomic.
|
•
|
renegotiation, modification or nullification of existing contracts, such as may occur pursuant to future regulations enacted as a result of changes in Israel's antitrust, export and natural gas development policies, or the hydrocarbons law enacted in 2006 by the government of Equatorial Guinea, which can result in an increase in the amount of revenues that the host government receives from production (government take) or otherwise decrease project profitability;
|
•
|
loss of revenue, property and equipment as a result of actions taken by host nations, such as expropriation or nationalization of assets or termination of contracts;
|
•
|
disruptions caused by territorial or boundary disputes in certain international regions;
|
•
|
changes in drilling or safety regulations in other countries;
|
•
|
laws and policies of the US and foreign jurisdictions affecting trade, foreign investment, taxation and business conduct;
|
•
|
potential for Israel natural gas production and regional exports to be interrupted by political conditions and events, and regional instability or armed conflict in the region;
|
•
|
difficulties enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations;
|
•
|
foreign exchange or repatriation restrictions;
|
•
|
war, piracy, acts of terrorism or civil unrest;
|
•
|
US and international monetary policies causing changes in the relative value of the US dollar as compared with the currencies of other countries in which we conduct business; and
|
•
|
other hazards arising out of foreign governmental sovereignty over areas in which we conduct operations.
|
•
|
restrict resource access or investment in lease holdings;
|
•
|
limit exploration activities, which could have a long-term negative impact on the quantities of proved reserves we record and inhibit future production growth;
|
•
|
have a negative impact on the ability of us and/or our partners to obtain financing;
|
•
|
cause delay in or cancellation of development plans, which could also have a long-term negative impact on the quantities of proved reserves we record and inhibit future production growth;
|
•
|
reduce the profitability of our projects, resulting in decreases in net income and cash flows with the potential to make future investments uneconomical;
|
•
|
result in currently producing projects becoming uneconomic, to the extent fiscal changes are retroactive, thereby reducing the amount of proved reserves we record and cash flows we receive, and possibly resulting in asset impairment charges;
|
•
|
require that valuation allowances be established against deferred tax assets, with offsetting increases in income tax expense, resulting in decreases in net income and cash flow;
|
•
|
restrict our ability to compete with imported volumes of crude oil or natural gas; and/or
|
•
|
adversely affect the price of our common stock.
|
•
|
increased volatility in global crude oil, natural gas and NGL prices which could negatively impact the global economy, resulting in slower economic growth rates, which could reduce demand for our products;
|
•
|
negative impact on the world crude oil supply if infrastructure or transportation are disrupted, leading to further commodity price volatility;
|
•
|
difficulty in attracting and retaining qualified personnel to work in areas with potential for conflict;
|
•
|
inability of our personnel or supplies to enter or exit the countries where we are conducting operations;
|
•
|
disruption of our operations due to evacuation of personnel;
|
•
|
inability to deliver our production due to disruption or closing of transportation routes;
|
•
|
reduced ability to export our production due to efforts of countries to conserve domestic resources;
|
•
|
damage to or destruction of our wells, production facilities, receiving terminals or other operating assets;
|
•
|
damage to or destruction of property belonging to our natural gas purchasers leading to interruption of natural gas deliveries, claims of force majeure, and/or termination of natural gas sales contracts, resulting in a reduction in our revenues;
|
•
|
inability of our service and equipment providers to deliver items necessary for us to conduct our operations;
|
•
|
lack of availability of drilling rig, oilfield equipment or services if third party providers decide to exit the region;
|
•
|
shutdown of a financial system, communications network, or power grid causing a disruption to our business activities; and
|
•
|
capital market reassessment of risk and reduction of available capital making it more difficult for us and our partners to obtain financing for potential development projects.
|
•
|
pipeline ruptures and spills;
|
•
|
fires, explosions, blowouts and well cratering;
|
•
|
equipment malfunctions and/or mechanical failure on high-volume, high-impact wells;
|
•
|
malfunctions and/or mechanical failure at terminals or other onshore delivery points;
|
•
|
leaks or spills occurring during the transfer of hydrocarbons from an FPSO to an oil tanker;
|
•
|
loss of product occurring as a result of transfer to a rail car or train derailments;
|
•
|
formations with abnormal pressures and basin subsidence which could result in leakage or loss of access to hydrocarbons;
|
•
|
release of pollutants;
|
•
|
spills, leaks or discharges of fluids used in or produced in the course of operations, especially those that reach surface water or groundwater; and
|
•
|
security breaches, cyber attacks, piracy or terroristic acts.
|
•
|
hurricanes, tropical storms, cyclones, windstorms, or “superstorms” which could affect our operations in areas such as Texas, deepwater Gulf of Mexico, and the Marcellus Shale;
|
•
|
winter storms and snow which could affect our operations in the DJ Basin and Marcellus Shale;
|
•
|
extremely high temperatures, which could affect third party gathering and processing facilities in the DJ Basin and Texas;
|
•
|
severe droughts resulting in new restrictions on water usage in the DJ Basin, Marcellus Shale and Texas;
|
•
|
harsh weather and rough seas offshore the Falkland Islands and Newfoundland, which could limit exploration activities; and
|
•
|
other natural disasters.
|
•
|
lower commodity price outlook;
|
•
|
title problems;
|
•
|
near-term lease expiration;
|
•
|
decisions impacting allocation of capital;
|
•
|
compliance with environmental and other governmental requirements;
|
•
|
availability of market, or costs to develop infrastructure;
|
•
|
increases in the cost of, or shortages or delays in the availability of, drilling rigs, equipment and qualified personnel;
|
•
|
unexpected drilling conditions;
|
•
|
pressure or other irregularities in formations;
|
•
|
equipment failures or accidents; and
|
•
|
adverse weather conditions.
|
•
|
blocked development;
|
•
|
denial or delay of permits;
|
•
|
shortening of lease terms or reduction in lease size;
|
•
|
restrictions on installation or operation of gathering, processing or pipeline facilities;
|
•
|
restrictions on the transportation of crude oil and natural gas;
|
•
|
restrictions on the use of certain operating practices, such as hydraulic fracturing;
|
•
|
reduced access to water supplies or restrictions on water disposal;
|
•
|
limited access or damage to or destruction of our property;
|
•
|
legal challenges or lawsuits;
|
•
|
targeted activist shareholder campaigns;
|
•
|
increased regulation of our business;
|
•
|
damaging publicity about the Company;
|
•
|
increased costs of doing business;
|
•
|
reduction in demand for our products; and
|
•
|
other adverse effects on our ability to develop our properties and expand production.
|
•
|
unauthorized access to seismic data, reserves information or other sensitive or proprietary information could have a negative impact on our ability to compete for oil and gas resources;
|
•
|
data corruption, communication interruption, or other operational disruption during drilling activities could result in failure to reach the intended target or a drilling incident;
|
•
|
data corruption or operational disruption of production infrastructure could result in loss of production, or accidental discharge;
|
•
|
a cyber attack on a vendor or service provider could result in supply chain disruptions which could delay or halt a development project, effectively delaying the start of cash flows from the project;
|
•
|
a cyber attack on a third party gathering or pipeline service provider could prevent us from marketing our production, resulting in a loss of revenues;
|
•
|
a cyber attack involving commodities exchanges or financial institutions could slow or halt commodities trading, thus preventing us from marketing our production or engaging in hedging activities, resulting in a loss of revenues;
|
•
|
a cyber attack which halts activities at a power generation facility or refinery using natural gas as feed stock could have a significant impact on the natural gas market, resulting in reduced demand for our production, lower natural gas prices, and reduced revenues;
|
•
|
a cyber attack on a communications network or power grid could cause operational disruption resulting in loss of revenues;
|
•
|
a deliberate corruption of our financial or operational data could result in events of non-compliance which could lead to regulatory fines or penalties; and
|
•
|
business interruptions could result in expensive remediation efforts, distraction of management, damage to our reputation, or a negative impact on the price of our common stock.
|
•
|
new municipal or state land use regulations, which may restrict drilling locations or certain activities such as hydraulic fracturing;
|
•
|
local and municipal government control of land or zoning requirements, which can conflict with state law and deprive land owners of property development rights;
|
•
|
landowner, community and/or governmental opposition to infrastructure development;
|
•
|
regulation of federal land by the BLM;
|
•
|
anti-development activities, which can reduce our access to leases through legal challenges or lawsuits, disruption of drilling, or damage to equipment;
|
•
|
the presence of threatened or endangered species or of their habitat;
|
•
|
disputes regarding leases; and
|
•
|
disputes with landowners, royalty owners, or other operators over such matters as title transfer, joint interest billing arrangements, revenue distribution, or production or cost sharing arrangements.
|
•
|
exploration activities in frontier areas may not result in commercially productive quantities of crude oil, natural gas and NGL reserves;
|
•
|
remote locations make it more difficult and time-consuming to transport personnel, equipment and supplies;
|
•
|
certain operating environments, such as offshore the Falkland Islands and Newfoundland, include harsh weather and rough seas which could limit seismic surveys and other exploration activities during certain periods;
|
•
|
pandemics and epidemics, which may adversely affect our business operations through travel or other restrictions; and
|
•
|
there have been numerous acts of piracy, kidnapping, civil strife, regional conflict, border disputes, cross-border violence, and war, as well as violence associated with corruption, drug trafficking and regime changes in certain areas.
|
•
|
a portion of our cash flows from operating activities must be used to service our indebtedness and is not available for other purposes;
|
•
|
we may be at a competitive disadvantage as compared to similar companies that have less debt;
|
•
|
a covenant contained in our Credit Agreement provides that our total debt to capitalization ratio (as defined in the Credit Agreement) will not exceed 65% at any time, which may make additional borrowings more expensive, thereby affecting our flexibility in planning for, and reacting to, changes in the economy and our industry;
|
•
|
additional future financing for working capital, capital expenditures, acquisitions, general corporate or other purposes may have higher costs and more restrictive covenants;
|
•
|
changes in our debt credit ratings may negatively affect the cost, terms, conditions and/or availability of future financing, and lower ratings will increase the interest rate and fees we pay on our unsecured revolving credit facility (Revolving Credit Facility); and
|
•
|
we may be more vulnerable to general adverse economic and industry conditions.
|
•
|
large multi-national, integrated oil and gas companies;
|
•
|
state-controlled national oil companies;
|
•
|
US independent oil and gas companies;
|
•
|
US onshore midstream companies;
|
•
|
service companies engaging in exploration and production activities; and
|
•
|
private investing in oil and gas equity funds.
|
•
|
seeking to acquire desirable producing properties or new leases for future exploration;
|
•
|
acquiring or increasing access to gathering, processing and transportation services and capacity;
|
•
|
marketing our crude oil, natural gas and NGL production;
|
•
|
seeking to acquire the equipment and expertise necessary to operate and develop properties; and
|
•
|
attracting and retaining employees with certain skills.
|
•
|
historical production from the area compared with production from other areas;
|
•
|
the assumed effects of regulations by governmental agencies, including the SEC;
|
•
|
assumptions concerning future crude oil, natural gas, and NGL prices;
|
•
|
anticipated development cycle time;
|
•
|
future development costs;
|
•
|
future operating and abandonment costs;
|
•
|
impacts of cost recovery provisions in contracts with foreign governments;
|
•
|
severance and excise taxes; and
|
•
|
workover and remedial costs.
|
•
|
incorrect estimates or assumptions about reserves, exploration potential or potential drilling locations;
|
•
|
incorrect assumptions regarding future revenues, including future commodity prices and differentials, or regarding future development and operating costs;
|
•
|
incorrect assumptions regarding potential synergies and the overall costs of equity or debt;
|
•
|
difficulties in integrating the operations, technologies, products and personnel of the acquired assets or business; and
|
•
|
unknown and unforeseen liabilities or other issues related to any acquisition for which contractual protections prove inadequate, including environmental liabilities and title defects.
|
•
|
current commodity prices;
|
•
|
laws and regulations impacting oil and gas operations in the areas where the assets are located;
|
•
|
willingness of the purchaser to assume certain liabilities such as asset retirement obligations;
|
•
|
our willingness to indemnify buyers for certain matters; and
|
•
|
delays in closing.
|
•
|
increase the costs of drilling exploratory and development wells;
|
•
|
cause delays in, or preclude, the development of our projects resulting in longer development cycle times;
|
•
|
result in additional operating and capital costs;
|
•
|
divert our cash flows from capital investments in order to maintain liquidity;
|
•
|
increase or remove liability caps for claims of damages from oil spills;
|
•
|
increase our share of civil or criminal fines or sanctions for actual or alleged violations if a well incident were to occur; and
|
•
|
limit our ability to obtain additional insurance coverage, at a level that balances the cost of insurance and our desired rates of return, to protect against any increase in liability.
|
|
|
High
|
|
Low
|
|
Dividends Per Share
|
|||||||
2015
|
|
|
|
|
|
|
|||||||
First Quarter
|
|
$
|
52.42
|
|
|
$
|
41.01
|
|
|
$
|
0.18
|
|
|
Second Quarter
|
|
53.68
|
|
|
42.13
|
|
|
0.18
|
|
||||
Third Quarter
|
|
43.03
|
|
|
29.13
|
|
|
0.18
|
|
||||
Fourth Quarter
|
|
39.85
|
|
|
29.56
|
|
|
0.18
|
|
||||
2016
|
|
|
|
|
|
|
|||||||
First Quarter
|
|
$
|
35.04
|
|
|
$
|
23.77
|
|
|
$
|
0.10
|
|
|
Second Quarter
|
|
38.62
|
|
|
29.47
|
|
|
0.10
|
|
||||
Third Quarter
|
|
37.50
|
|
|
32.71
|
|
—
|
|
0.10
|
|
|||
Fourth Quarter
|
|
42.03
|
|
|
33.75
|
|
|
0.10
|
|
Period
|
|
Total Number of
Shares Purchased
(1)
|
|
Average
Price Paid
Per Share
|
|
Total Number of
Shares Purchased
as Part of Publicly
Announced Plans or
Programs
|
|
Approximate Dollar
Value of Shares that
May Yet Be
Purchased Under the
Plans or Programs
|
|||||
|
|
|
|
|
|
|
|
(in thousands)
|
|||||
10/1/2016 - 10/31/2016
|
|
848
|
|
|
$
|
35.78
|
|
|
—
|
|
|
—
|
|
11/1/2016 - 11/30/2016
|
|
304
|
|
|
35.98
|
|
|
—
|
|
|
—
|
|
|
12/1/2016 - 12/31/2016
|
|
391
|
|
|
38.86
|
|
|
—
|
|
|
—
|
|
|
Total
|
|
1,543
|
|
|
$
|
36.60
|
|
|
—
|
|
|
—
|
|
Year Ended December 31,
|
2012
|
2013
|
2014
|
2015
|
2016
|
||||||||||
Noble Energy, Inc.
|
$
|
108.82
|
|
$
|
146.99
|
|
$
|
103.45
|
|
$
|
73.09
|
|
$
|
85.47
|
|
S&P 500
|
116.00
|
|
153.58
|
|
174.60
|
|
177.01
|
|
198.18
|
|
|||||
Peer Group
|
101.34
|
|
133.49
|
|
114.88
|
|
71.07
|
|
102.69
|
|
|
|
Year Ended December 31,
|
||||||||||||||||||
(millions, except as noted)
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
Revenues and Income
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total Revenues
|
|
$
|
3,491
|
|
|
$
|
3,183
|
|
|
$
|
5,115
|
|
|
$
|
5,015
|
|
|
$
|
4,223
|
|
(Loss) Income from Continuing Operations Including Noncontrolling Interests
|
|
(985
|
)
|
|
(2,441
|
)
|
|
1,214
|
|
|
907
|
|
|
965
|
|
|||||
Net (Loss) Income Including Noncontrolling Interests
|
|
(985
|
)
|
|
(2,441
|
)
|
|
1,214
|
|
|
978
|
|
|
1,027
|
|
|||||
Net (Loss) Income Attributable to Noble Energy
|
|
(998
|
)
|
|
(2,441
|
)
|
|
1,214
|
|
|
978
|
|
|
1027
|
|
|||||
Per Share Data, Attributable to Noble Energy
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
(Loss) Earnings Per Share - Basic
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
(Loss) Income from Continuing Operations
|
|
$
|
(2.32
|
)
|
|
$
|
(6.07
|
)
|
|
$
|
3.36
|
|
|
$
|
2.53
|
|
|
$
|
2.71
|
|
Net (Loss) Income
|
|
(2.32
|
)
|
|
(6.07
|
)
|
|
3.36
|
|
|
2.72
|
|
|
2.89
|
|
|||||
(Loss) Earnings Per Share - Diluted
|
|
|
|
|
|
|
|
|
|
|
||||||||||
(Loss) Income from Continuing Operations
|
|
(2.32
|
)
|
|
(6.07
|
)
|
|
3.27
|
|
|
2.50
|
|
|
2.68
|
|
|||||
Net (Loss) Income
|
|
(2.32
|
)
|
|
(6.07
|
)
|
|
3.27
|
|
|
2.69
|
|
|
2.86
|
|
|||||
Cash Dividends Per Share
|
|
0.40
|
|
|
0.72
|
|
|
0.68
|
|
|
0.55
|
|
|
0.45
|
|
|||||
Year-End Stock Price Per Share
|
|
38.06
|
|
|
32.93
|
|
|
47.43
|
|
|
68.11
|
|
|
50.87
|
|
|||||
Weighted Average Shares Outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Basic
|
|
430
|
|
|
402
|
|
|
361
|
|
|
359
|
|
|
356
|
|
|||||
Diluted
|
|
430
|
|
|
402
|
|
|
367
|
|
|
363
|
|
|
359
|
|
|||||
Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Net Cash Provided by Operating Activities
|
|
$
|
1,351
|
|
|
$
|
2,062
|
|
|
$
|
3,506
|
|
|
$
|
2,937
|
|
|
$
|
2,933
|
|
Additions to Property, Plant and Equipment
|
|
1,541
|
|
|
2,979
|
|
|
4,871
|
|
|
3,947
|
|
|
3,650
|
|
|||||
Proceeds from Divestitures
|
|
1,241
|
|
|
151
|
|
|
321
|
|
|
327
|
|
|
1,160
|
|
|||||
Proceeds from Issuance of Noble Energy Common Stock, Net of Offering Costs
|
|
—
|
|
|
1,112
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Proceeds from Issuance of Noble Midstream Partners Common Units, Net of Offering Costs
|
|
299
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Financial Position
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Cash and Cash Equivalents
|
|
$
|
1,180
|
|
|
$
|
1,028
|
|
|
$
|
1,183
|
|
|
$
|
1,117
|
|
|
$
|
1,387
|
|
Property, Plant, and Equipment, Net
|
|
18,548
|
|
|
21,300
|
|
|
18,143
|
|
|
15,725
|
|
|
13,551
|
|
|||||
Goodwill
(2)
|
|
—
|
|
|
—
|
|
|
620
|
|
|
627
|
|
|
635
|
|
|||||
Total Assets
|
|
21,011
|
|
|
24,196
|
|
|
22,518
|
|
|
19,642
|
|
|
17,554
|
|
|||||
Long-term Obligations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Long-Term Debt
|
|
7,011
|
|
|
7,976
|
|
|
6,068
|
|
|
4,566
|
|
|
3,736
|
|
|||||
Deferred Income Taxes
|
|
1,819
|
|
|
2,826
|
|
|
2,516
|
|
|
2,441
|
|
|
2,218
|
|
|||||
Asset Retirement Obligations, Noncurrent
|
|
775
|
|
|
861
|
|
|
670
|
|
|
547
|
|
|
333
|
|
|||||
Other
|
|
328
|
|
|
358
|
|
|
417
|
|
|
562
|
|
|
477
|
|
|||||
Total Equity
|
|
9,600
|
|
|
10,370
|
|
|
10,325
|
|
|
9,184
|
|
|
8,258
|
|
(1)
|
Amounts adjusted for the 2-for-1 stock split which occurred during second quarter 2013.
|
(2)
|
Goodwill was fully impaired at December 31, 2015. See
Item 8. Financial Statements and Supplementary Data – Note
1. Summary of Significant Accounting Policies
.
|
|
|
Year Ended December 31,
|
||||||||||||||||||
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
Operations Information - Consolidated Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Consolidated Crude Oil Sales (MBbl/d)
|
|
125
|
|
|
112
|
|
|
103
|
|
|
99
|
|
|
86
|
|
|||||
Average Realized Price ($/Bbl)
|
|
$
|
40.39
|
|
|
$
|
45.00
|
|
|
$
|
91.58
|
|
|
$
|
100.29
|
|
|
$
|
101.52
|
|
Consolidated Natural Gas Sales (MMcf/d)
|
|
1,397
|
|
|
1,187
|
|
|
992
|
|
|
901
|
|
|
774
|
|
|||||
Average Realized Price ($/Mcf)
|
|
$
|
2.42
|
|
|
$
|
2.44
|
|
|
$
|
3.38
|
|
|
$
|
2.97
|
|
|
$
|
2.19
|
|
Consolidated NGL Sales (MBbl/d)
|
|
54
|
|
|
39
|
|
|
23
|
|
|
16
|
|
|
16
|
|
|||||
Average Realized Price ($/Bbl)
|
|
$
|
14.92
|
|
|
$
|
13.91
|
|
|
$
|
33.75
|
|
|
$
|
35.53
|
|
|
$
|
35.36
|
|
Proved Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Crude Oil and Condensate Reserves (MMBbls)
|
|
333
|
|
|
307
|
|
|
304
|
|
|
322
|
|
|
268
|
|
|||||
Natural Gas Reserves (Bcf)
|
|
5,308
|
|
|
5,549
|
|
|
5,833
|
|
|
5,828
|
|
|
4,964
|
|
|||||
NGL Reserves (MMBbls)
|
|
219
|
|
|
189
|
|
|
128
|
|
|
113
|
|
|
89
|
|
|||||
Total Reserves (MMBoe)
|
|
1,437
|
|
|
1,421
|
|
|
1,404
|
|
|
1,406
|
|
|
1,184
|
|
|||||
Number of Employees
|
|
2,274
|
|
|
2,395
|
|
|
2,735
|
|
|
2,527
|
|
|
2,190
|
|
•
|
•
|
•
|
•
|
•
|
•
|
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
•
|
integration of Rosetta Resources Inc., which expanded our portfolio with entry into two top-tier US Basins, the Eagle Ford Shale and Permian Basin;
|
•
|
additional Permian Basin bolt-on acquisitions;
|
•
|
improvement in the DJ Basin regulatory and legislative environment;
|
•
|
exchange of acreage in the DJ Basin which increased our contiguous acreage position; and
|
•
|
dissolution of the Marcellus Shale joint venture, providing increased flexibility and control over our investment.
|
•
|
project sanction readiness at Leviathan;
|
•
|
increased production with less capital investment;
|
•
|
improved returns with technology advancements and structural cost savings; and
|
•
|
delivery of major offshore projects on budget and on schedule.
|
•
|
proactive and strategic action to manage within cash flows;
|
•
|
strong liquidity position including cash on hand and unused borrowing capacity;
|
•
|
portfolio management and midstream strategy, which increase our future financial capacity;
|
•
|
reduction of our outstanding debt through cash on hand; and
|
•
|
maintenance of our investment grade credit rating.
|
•
|
crude oil, natural gas and NGL revenues of
$3.4 billion
, as compared with
$3.1 billion
for
2015
;
|
•
|
net loss attributable to Noble Energy of
$998 million
, as compared with net loss of
$2.4 billion
for
2015
;
|
•
|
net loss on commodity derivative instruments of
$139 million
(including
$708 million
non-cash loss), as compared with
$501 million
net gain (including
$508 million
non-cash loss) for
2015
;
|
•
|
dry hole expense of
$579 million
, as compared with
$266 million
for
2015
;
|
•
|
undeveloped leasehold impairment expense of
$93 million
, as compared with
$21 million
for 2015;
|
•
|
reduced lease operating expense of
$3.59
per BOE, as compared with
$4.43
per BOE for
2015
, a reduction of
19%
;
|
•
|
reduced general and administrative expense of
$2.64
per BOE, as compared with
$3.11
per BOE for
2015
, a reduction of
15%
;
|
•
|
asset impairment expense of
$92 million
, as compared with
$533 million
for
2015
;
|
•
|
diluted loss per share attributable to Noble Energy of
$2.32
, as compared with diluted loss per share of
$6.07
for
2015
;
|
•
|
cash flows provided by operating activities of
$1.4 billion
, as compared with
$2.1 billion
in
2015
; and
|
•
|
capital expenditures of
$1.6 billion
, as compared with $2.9 billion, excluding the Rosetta Merger, in
2015
.
|
•
|
net cash proceeds of
$299 million
received from issuance of Noble Midstream Partners common units, net of offering costs;
|
•
|
proceeds of
$1.2 billion
from asset sales; and
|
•
|
prepayment of $850 million of borrowings under our Term Loan Facility.
|
•
|
cash balance of
$1.2 billion
, as compared with
$1.0 billion
at
December 31, 2015
;
|
•
|
total liquidity of
$5.2 billion
, as compared with
$5.0 billion
at
December 31, 2015
; and
|
•
|
ratio of debt-to-book capital of
43%
, as compared with
43%
at
December 31, 2015
.
|
•
|
we have a high-quality, globally diversified portfolio of assets, focused on top-tier basins, and the majority of our assets are held by production, which provides investment optionality and flexibility;
|
•
|
we have exploration expertise which has led to numerous discoveries, in the deepwater Gulf of Mexico, Levant Basin offshore Eastern Mediterranean and the Douala Basin offshore West Africa, resulting in major development project opportunities;
|
•
|
we have operational and technical expertise which has led to our delivery of major development projects on schedule and within budget providing a competitive and financial advantage in our industry;
|
•
|
we have achieved substantial cost reductions (and are well-positioned on the global cost supply curve) impacting both operating expenses and capital expenditures;
|
•
|
we have designed a capital investment program, with flexibility allowing us to respond to changing commodity price conditions in 2017;
|
•
|
we have adjusted our quarterly dividend to 10 cents per common share; and
|
•
|
we have robust liquidity of $5.2 billion at December 31, 2016 and ability to access capital markets.
|
•
|
commodity prices, which, if subject to decline, could result in current production becoming uneconomic;
|
•
|
overall level and timing of capital expenditures which, as discussed below and dependent upon our drilling success, will impact near-term production volumes;
|
•
|
Israeli industrial and residential demand for electricity, which is largely impacted by weather conditions and conversion of Israeli electricity portfolio from coal to natural gas;
|
•
|
timing of the divestiture of the remaining 7.5% working interest in the Tamar field which will lower our sales volumes;
|
•
|
potential growth in the Israeli natural gas export market;
|
•
|
timing of crude oil and condensate liftings impacting sales volumes in West Africa;
|
•
|
natural field decline in onshore US, deepwater Gulf of Mexico and offshore Equatorial Guinea;
|
•
|
potential weather-related volume curtailments due to hurricanes in the deepwater Gulf of Mexico and Gulf Coast areas, or winter storms and flooding impacting onshore US operations;
|
•
|
reliability of support equipment and facilities, pipeline disruptions, and/or potential pipeline and processing facility capacity constraints which may cause restrictions or interruptions in production and/or midstream processing;
|
•
|
malfunctions and/or mechanical failures at terminals or other onshore US delivery points;
|
•
|
impact of enhanced completion efforts for onshore US assets;
|
•
|
potential shut-in of US producing properties if storage capacity becomes unavailable;
|
•
|
potential drilling and/or completion permit delays due to future regulatory changes; and
|
•
|
potential purchases of producing properties or divestments of operating assets.
|
•
|
commodity prices, including price realizations on specific crude oil, natural gas and NGL production;
|
•
|
operating and development costs and the ability to achieve material supplier price reductions;
|
•
|
production, drilling, delivery commitments or other contractual obligations;
|
•
|
drilling results;
|
•
|
property acquisitions and divestitures;
|
•
|
exploration activity;
|
•
|
cash flows from operations;
|
•
|
indebtedness levels;
|
•
|
availability of financing or other sources of funding;
|
•
|
permitting activity in the deepwater Gulf of Mexico;
|
•
|
potential legislative or regulatory changes regarding the use of hydraulic fracturing;
|
•
|
potential changes in the fiscal regimes of the US and other countries in which we operate; and
|
•
|
impact of new laws and regulations on our business practices.
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
(millions, except per share)
|
|
|
|
|
|
|
||||||
Total Revenues
|
|
$
|
3,491
|
|
|
$
|
3,183
|
|
|
$
|
5,115
|
|
Total Operating Expenses
|
|
4,787
|
|
|
5,655
|
|
|
4,197
|
|
|||
Operating (Loss) Income
|
|
(1,296
|
)
|
|
(2,472
|
)
|
|
918
|
|
|||
Total Other (Income) Expense
|
|
476
|
|
|
(253
|
)
|
|
(792
|
)
|
|||
(Loss) Income from Operations Before Income Taxes
|
|
(1,772
|
)
|
|
(2,219
|
)
|
|
1,710
|
|
|||
Net (Loss) Income Including Noncontrolling Interests
|
|
(985
|
)
|
|
(2,441
|
)
|
|
1,214
|
|
|||
Less: Net Income Attributable to Noncontrolling Interests
|
|
13
|
|
|
—
|
|
|
—
|
|
|||
Net (Loss) Income Attributable to Noble Energy
|
|
(998
|
)
|
|
(2,441
|
)
|
|
1,214
|
|
|||
|
|
|
|
|
|
|
||||||
Net (Loss) Income Attributable to Noble Energy Per Share
|
|
|
|
|
|
|
|
|
|
|||
Basic
|
|
(2.32
|
)
|
|
(6.07
|
)
|
|
3.36
|
|
|||
Diluted
|
|
(2.32
|
)
|
|
(6.07
|
)
|
|
3.27
|
|
|
Sales Volumes
|
|
Average Realized Sales Prices
|
||||||||||||||||||||
|
Crude Oil & Condensate
(MBbl/d)
|
|
Natural
Gas
(MMcf/d)
|
|
NGLs
(MBbl/d)
|
|
Total
(MBoe/d)
(1)
|
|
Crude Oil & Condensate
(Per Bbl)
|
|
Natural
Gas
(Per Mcf)
|
|
NGLs
(Per Bbl)
|
||||||||||
Year Ended December 31, 2016
|
|||||||||||||||||||||||
United States
|
99
|
|
|
881
|
|
|
54
|
|
|
301
|
|
|
$
|
39.59
|
|
|
$
|
2.11
|
|
|
$
|
14.92
|
|
Israel
|
—
|
|
|
281
|
|
|
—
|
|
|
47
|
|
|
—
|
|
|
5.21
|
|
|
—
|
|
|||
Equatorial Guinea
(2)
|
26
|
|
|
235
|
|
|
—
|
|
|
65
|
|
|
43.54
|
|
|
0.27
|
|
|
—
|
|
|||
Total Consolidated Operations
|
125
|
|
|
1,397
|
|
|
54
|
|
|
413
|
|
|
40.39
|
|
|
2.42
|
|
|
14.92
|
|
|||
Equity Investee
(3)
|
2
|
|
|
—
|
|
|
5
|
|
|
7
|
|
|
45.44
|
|
|
—
|
|
|
26.30
|
|
|||
Total
|
127
|
|
|
1,397
|
|
|
59
|
|
|
420
|
|
|
$
|
40.46
|
|
|
$
|
2.42
|
|
|
$
|
15.96
|
|
Year Ended December 31, 2015
|
|||||||||||||||||||||||
United States
|
81
|
|
|
708
|
|
|
39
|
|
|
237
|
|
|
$
|
43.46
|
|
|
$
|
2.10
|
|
|
$
|
13.91
|
|
Israel
|
—
|
|
|
252
|
|
|
—
|
|
|
42
|
|
|
—
|
|
|
5.34
|
|
|
—
|
|
|||
Equatorial Guinea
(2)
|
31
|
|
|
227
|
|
|
—
|
|
|
69
|
|
|
48.85
|
|
|
0.27
|
|
|
—
|
|
|||
Total Consolidated Operations
|
112
|
|
|
1,187
|
|
|
39
|
|
|
348
|
|
|
45.00
|
|
|
2.44
|
|
|
13.91
|
|
|||
Equity Investee
(3)
|
2
|
|
|
—
|
|
|
5
|
|
|
7
|
|
|
48.85
|
|
|
—
|
|
|
28.40
|
|
|||
Total
|
114
|
|
|
1,187
|
|
|
44
|
|
|
355
|
|
|
$
|
45.05
|
|
|
$
|
2.44
|
|
|
$
|
15.59
|
|
Year Ended December 31, 2014
|
|||||||||||||||||||||||
United States
|
68
|
|
|
518
|
|
|
23
|
|
|
176
|
|
|
$
|
89.60
|
|
|
$
|
3.86
|
|
|
$
|
33.75
|
|
Israel
|
—
|
|
|
231
|
|
|
—
|
|
|
39
|
|
|
—
|
|
|
5.57
|
|
|
—
|
|
|||
Equatorial Guinea
(2)
|
33
|
|
|
243
|
|
|
—
|
|
|
74
|
|
|
94.61
|
|
|
0.27
|
|
|
—
|
|
|||
China
|
2
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
103.74
|
|
|
—
|
|
|
—
|
|
|||
Total Consolidated Operations
|
103
|
|
|
992
|
|
|
23
|
|
|
291
|
|
|
91.58
|
|
|
3.38
|
|
|
33.75
|
|
|||
Equity Investee
(3)
|
2
|
|
|
—
|
|
|
5
|
|
|
7
|
|
|
96.53
|
|
|
—
|
|
|
62.89
|
|
|||
Total
|
105
|
|
|
992
|
|
|
28
|
|
|
298
|
|
|
$
|
91.65
|
|
|
$
|
3.38
|
|
|
$
|
39.19
|
|
(1)
|
Natural gas is converted on the basis of six Mcf of gas per one barrel of crude oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Given commodity price disparities, the price for a barrel of crude oil equivalent for
|
(2)
|
Natural gas from the Alba field is under contract for $0.25 per MMBtu to a methanol plant, an LPG plant, an LNG plant and a power generation plant. The methanol and LPG plants are owned by affiliated entities accounted for under the equity method.
|
(3)
|
Volumes represent sales of condensate and LPG from the Alba plant in Equatorial Guinea.
|
|
|
Crude Oil &
Condensate
|
|
Natural
Gas
|
|
NGLs
|
|
Total
|
||||||||
(millions)
|
|
|
|
|
|
|
|
|
||||||||
2014 Sales Revenues
|
|
$
|
3,438
|
|
|
$
|
1,223
|
|
|
$
|
284
|
|
|
$
|
4,945
|
|
Changes due to
|
|
|
|
|
|
|
|
|
||||||||
Increase in Sales Volumes
|
|
306
|
|
|
241
|
|
|
181
|
|
|
728
|
|
||||
Decrease in Sales Prices
|
|
(1,904
|
)
|
|
(408
|
)
|
|
(268
|
)
|
|
(2,580
|
)
|
||||
2015 Sales Revenues
|
|
$
|
1,840
|
|
|
$
|
1,056
|
|
|
$
|
197
|
|
|
$
|
3,093
|
|
Changes due to
|
|
|
|
|
|
|
|
|
||||||||
Increase in Sales Volumes
|
|
153
|
|
|
190
|
|
|
84
|
|
|
427
|
|
||||
Increase (Decrease) in Sales Prices
|
|
(139
|
)
|
|
(7
|
)
|
|
15
|
|
|
(131
|
)
|
||||
2016 Sales Revenues
|
|
$
|
1,854
|
|
|
$
|
1,239
|
|
|
$
|
296
|
|
|
$
|
3,389
|
|
•
|
higher sales volumes of 9 MBbl/d in the Eagle Ford Shale and Permian Basin primarily attributable to full year consolidation following the Rosetta Merger;
|
•
|
sales volumes from the Big Bend and Dantzler developments (deepwater Gulf of Mexico), which began producing fourth quarter 2015 and contributed 12 MBbl/d, net, collectively in 2016; and
|
•
|
start up of the deepwater Gulf of Mexico Gunflint development in July 2016 which contributed 3 MBbl/d;
|
•
|
a
10%
decrease in total consolidated average realized prices primarily due to the decline in global crude oil prices that began in the second half of 2014 and continued into 2016; and
|
•
|
decrease in sales volumes due to natural field decline at Aseng and Alen, offshore Equatorial Guinea.
|
•
|
a 51% decrease in total consolidated average realized prices primarily due to the decline in global crude oil prices that began in the second half of 2014 and continued in 2015;
|
•
|
decrease in sales volumes due to planned downtime and maintenance as well as natural field decline in the deepwater Gulf of Mexico and the Aseng field, offshore Equatorial Guinea; and
|
•
|
decrease in sales volumes due to the sale of our China assets at the end of second quarter 2014;
|
•
|
higher sales volumes of 7 MBbl/d in the DJ Basin primarily attributable to increased well productivity due to enhanced completion techniques and increased processing capacity;
|
•
|
sales volumes of 7 MBbl/d contributed by our recently-acquired Eagle Ford Shale and Permian Basin assets; and
|
•
|
start up of the deepwater Gulf of Mexico Rio Grande development in fourth quarter 2015 which contributed 2 MBbl/d.
|
•
|
higher sales volumes of 93 MMcf/d in the Marcellus Shale primarily attributable to well completion and infrastructure development;
|
•
|
higher sales volumes of 81 MMcf/d in the Eagle Ford Shale and Permian Basin primarily attributable to full year consolidation following the Rosetta Merger;
|
•
|
record sales volumes from the Tamar field, offshore Israel, which contributed an incremental 29 MMcf/d, in response to higher power generation needs; and
|
•
|
higher sales volumes offshore Equatorial Guinea due to the completion of the Alba B3 compression project.
|
•
|
a 28% decrease in total consolidated average realized natural gas prices, including a 46% decrease in US average realized prices primarily due to oversupply; and
|
•
|
a widening of location basis differentials in the Marcellus Shale due to an oversupply of natural gas in the region which lowered the price we received;
|
•
|
higher sales volumes of 28 MMcf/d in the DJ Basin primarily attributable to increased well productivity due to enhanced completion techniques and increased processing capacity;
|
•
|
higher sales volumes of 131 MMcf/d in the Marcellus Shale primarily attributable to well completion and infrastructure development;
|
•
|
sales volumes of 58 MMcf/d contributed by our recently-acquired Eagle Ford Shale and Permian Basin assets; and
|
•
|
record sales volumes from the Tamar field, offshore Israel, which contributed an incremental 21 MMcf/d, in response to higher power generation needs.
|
•
|
higher sales volumes of 14 MBbl/d in the Eagle Ford Shale and Permian Basin primarily attributable to a full year of production as well as increased development activity;
|
•
|
a
7%
increase in total consolidated average realized prices, primarily due to higher spot prices in the Marcellus Shale; and
|
•
|
higher sales volumes of 2 MBbl/d in the DJ Basin primarily attributable to increased well productivity due to enhanced completion techniques and increased processing capacity;
|
•
|
slightly lower sales volumes in the Marcellus Shale due to the higher dry gas composition of wells that were brought online in 2016.
|
•
|
a 59% decrease in total consolidated average realized NGL prices, which are closely linked to the NYMEX WTI crude oil price decline, particularly in the Marcellus Shale;
|
•
|
higher sales volumes of 2 MBbl/d in the DJ Basin primarily attributable to increased well productivity due to enhanced completion techniques and increased processing capacity;
|
•
|
higher sales volumes of 5 MBbl/d in the Marcellus Shale primarily attributable to well completion and infrastructure development; and
|
•
|
sales volumes of 9 MBbl/d contributed by our recently-acquired Eagle Ford Shale and Permian Basin assets.
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
Net Income (in millions)
|
|
|
|
|
|
|
||||||
CONE Gathering and CONE Midstream
|
|
$
|
48
|
|
|
$
|
46
|
|
|
$
|
9
|
|
AMPCO and Affiliates
|
|
16
|
|
|
8
|
|
|
62
|
|
|||
Alba Plant
|
|
34
|
|
|
31
|
|
|
99
|
|
|||
Other
|
|
4
|
|
|
5
|
|
|
—
|
|
|||
Dividends (in millions)
|
|
|
|
|
|
|
||||||
CONE Gathering and CONE Midstream
|
|
27
|
|
|
17
|
|
|
48
|
|
|||
AMPCO and Affiliates
|
|
16
|
|
|
31
|
|
|
61
|
|
|||
Alba Plant
|
|
40
|
|
|
29
|
|
|
117
|
|
|||
Sales Volumes
|
|
|
|
|
|
|
||||||
Methanol (MMgal)
|
|
162
|
|
|
117
|
|
|
130
|
|
|||
Condensate (MBbl/d)
|
|
2
|
|
|
2
|
|
|
2
|
|
|||
LPG (MBbl/d)
|
|
5
|
|
|
5
|
|
|
5
|
|
|||
Average Realized Prices
|
|
|
|
|
|
|
||||||
Methanol (per gallon)
|
|
$
|
0.63
|
|
|
$
|
0.92
|
|
|
$
|
1.26
|
|
Condensate (per Bbl)
|
|
45.44
|
|
|
48.85
|
|
|
96.53
|
|
|||
LPG (per Bbl)
|
|
26.30
|
|
|
28.40
|
|
|
62.89
|
|
|
|
|
Inc (Dec) from Prior Year
|
|
|
|
Inc (Dec) from Prior Year
|
|
|
||||||||
(millions)
|
2016
|
|
|
2015
|
|
|
2014
|
||||||||||
Production Expense
|
$
|
1,083
|
|
|
11
|
%
|
|
$
|
979
|
|
|
4
|
%
|
|
$
|
945
|
|
Exploration Expense
|
925
|
|
|
90
|
%
|
|
488
|
|
|
(2
|
)%
|
|
498
|
|
|||
Depreciation, Depletion and Amortization
|
2,454
|
|
|
15
|
%
|
|
2,131
|
|
|
21
|
%
|
|
1,759
|
|
|||
General and Administrative
|
399
|
|
|
1
|
%
|
|
396
|
|
|
(21
|
)%
|
|
503
|
|
|||
Asset Impairments
|
92
|
|
|
(83
|
)%
|
|
533
|
|
|
7
|
%
|
|
500
|
|
|||
Goodwill Impairment
|
—
|
|
|
N/M
|
|
|
779
|
|
|
N/M
|
|
|
—
|
|
|||
Other Operating (Income) Expense, Net
|
(166
|
)
|
|
N/M
|
|
|
349
|
|
|
N/M
|
|
|
(8
|
)
|
|||
Total
|
$
|
4,787
|
|
|
(15
|
)%
|
|
$
|
5,655
|
|
|
35
|
%
|
|
4,197
|
|
(millions, except unit rate)
|
Total per BOE
(1)
|
|
Total
|
|
United
States
|
|
Israel
|
|
Equatorial Guinea
|
|
Other Int'l/
Corporate
(2)
|
||||||||||||
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Lease Operating Expense
(3)
|
$
|
3.59
|
|
|
$
|
542
|
|
|
$
|
400
|
|
|
$
|
37
|
|
|
$
|
105
|
|
|
$
|
—
|
|
Production and Ad Valorem Taxes
|
0.52
|
|
|
78
|
|
|
78
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Transportation and Gathering Expense
|
3.07
|
|
|
463
|
|
|
463
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total Production Expense
|
$
|
7.18
|
|
|
$
|
1,083
|
|
|
$
|
941
|
|
|
$
|
37
|
|
|
$
|
105
|
|
|
$
|
—
|
|
Total Production Expense per BOE
|
|
|
$
|
7.18
|
|
|
$
|
8.56
|
|
|
$
|
2.14
|
|
|
$
|
4.42
|
|
|
N/M
|
|
|||
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Lease Operating Expense
(3)
|
$
|
4.43
|
|
|
$
|
563
|
|
|
$
|
370
|
|
|
$
|
49
|
|
|
$
|
131
|
|
|
$
|
13
|
|
Production and Ad Valorem Taxes
|
1.00
|
|
|
127
|
|
|
125
|
|
|
—
|
|
|
—
|
|
|
2
|
|
||||||
Transportation and Gathering Expense
|
2.26
|
|
|
289
|
|
|
289
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total Production Expense
|
$
|
7.69
|
|
|
$
|
979
|
|
|
$
|
784
|
|
|
$
|
49
|
|
|
$
|
131
|
|
|
$
|
15
|
|
Total Production Expense per BOE
|
|
|
$
|
7.69
|
|
|
$
|
9.07
|
|
|
$
|
3.15
|
|
|
$
|
5.21
|
|
|
N/M
|
|
|||
Year Ended December 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Lease Operating Expense
(3)
|
$
|
5.58
|
|
|
$
|
593
|
|
|
$
|
343
|
|
|
$
|
54
|
|
|
$
|
147
|
|
|
$
|
49
|
|
Production and Ad Valorem Taxes
|
1.73
|
|
|
184
|
|
|
166
|
|
|
—
|
|
|
—
|
|
|
18
|
|
||||||
Transportation and Gathering Expense
|
1.60
|
|
|
168
|
|
|
166
|
|
|
—
|
|
|
—
|
|
|
2
|
|
||||||
Total Production Expense
|
$
|
8.91
|
|
|
$
|
945
|
|
|
$
|
675
|
|
|
$
|
54
|
|
|
$
|
147
|
|
|
$
|
69
|
|
Total Production Expense per BOE
|
|
|
$
|
8.91
|
|
|
$
|
10.55
|
|
|
$
|
3.84
|
|
|
$
|
5.44
|
|
|
N/M
|
|
(1)
|
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees and include expenses related to Noble Midstream Partners.
|
(2)
|
Other International, Corporate includes the North Sea (in 2014 and 2015), China (through June 30, 2014) and corporate expenditures.
|
(3)
|
Lease operating expense includes oil and gas operating costs (labor, fuel, repairs, replacements, saltwater disposal and other related lifting costs) and workover expense.
|
•
|
decrease of $92 million onshore US, primarily in the DJ Basin and Marcellus Shale, and $27 million offshore Equatorial Guinea due to cost reduction initiatives, including lower equipment utilization and saltwater disposal costs;
|
•
|
increase of $74 million attributable to new production from onshore US and deepwater Gulf of Mexico development activities; and
|
•
|
increase of $38 million related to the acquisition of Eagle Ford Shale and Permian Basin production third quarter 2015.
|
•
|
decrease of $17 million from sales of non-strategic onshore US properties in 2014;
|
•
|
decrease of $17 million due to the sale of our China assets at the end of second quarter 2014;
|
•
|
decrease of $15 million in deepwater Gulf of Mexico due to cessation of operations at South Raton, natural field decline and cost reduction initiatives;
|
•
|
decrease of $15 million offshore West Africa due to cost reduction initiatives and lower production;
|
•
|
decrease of $6 million in offshore Israel due to cost reduction initiatives; and
|
•
|
decrease of $9 million in other international/corporate due to cost reduction initiatives;
|
•
|
increase of $38 million attributable to our recently-acquired Eagle Ford Shale and Permian Basin assets; and
|
•
|
increase of $11 million in the Marcellus Shale due to increased production.
|
•
|
increase of $66 million related to higher production from our Marcellus Shale assets;
|
•
|
increase of $57 million related to change in mix of transportation methods used for our DJ Basin production;
|
•
|
increase of $49 million related to higher production from our Eagle Ford Shale assets acquired third quarter 2015; and
|
•
|
increase of $17 million related to production from our new deepwater Gulf of Mexico projects at Big Bend and Dantzler (which began producing fourth quarter 2015) and Gunflint (which began producing in July 2016).
|
•
|
increase of $81 million in the Marcellus Shale due to higher production and increased expenses due to service contracts with CONE Gathering;
|
•
|
increase of $33 million due to recently-acquired Eagle Ford Shale and Permian Basin properties; and
|
•
|
increase of $12 million in the DJ Basin due to the May 2015 commencement of Tallgrass pipeline, which transports DJ Basin crude oil;
|
•
|
$8 million decrease due to the sale of non-strategic onshore US, China and North Sea properties in 2014.
|
(millions)
|
Total
|
|
United States
|
|
Eastern Mediter-ranean
(1)
|
|
West
Africa
(2)
|
|
Other Int'l,
Corporate
(3)
|
||||||||||
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Leasehold Impairment and Amortization
|
$
|
148
|
|
|
$
|
123
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
25
|
|
Dry Hole Cost
(4)
|
579
|
|
|
85
|
|
|
26
|
|
|
468
|
|
|
—
|
|
|||||
Seismic, Geological and Geophysical
|
76
|
|
|
—
|
|
|
—
|
|
|
10
|
|
|
66
|
|
|||||
Staff Expense
|
77
|
|
|
3
|
|
|
1
|
|
|
5
|
|
|
68
|
|
|||||
Other
(5)
|
45
|
|
|
34
|
|
|
7
|
|
|
—
|
|
|
4
|
|
|||||
Total Exploration Expense
|
$
|
925
|
|
|
$
|
245
|
|
|
$
|
34
|
|
|
$
|
483
|
|
|
$
|
163
|
|
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
|
|
||||||||||
Leasehold Impairment and Amortization
|
$
|
113
|
|
|
$
|
105
|
|
|
$
|
5
|
|
|
$
|
3
|
|
|
$
|
—
|
|
Dry Hole Cost
|
266
|
|
|
93
|
|
|
—
|
|
|
33
|
|
|
140
|
|
|||||
Seismic, Geological and Geophysical
|
34
|
|
|
5
|
|
|
—
|
|
|
10
|
|
|
19
|
|
|||||
Staff Expense
|
43
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
42
|
|
|||||
Other
(5)
|
32
|
|
|
—
|
|
|
6
|
|
|
—
|
|
|
26
|
|
|||||
Total Exploration Expense
|
$
|
488
|
|
|
$
|
203
|
|
|
$
|
12
|
|
|
$
|
46
|
|
|
$
|
227
|
|
Year Ended December 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Leasehold Impairment and Amortization
|
$
|
43
|
|
|
$
|
43
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Dry Hole Cost
|
226
|
|
|
147
|
|
|
—
|
|
|
—
|
|
|
79
|
|
|||||
Seismic, Geological and Geophysical
|
86
|
|
|
28
|
|
|
4
|
|
|
18
|
|
|
36
|
|
|||||
Staff Expense
|
72
|
|
|
25
|
|
|
2
|
|
|
4
|
|
|
41
|
|
|||||
Other
(5)
|
71
|
|
|
25
|
|
|
11
|
|
|
4
|
|
|
31
|
|
|||||
Total Exploration Expense
|
$
|
498
|
|
|
$
|
268
|
|
|
$
|
17
|
|
|
$
|
26
|
|
|
$
|
187
|
|
(1)
|
Eastern Mediterranean includes Israel and Cyprus.
|
(2)
|
West Africa includes Equatorial Guinea, Cameroon and Gabon.
|
(3)
|
Other International, Corporate includes the Falkland Islands, Suriname and other new ventures and corporate expenditures.
|
(4)
|
For a discussion of 2016 dry hole cost, see
Items 1. and 2. Business and Properties – International – West Africa
and
Item 8. Financial Statements and Supplementary Data – Note 6. Capitalized Exploratory Well Costs
.
|
(5)
|
Includes lease rental and other exploration expense.
|
•
|
leasehold impairment expense including the write-off of leases and licenses of $58 million for the deepwater Gulf of Mexico, $25 million for the Falkland Islands and $10 million for other onshore US;
|
•
|
dry hole cost including costs related to the Silvergate exploratory well, deepwater Gulf of Mexico, the Dolphin 1 natural gas discovery, offshore Israel, and certain discoveries offshore West Africa;
|
•
|
seismic expense relating to the acquisition of 3D seismic data in West Africa and other international areas;
|
•
|
other cost for onshore US including lease rentals primarily related to Permian Basin leases; and
|
•
|
salaries and related expenses for corporate exploration and new ventures personnel.
|
•
|
leasehold impairment expense including the write-off of our northeast Nevada leases of $21 million;
|
•
|
US dry hole cost including amounts related to northeast Nevada exploration efforts which we elected to discontinue after assessing commercial viability in the current commodity price environment;
|
•
|
West Africa dry hole cost including the Cheetah well (offshore Cameroon) and Other International dry hole cost including the Humpback well (offshore Falkland Islands), neither of which identified commercial quantities of hydrocarbons; and
|
•
|
salaries and related expenses for corporate exploration and new ventures personnel.
|
|
Year Ended December 31,
|
||||||||||
(millions, except unit rate)
|
2016
|
|
2015
|
|
2014
|
||||||
United States
|
$
|
2,122
|
|
|
$
|
1,692
|
|
|
$
|
1,318
|
|
Israel
|
81
|
|
|
70
|
|
|
63
|
|
|||
Equatorial Guinea
|
205
|
|
|
326
|
|
|
299
|
|
|||
Other International, and Corporate
|
46
|
|
|
43
|
|
|
79
|
|
|||
Total DD&A Expense
(1)
|
$
|
2,454
|
|
|
$
|
2,131
|
|
|
$
|
1,759
|
|
Unit Rate per BOE
(2)
|
$
|
16.26
|
|
|
$
|
16.75
|
|
|
$
|
16.55
|
|
(1)
|
DD&A expense includes accretion of discount on asset retirement obligations of $
48 million
in
2016
, $
43 million
in
2015
, and $
36 million
in
2014
.
|
(2)
|
Consolidated unit rates exclude sales volumes and costs attributable to equity method investees.
|
•
|
increase of $178 million related to higher sales volumes resulting from commencement of production from the Big Bend, Dantzler and Gunflint development projects in deepwater Gulf of Mexico in 2016 and 2015;
|
•
|
increase of $134 million related to the acquisition of Eagle Ford Shale and Permian Basin production third quarter 2015; and
|
•
|
$121 million related to the reduction in proved reserves in fourth quarter 2015 primarily due to downward price revisions in DJ Basin and Marcellus Shale;
|
•
|
an overall lower segment rate for offshore Equatorial Guinea due to the fluctuation in production from higher DD&A rate assets Aseng and Alen to lower DD&A rate asset Alba field.
|
•
|
increase of $332 million in the DJ Basin and Marcellus Shale due to higher sales volumes and a reduction in proved reserves at year end primarily due to downward price revisions;
|
•
|
increase of $93 million related to our recently-acquired Eagle Ford Shale and Permian Basin assets;
|
•
|
increase of $55 million related to the Rio Grande development, deepwater Gulf of Mexico, which began producing in 2015;
|
•
|
increase in Equatorial Guinea due to a reduction in proved reserves at year end primarily due to downward price revisions; and
|
•
|
increase due to record sales volumes from the Tamar field, offshore Israel;
|
•
|
decrease of $92 million in the deepwater Gulf of Mexico due to planned downtime and maintenance and proved reserves additions; and
|
•
|
decrease due to the sale of our China assets during 2014.
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
G&A Expense (millions)
|
$
|
399
|
|
|
$
|
396
|
|
|
$
|
503
|
|
Unit Rate per BOE
(1)
|
$
|
2.64
|
|
|
$
|
3.11
|
|
|
$
|
4.73
|
|
(1)
|
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.
|
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Asset Impairments
|
|
$
|
92
|
|
|
$
|
533
|
|
|
$
|
500
|
|
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Goodwill Impairment
|
|
$
|
—
|
|
|
$
|
779
|
|
|
$
|
—
|
|
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Marketing Expense
|
|
$
|
58
|
|
|
$
|
33
|
|
|
$
|
16
|
|
Loss on Terminated Contract
|
|
41
|
|
|
—
|
|
|
—
|
|
|||
Gain on Divestitures, Net
|
|
(238
|
)
|
|
—
|
|
|
(73
|
)
|
|||
Corporate Restructuring Expense
|
|
8
|
|
|
51
|
|
|
—
|
|
|||
Gain on Debt Extinguishment
|
|
(80
|
)
|
|
—
|
|
|
—
|
|
|||
Pension Plan Expense
|
|
—
|
|
|
88
|
|
|
—
|
|
|||
Impact of Rosetta Merger
|
|
(25
|
)
|
|
81
|
|
|
—
|
|
|||
Other, Net
|
|
70
|
|
|
96
|
|
|
49
|
|
|||
Total
|
|
$
|
(166
|
)
|
|
$
|
349
|
|
|
$
|
(8
|
)
|
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Loss (Gain) on Commodity Derivative Instruments
|
|
$
|
139
|
|
|
$
|
(501
|
)
|
|
$
|
(976
|
)
|
Interest, Net of Amount Capitalized
|
|
328
|
|
|
263
|
|
|
210
|
|
|||
Other Non-Operating Expense (Income), Net
|
|
9
|
|
|
(15
|
)
|
|
(26
|
)
|
|||
Total
|
|
$
|
476
|
|
|
$
|
(253
|
)
|
|
$
|
(792
|
)
|
•
|
cash settlements (received) or paid relating to our crude oil and natural gas commodity derivative contracts, and
|
•
|
non-cash (increases) or decreases in the fair values of our crude oil and natural gas commodity derivative contracts.
|
•
|
$499 million
contributed by crude oil contracts; and
|
•
|
$70 million
contributed by natural gas contracts.
|
•
|
$582 million
related to crude oil contracts; and
|
•
|
$126 million
related to natural gas contracts.
|
•
|
$755 million contributed by crude oil contracts entered into by Noble and $89 million contributed by crude oil contracts acquired in the Rosetta Merger; and
|
•
|
$120 million contributed by natural gas contracts entered into by Noble, $27 million contributed by natural gas contracts acquired in the Rosetta Merger and $18 million contributed by NGL contracts acquired in the Rosetta Merger.
|
•
|
$423 million related to crude oil contracts;
|
•
|
$65 million related to natural gas contracts; and
|
•
|
$20 million related to NGL contracts.
|
•
|
$34 million contributed by crude oil contracts;
|
•
|
$5 million paid for natural gas contracts.
|
•
|
$863 million related to crude oil contracts; and
|
•
|
$84 million related to natural gas contracts.
|
|
|
Year Ended December 31,
|
||||||||||
(millions, except per unit)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Interest Expense
|
|
$
|
412
|
|
|
$
|
407
|
|
|
$
|
326
|
|
Capitalized Interest
|
|
(84
|
)
|
|
(144
|
)
|
|
(116
|
)
|
|||
Interest Expense, Net
|
|
$
|
328
|
|
|
$
|
263
|
|
|
$
|
210
|
|
Unit Rate per BOE
(1)
|
|
$
|
2.17
|
|
|
$
|
2.07
|
|
|
$
|
1.97
|
|
(1)
|
Consolidated unit rates exclude sales volumes and costs attributable to equity method investees.
|
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Income Tax Provision (Benefit)
|
|
$
|
(787
|
)
|
|
$
|
222
|
|
|
$
|
496
|
|
Effective Rate
|
|
44.4
|
%
|
|
(10.0
|
)%
|
|
29.0
|
%
|
|
December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
(millions, except percentages)
|
|
|
|
|
|
||||||
Total Cash
(1)
|
$
|
1,209
|
|
|
$
|
1,028
|
|
|
$
|
1,183
|
|
Amount Available to be Borrowed Under Revolving Credit Facility
(2)
|
4,000
|
|
|
4,000
|
|
|
4,000
|
|
|||
Total Liquidity
|
$
|
5,209
|
|
|
$
|
5,028
|
|
|
$
|
5,183
|
|
Total Debt
(3)
|
$
|
7,114
|
|
|
$
|
7,976
|
|
|
$
|
6,197
|
|
Noble Energy Share of Equity
|
9,600
|
|
|
10,370
|
|
|
10,325
|
|
|||
Ratio of Debt-to-Book Capital
(4)
|
43
|
%
|
|
43
|
%
|
|
38
|
%
|
(1)
|
Total cash includes cash and cash equivalents of almost
$1.2 billion
, which includes $57 million cash relating to Noble Midstream Partners, as well as restricted cash of $30 million related to the Permian Basin property acquisition that closed in January 2017.
|
(2)
|
Excludes $350 million available to be borrowed under Noble Midstream Services Revolving Credit Facility, which is not available to Noble Energy, as of December 31, 2016. See Revolving Credit Facilities
,
below.
|
(3)
|
Total debt includes capital lease and other obligations and excludes unamortized debt discount/premium, and issuance costs.
|
(4)
|
We define our ratio of debt-to-book capital as total debt (which includes long-term debt excluding unamortized discount/premium and issuance costs, the current portion of long-term debt, and short-term borrowings) divided by the sum of total debt plus Noble Energy's share of equity.
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
(millions)
|
|
|
|
|
|
|
||||||
Total Cash Provided By (Used in)
|
|
|
|
|
|
|
||||||
Operating Activities
|
|
$
|
1,351
|
|
|
$
|
2,062
|
|
|
$
|
3,506
|
|
Investing Activities
|
|
(431
|
)
|
|
(2,871
|
)
|
|
(4,465
|
)
|
|||
Financing Activities
|
|
(768
|
)
|
|
654
|
|
|
1,025
|
|
|||
Increase (Decrease) in Cash and Cash Equivalents
|
|
$
|
152
|
|
|
$
|
(155
|
)
|
|
$
|
66
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
(millions)
|
|
|
|
|
|
|
||||||
Acquisition, Capital and Exploration Expenditures
|
|
|
|
|
|
|
|
|
||||
Proved Property Acquisition
(1)
|
|
$
|
—
|
|
|
$
|
1,613
|
|
|
$
|
—
|
|
Unproved Property Acquisition
(2)
|
|
234
|
|
|
1,480
|
|
|
249
|
|
|||
Exploration
|
|
222
|
|
|
322
|
|
|
505
|
|
|||
Development
|
|
1,017
|
|
|
2,055
|
|
|
3,660
|
|
|||
Midstream
(3)
|
|
42
|
|
|
356
|
|
|
229
|
|
|||
Corporate and Other
|
|
50
|
|
|
97
|
|
|
169
|
|
|||
Total
|
|
$
|
1,565
|
|
|
$
|
5,923
|
|
|
$
|
4,812
|
|
Other
|
|
|
|
|
|
|
|
|
||||
Investment in Equity Method Investee
(4)
|
|
$
|
8
|
|
|
$
|
104
|
|
|
$
|
71
|
|
Increase in Capital Lease Obligations
(5)
|
|
5
|
|
|
55
|
|
|
110
|
|
(1)
|
Proved property acquisition costs for 2015 relates to proved properties acquired in the Rosetta Merger. See
Item 8. Financial Statements and Supplementary Data - Note
3. Acquisitions, Divestitures and Merger
.
|
(2)
|
2016 unproved property acquisition costs relate to the termination of the Marcellus Shale joint development. Costs in 2015 primarily relate to unproved properties acquired in the Rosetta Merger. See
Item 8. Financial Statements and Supplementary Data - Note
3. Acquisitions, Divestitures and Merger
. Additionally, unproved property acquisition cost for 2015 includes $49 million in the DJ Basin, $60 million in the Marcellus Shale, and $10 million and $5 million for costs incurred after the Rosetta Merger in the Permian Basin and Eagle Ford Shale, respectively.
|
(3)
|
2016 includes expenditures of Noble Midstream Partners, and 2015 includes midstream assets acquired in the Rosetta Merger. See
Item 8. Financial Statements and Supplementary Data - Note
3. Acquisitions, Divestitures and Merger
.
|
(4)
|
We own a 50% interest in CONE Gathering which is accounted for using the equity method. CONE Gathering constructs, owns and operates gathering lines and facilities related to the Marcellus Shale development.
|
(5)
|
Relates to onshore US assets.
|
•
|
$1.0 billion
net decrease in debt;
|
•
|
$172 million
decrease in shareholders' equity from dividends paid; and
|
•
|
$1.0 billion
decrease in shareholders' equity from current year net loss.
|
Obligation
|
Total
|
|
2017
|
|
2018 and 2019
|
|
2020 and 2021
|
|
2022 and beyond
|
||||||||||
(millions)
|
|
|
|
|
|
|
|
|
|
||||||||||
Long-Term Debt
(1)
|
$
|
6,739
|
|
|
$
|
—
|
|
|
$
|
1,550
|
|
|
$
|
1,379
|
|
|
$
|
3,810
|
|
Interest Payments
(2)
|
5,347
|
|
|
363
|
|
|
646
|
|
|
523
|
|
|
3,815
|
|
|||||
Capital Lease and Other Obligations
(3)
|
461
|
|
|
77
|
|
|
131
|
|
|
90
|
|
|
163
|
|
|||||
Drilling and Equipment Obligations
(4)
|
130
|
|
|
128
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|||||
Purchase Obligations
(5)
|
339
|
|
|
127
|
|
|
146
|
|
|
36
|
|
|
30
|
|
|||||
Transportation and Gathering
(6)
|
2,954
|
|
|
250
|
|
|
626
|
|
|
512
|
|
|
1,566
|
|
|||||
Operating Lease Obligations
(7)
|
346
|
|
|
30
|
|
|
72
|
|
|
56
|
|
|
188
|
|
|||||
Other Liabilities
(8)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Asset Retirement Obligations
(9)
|
935
|
|
|
162
|
|
|
117
|
|
|
56
|
|
|
600
|
|
|||||
Commodity Derivative Instruments
(10)
|
116
|
|
|
102
|
|
|
14
|
|
|
—
|
|
|
—
|
|
|||||
Total Contractual Obligations
|
$
|
17,367
|
|
|
$
|
1,239
|
|
|
$
|
3,304
|
|
|
$
|
2,652
|
|
|
$
|
10,172
|
|
(1)
|
Long-term debt excludes our capital lease and other obligations. See
Item 8. Financial Statements and Supplementary Data – Note
10. Long-Term Debt
.
|
(2)
|
Interest payments are based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2016. See
Item 8. Financial Statements and Supplementary Data – Note
10. Long-Term Debt
.
|
(3)
|
Annual capital lease payments, net to our interest, exclude regular maintenance and operational costs. See
Item 8. Financial Statements and Supplementary Data – Note
10. Long-Term Debt
.
|
(4)
|
Drilling and equipment obligations represent our working interest share of contractual agreements with third-party service providers to procure drilling rigs, such as the Atwood Advantage drill ship, and other related equipment for exploratory and development drilling activities. See Counterparty Credit Risk, above, and
Item 8. Financial Statements and Supplementary Data – Note
18. Commitments and Contingencies
.
|
(5)
|
Purchase obligations represent our working interest share of contractual agreements to purchase goods or services that are enforceable, are legally binding and specify all significant terms, including fixed and minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction. See Counterparty Credit Risk, above, and
Item 8. Financial Statements and Supplementary Data – Note
18. Commitments and Contingencies
.
|
(6)
|
Transportation and gathering obligations represent minimum charges for firm transportation and gathering agreements related to our production. See Items 1. and 2. Business and Properties – Delivery Commitments. See
Item 8. Financial Statements and Supplementary Data – Note
18. Commitments and Contingencies
.
|
(7)
|
Operating lease obligations represent non-cancelable leases for office buildings and facilities and oil and gas operations equipment used in our daily operations. Amounts have not been discounted. See
Item 8. Financial Statements and Supplementary Data – Note
18. Commitments and Contingencies
.
|
(8)
|
The table excludes deferred compensation liabilities of $
218 million
as specific payment dates are unknown. See
Item 8. Financial Statements and Supplementary Data – Note
12. Stock-Based and Other Compensation Plans
.
|
(9)
|
Asset retirement obligations are discounted. See
Item 8. Financial Statements and Supplementary Data – Note
9. Asset Retirement Obligations
.
|
(10)
|
Amount represents open commodity derivative instruments that were in a net payable position with the counterparty at December 31, 2016. See
Item 8. Financial Statements and Supplementary Data – Note
8. Derivative Instruments and Hedging Activities
.
|
Consolidated Financial Statements of Noble Energy, Inc.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noble Energy, Inc.
|
|
|
|
/s/ KPMG LLP
|
|
|
Houston, Texas
|
|
|
|
|
February 14, 2017
|
|
|
|
|
|
|
/s/ KPMG LLP
|
|
|
Houston, Texas
|
|
|
|
|
February 14, 2017
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Revenues
|
|
|
|
|
|
||||||
Oil, Gas and NGL Sales
|
$
|
3,389
|
|
|
$
|
3,093
|
|
|
$
|
4,945
|
|
Income from Equity Method Investees
|
102
|
|
|
90
|
|
|
170
|
|
|||
Total Revenues
|
3,491
|
|
|
3,183
|
|
|
5,115
|
|
|||
Costs and Expenses
|
|
|
|
|
|
||||||
Production Expense
|
1,083
|
|
|
979
|
|
|
945
|
|
|||
Exploration Expense
|
925
|
|
|
488
|
|
|
498
|
|
|||
Depreciation, Depletion and Amortization
|
2,454
|
|
|
2,131
|
|
|
1,759
|
|
|||
General and Administrative
|
399
|
|
|
396
|
|
|
503
|
|
|||
Asset Impairments
|
92
|
|
|
533
|
|
|
500
|
|
|||
Goodwill Impairment
|
—
|
|
|
779
|
|
|
—
|
|
|||
Other Operating (Income) Expense, Net
|
(166
|
)
|
|
349
|
|
|
(8
|
)
|
|||
Total Operating Expenses
|
4,787
|
|
|
5,655
|
|
|
4,197
|
|
|||
Operating (Loss) Income
|
(1,296
|
)
|
|
(2,472
|
)
|
|
918
|
|
|||
Other (Income) Expense
|
|
|
|
|
|
||||||
Loss (Gain) on Commodity Derivative Instruments
|
139
|
|
|
(501
|
)
|
|
(976
|
)
|
|||
Interest, Net of Amount Capitalized
|
328
|
|
|
263
|
|
|
210
|
|
|||
Other Non-Operating Expense (Income), Net
|
9
|
|
|
(15
|
)
|
|
(26
|
)
|
|||
Total Other Expense (Income)
|
476
|
|
|
(253
|
)
|
|
(792
|
)
|
|||
(Loss) Income Before Income Taxes
|
(1,772
|
)
|
|
(2,219
|
)
|
|
1,710
|
|
|||
Income Tax (Benefit) Provision
|
(787
|
)
|
|
222
|
|
|
496
|
|
|||
Net (Loss) Income Including Noncontrolling Interests
|
(985
|
)
|
|
(2,441
|
)
|
|
1,214
|
|
|||
Less: Net Income Attributable to Noncontrolling Interests
|
13
|
|
|
—
|
|
|
—
|
|
|||
Net (Loss) Income Attributable to Noble Energy
|
$
|
(998
|
)
|
|
$
|
(2,441
|
)
|
|
$
|
1,214
|
|
|
|
|
|
|
|
||||||
Net (Loss) Income Attributable to Noble Energy per Share of Common Stock
|
|
|
|
|
|
||||||
Basic
|
$
|
(2.32
|
)
|
|
$
|
(6.07
|
)
|
|
$
|
3.36
|
|
Diluted
|
$
|
(2.32
|
)
|
|
$
|
(6.07
|
)
|
|
$
|
3.27
|
|
|
|
|
|
|
|
||||||
Weighted Average Number of Shares Outstanding
|
|
|
|
|
|
||||||
Basic
|
430
|
|
|
402
|
|
|
361
|
|
|||
Diluted
|
430
|
|
|
402
|
|
|
367
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Net (Loss) Income Including Noncontrolling Interests
|
$
|
(985
|
)
|
|
$
|
(2,441
|
)
|
|
$
|
1,214
|
|
Other Items of Comprehensive Income (Loss)
|
|
|
|
|
|
||||||
Net Change in Mutual Fund Investment
|
—
|
|
|
(11
|
)
|
|
—
|
|
|||
Less Tax Expense
|
—
|
|
|
4
|
|
|
—
|
|
|||
Net Change in Pension and Other
|
3
|
|
|
99
|
|
|
42
|
|
|||
Less Tax (Benefit) Expense
|
(1
|
)
|
|
(35
|
)
|
|
(15
|
)
|
|||
Other Comprehensive Income (Loss)
|
2
|
|
|
57
|
|
|
27
|
|
|||
Comprehensive (Loss) Income Including Noncontrolling Interests
|
$
|
(983
|
)
|
|
$
|
(2,384
|
)
|
|
$
|
1,241
|
|
Less: Comprehensive Income Attributable to Noncontrolling Interests
|
13
|
|
|
—
|
|
|
—
|
|
|||
Comprehensive (Loss) Income Attributable to Noble Energy
|
$
|
(996
|
)
|
|
$
|
(2,384
|
)
|
|
$
|
1,241
|
|
|
December 31,
2016 |
|
December 31,
2015 |
||||
ASSETS
|
|
|
|
||||
Current Assets
|
|
|
|
||||
Cash and Cash Equivalents
|
$
|
1,180
|
|
|
$
|
1,028
|
|
Accounts Receivable, Net
|
615
|
|
|
450
|
|
||
Commodity Derivative Assets
|
—
|
|
|
582
|
|
||
Other Current Assets
|
160
|
|
|
216
|
|
||
Total Current Assets
|
1,955
|
|
|
2,276
|
|
||
Property, Plant and Equipment
|
|
|
|
||||
Oil and Gas Properties (Successful Efforts Method of Accounting)
|
30,355
|
|
|
31,220
|
|
||
Property, Plant and Equipment, Other
|
909
|
|
|
858
|
|
||
Total Property, Plant and Equipment, Gross
|
31,264
|
|
|
32,078
|
|
||
Accumulated Depreciation, Depletion and Amortization
|
(12,716
|
)
|
|
(10,778
|
)
|
||
Total Property, Plant and Equipment, Net
|
18,548
|
|
|
21,300
|
|
||
Other Noncurrent Assets
|
508
|
|
|
620
|
|
||
Total Assets
|
$
|
21,011
|
|
|
$
|
24,196
|
|
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
|
|
||||
Current Liabilities
|
|
|
|
||||
Accounts Payable - Trade
|
$
|
736
|
|
|
$
|
1,128
|
|
Other Current Liabilities
|
742
|
|
|
677
|
|
||
Total Current Liabilities
|
1,478
|
|
|
1,805
|
|
||
Long-Term Debt
|
7,011
|
|
|
7,976
|
|
||
Net Deferred Income Tax Liability
|
1,819
|
|
|
2,826
|
|
||
Other Noncurrent Liabilities
|
1,103
|
|
|
1,219
|
|
||
Total Liabilities
|
11,411
|
|
|
13,826
|
|
||
|
|
|
|
||||
Shareholders’ Equity
|
|
|
|
||||
Preferred Stock - Par Value $1.00 per share; 4 Million Shares Authorized, None Issued
|
—
|
|
|
—
|
|
||
Common Stock - Par Value $0.01; 1 Billion and 500 Million Shares Authorized; 471 Million and 470 Million Shares Issued, Respectively
|
5
|
|
|
5
|
|
||
Additional Paid in Capital
|
6,450
|
|
|
6,360
|
|
||
Accumulated Other Comprehensive Loss
|
(31
|
)
|
|
(33
|
)
|
||
Treasury Stock, at Cost; 38 Million Shares
|
(692
|
)
|
|
(688
|
)
|
||
Retained Earnings
|
3,556
|
|
|
4,726
|
|
||
Noble Energy Share of Equity
|
9,288
|
|
|
10,370
|
|
||
Noncontrolling Interests
|
312
|
|
|
—
|
|
||
Total Equity
|
9,600
|
|
|
10,370
|
|
||
Total Liabilities and Equity
|
$
|
21,011
|
|
|
$
|
24,196
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Cash Flows From Operating Activities
|
|
|
|
|
|
||||||
Net (Loss) Income Including Noncontrolling Interests
|
$
|
(985
|
)
|
|
$
|
(2,441
|
)
|
|
$
|
1,214
|
|
Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities
|
|
|
|
|
|
|
|
||||
Depreciation, Depletion and Amortization
|
2,454
|
|
|
2,131
|
|
|
1,759
|
|
|||
Asset Impairments
|
92
|
|
|
533
|
|
|
500
|
|
|||
Goodwill Impairment
|
—
|
|
|
779
|
|
|
—
|
|
|||
Dry Hole Cost
|
579
|
|
|
266
|
|
|
226
|
|
|||
Deferred Income Taxes
|
(984
|
)
|
|
116
|
|
|
268
|
|
|||
Loss (Gain) on Commodity Derivative Instruments
|
139
|
|
|
(501
|
)
|
|
(976
|
)
|
|||
Net Cash Received in Settlement of Commodity Derivative Instruments
|
569
|
|
|
1,009
|
|
|
29
|
|
|||
Gain on Divestitures
|
(238
|
)
|
|
—
|
|
|
(73
|
)
|
|||
Stock Based Compensation
|
77
|
|
|
86
|
|
|
87
|
|
|||
Non-cash Pension Plan Termination Expense
|
—
|
|
|
82
|
|
|
—
|
|
|||
Gain on Debt Extinguishment
|
(80
|
)
|
|
—
|
|
|
—
|
|
|||
Undeveloped Leasehold Impairment
|
93
|
|
|
21
|
|
|
—
|
|
|||
Expiration and Amortization of Unproved Leaseholds
|
55
|
|
|
92
|
|
|
43
|
|
|||
Other Adjustments for Noncash Items Included in Income
|
40
|
|
|
18
|
|
|
17
|
|
|||
Changes in Operating Assets and Liabilities, Net of Assets Acquired and Liabilities Assumed
|
|
|
|
|
|
||||||
(Increase) Decrease in Accounts Receivable
|
(164
|
)
|
|
453
|
|
|
29
|
|
|||
(Decrease) Increase in Accounts Payable
|
(111
|
)
|
|
(364
|
)
|
|
318
|
|
|||
(Decrease) Increase in Current Income Taxes Payable
|
(32
|
)
|
|
(94
|
)
|
|
18
|
|
|||
(Decrease) Increase in Other Current Liabilities
|
(63
|
)
|
|
(70
|
)
|
|
45
|
|
|||
Other Operating Assets and Liabilities, Net
|
(90
|
)
|
|
(54
|
)
|
|
2
|
|
|||
Net Cash Provided by Operating Activities
|
1,351
|
|
|
2,062
|
|
|
3,506
|
|
|||
Cash Flows From Investing Activities
|
|
|
|
|
|
|
|
||||
Additions to Property, Plant and Equipment
|
(1,541
|
)
|
|
(2,979
|
)
|
|
(4,871
|
)
|
|||
Proceeds from Divestitures
|
1,241
|
|
|
151
|
|
|
321
|
|
|||
Marcellus Shale Acreage Exchange Consideration
|
(213
|
)
|
|
—
|
|
|
—
|
|
|||
Cash Acquired in Rosetta Merger
|
—
|
|
|
61
|
|
|
—
|
|
|||
Additions to Equity Method Investments
|
(8
|
)
|
|
(104
|
)
|
|
(71
|
)
|
|||
Distributions from Equity Method Investments
|
70
|
|
|
—
|
|
|
156
|
|
|||
Other
|
20
|
|
|
—
|
|
|
—
|
|
|||
Net Cash Used in Investing Activities
|
(431
|
)
|
|
(2,871
|
)
|
|
(4,465
|
)
|
|||
Cash Flows From Financing Activities
|
|
|
|
|
|
|
|
||||
Dividends Paid, Common Stock
|
(172
|
)
|
|
(291
|
)
|
|
(249
|
)
|
|||
Proceeds from Issuance of Noble Energy Common Stock, Net of Offering Costs
|
—
|
|
|
1,112
|
|
|
—
|
|
|||
Proceeds from Issuance of Noble Midstream Partners Common Units, Net of Offering Costs
|
299
|
|
|
—
|
|
|
—
|
|
|||
Proceeds from Noble Revolving Credit Facility
|
—
|
|
|
—
|
|
|
1,050
|
|
|||
Repayment of Noble Revolving Credit Facility
|
—
|
|
|
—
|
|
|
(1,050
|
)
|
|||
Repayment of Revolving Credit Facility Assumed in Rosetta Merger
|
—
|
|
|
(70
|
)
|
|
—
|
|
|||
Proceeds from Term Loan Facility
|
1,400
|
|
|
—
|
|
|
—
|
|
|||
Repayment of Term Loan Facility
|
(850
|
)
|
|
—
|
|
|
—
|
|
|||
Proceeds from Issuance of Senior Notes, Net
|
—
|
|
|
—
|
|
|
1,478
|
|
|||
Repayment of Senior Notes
|
(1,383
|
)
|
|
(12
|
)
|
|
(200
|
)
|
|||
Repayment of Capital Lease Obligation
|
(53
|
)
|
|
(67
|
)
|
|
(55
|
)
|
|||
Other
|
(9
|
)
|
|
(18
|
)
|
|
51
|
|
|||
Net Cash (Used in) Provided By Financing Activities
|
(768
|
)
|
|
654
|
|
|
1,025
|
|
|||
Increase (Decrease) in Cash and Cash Equivalents
|
152
|
|
|
(155
|
)
|
|
66
|
|
|||
Cash and Cash Equivalents at Beginning of Period
|
1,028
|
|
|
1,183
|
|
|
1,117
|
|
|||
Cash and Cash Equivalents at End of Period
|
$
|
1,180
|
|
|
$
|
1,028
|
|
|
$
|
1,183
|
|
|
Attributable to Noble Energy
|
|
|
|
|
|||||||||||||||||||||
|
Common
Stock
(1)
|
|
Additional
Paid in
Capital
|
|
Accumulated Other
Comprehensive
Loss
|
|
Treasury
Stock at
Cost
|
|
Retained
Earnings
|
|
Non-controlling Interests
|
|
Total
Equity
|
|||||||||||||
December 31, 2013
|
$
|
4
|
|
|
$
|
3,463
|
|
|
$
|
(117
|
)
|
|
$
|
(659
|
)
|
|
$
|
6,493
|
|
|
—
|
|
|
$
|
9,184
|
|
Net Income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,214
|
|
|
—
|
|
|
1,214
|
|
||||||
Stock-based Compensation
|
—
|
|
|
87
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
87
|
|
||||||
Exercise of Stock Options
|
—
|
|
|
48
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
48
|
|
||||||
Tax Benefits Related to Exercise of Stock Options
|
—
|
|
|
19
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
19
|
|
||||||
Dividends (68 cents per share)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(249
|
)
|
|
—
|
|
|
(249
|
)
|
||||||
Net Change in Other
|
—
|
|
|
7
|
|
|
27
|
|
|
(12
|
)
|
|
—
|
|
|
—
|
|
|
22
|
|
||||||
December 31, 2014
|
$
|
4
|
|
|
$
|
3,624
|
|
|
$
|
(90
|
)
|
|
$
|
(671
|
)
|
|
$
|
7,458
|
|
|
—
|
|
|
$
|
10,325
|
|
Net Loss
|
—
|
|
|
|
|
—
|
|
|
—
|
|
|
(2,441
|
)
|
|
—
|
|
|
(2,441
|
)
|
|||||||
Rosetta Merger
|
1
|
|
|
1,528
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,529
|
|
||||||
Stock-based Compensation
|
—
|
|
|
86
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
86
|
|
||||||
Exercise of Stock Options
|
—
|
|
|
8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8
|
|
||||||
Tax Benefits Related to Exercise of Stock Options
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
||||||
Dividends (72 cents per share)
|
—
|
|
|
|
|
—
|
|
|
—
|
|
|
(291
|
)
|
|
—
|
|
|
(291
|
)
|
|||||||
Issuance of Shares of Common Stock to Public, Net of Offering Costs
|
—
|
|
|
1,112
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,112
|
|
||||||
Net Change in Other
|
—
|
|
|
3
|
|
|
57
|
|
|
(17
|
)
|
|
—
|
|
|
—
|
|
|
43
|
|
||||||
December 31, 2015
|
$
|
5
|
|
|
$
|
6,360
|
|
|
$
|
(33
|
)
|
|
$
|
(688
|
)
|
|
$
|
4,726
|
|
|
—
|
|
|
$
|
10,370
|
|
Net Income (Loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(998
|
)
|
|
13
|
|
|
(985
|
)
|
||||||
Stock-based Compensation
|
—
|
|
|
68
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
68
|
|
||||||
Exercise of Stock Options
|
—
|
|
|
24
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
24
|
|
||||||
Tax Benefits Related to Exercise of Stock Options
|
—
|
|
|
(6
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6
|
)
|
||||||
Dividends (40 cents per share)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(172
|
)
|
|
—
|
|
|
(172
|
)
|
||||||
Issuance of Noble Midstream Partners Common Units, Net of Offering Costs
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
299
|
|
|
299
|
|
||||||
Net Change in Other
|
—
|
|
|
4
|
|
|
2
|
|
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
2
|
|
||||||
December 31, 2016
|
$
|
5
|
|
|
$
|
6,450
|
|
|
$
|
(31
|
)
|
|
$
|
(692
|
)
|
|
$
|
3,556
|
|
|
312
|
|
|
$
|
9,600
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
•
|
Level 1 measurements are fair value measurements which use quoted market prices (unadjusted) in active markets for identical assets or liabilities.
|
•
|
Level 2 measurements are fair value measurements which use inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly.
|
•
|
Level 3 measurements are fair value measurements which use unobservable inputs.
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Production Expense
|
|
|
|
|
|
|
|
|
|
|||
Lease Operating Expense
|
|
$
|
542
|
|
|
$
|
563
|
|
|
$
|
593
|
|
Production and Ad Valorem Taxes
|
|
78
|
|
|
127
|
|
|
184
|
|
|||
Transportation and Gathering Expense
(1)
|
|
463
|
|
|
289
|
|
|
168
|
|
|||
Total
|
|
$
|
1,083
|
|
|
$
|
979
|
|
|
$
|
945
|
|
Exploration Expense
|
|
|
|
|
|
|
||||||
Leasehold Impairment and Amortization
(2)
|
|
148
|
|
|
113
|
|
|
43
|
|
|||
Dry Hole Cost
(2)
|
|
579
|
|
|
266
|
|
|
226
|
|
|||
Seismic, Geological and Geophysical
|
|
76
|
|
|
34
|
|
|
86
|
|
|||
Staff Expense
|
|
77
|
|
|
43
|
|
|
72
|
|
|||
Other
|
|
45
|
|
|
32
|
|
|
71
|
|
|||
Total
|
|
925
|
|
|
488
|
|
|
498
|
|
|||
Other Operating (Income) Expense, Net
|
|
|
|
|
|
|
|
|
|
|||
Marketing Expense
(3)
|
|
58
|
|
|
33
|
|
|
16
|
|
|||
Loss on Terminated Contract
(4)
|
|
41
|
|
|
—
|
|
|
—
|
|
|||
Gain on Divestitures, Net
(5)
|
|
(238
|
)
|
|
—
|
|
|
(73
|
)
|
|||
Corporate Restructuring Expense
(6)
|
|
8
|
|
|
51
|
|
|
—
|
|
|||
Gain on Debt Extinguishment
(7)
|
|
(80
|
)
|
|
—
|
|
|
—
|
|
|||
Pension Plan Expense
(8)
|
|
—
|
|
|
88
|
|
|
—
|
|
|||
Impact of Rosetta Merger
(9)
|
|
(25
|
)
|
|
81
|
|
|
—
|
|
|||
Other, Net
|
|
70
|
|
|
96
|
|
|
49
|
|
|||
Total
|
|
$
|
(166
|
)
|
|
$
|
349
|
|
|
$
|
(8
|
)
|
Other Non-Operating (Income) Expense, Net
|
|
|
|
|
|
|
|
|
|
|||
Deferred Compensation Expense (Income)
(10)
|
|
$
|
11
|
|
|
$
|
(12
|
)
|
|
$
|
(25
|
)
|
Other (Income) Expense, Net
|
|
(2
|
)
|
|
(3
|
)
|
|
(1
|
)
|
|||
Total
|
|
$
|
9
|
|
|
$
|
(15
|
)
|
|
$
|
(26
|
)
|
(1)
|
Certain of our revenue received from purchasers was historically presented with deductions for transportation, gathering, fractionation or processing costs. Beginning in 2016, we have changed our presentation of revenue to no longer include these expenses as deductions from revenue. These costs are now included within production expense. Prior year amounts of
$50 million
and
$14 million
for the years ended December 31, 2015 and 2014, respectively, have been reclassified to transportation and gathering expense to conform to the current presentation.
|
(2)
|
See
Note
6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs
.
|
(3)
|
Amounts represent expense for unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments. Prior year amounts of $33 million and $16 million for the years ended December 31, 2015 and 2014, respectively, were previously presented within transportation and gathering expense. These amounts have been reclassified to conform to the current presentation. See
Note
18. Commitments and Contingencies
.
|
(4)
|
Amount relates to the termination of a rig contract offshore Falkland Islands as a result of a supplier's non-performance.
|
(5)
|
Includes gain related to the sale of
3.5%
working interest in the Tamar field, offshore Israel. See
Note
3. Acquisitions, Divestitures and Merger
.
|
(6)
|
Amount represents expenses associated with organizational activities.
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
(7)
|
Amount relates to the tendering of senior notes assumed in the Rosetta Merger. See
Note
10. Long-Term Debt
.
|
(8)
|
Amount includes reclassification of the actuarial loss from AOCL related to the re-measurement and termination of our defined benefit pension plan to net income (loss).
|
(9)
|
Amounts represent a purchase price allocation adjustment in 2016 and merger expenses in 2015. See
Note
3. Acquisitions, Divestitures and Merger
.
|
(10)
|
Amounts represent increases (decreases) in the fair values of shares of our common stock held in a rabbi trust and mutual funds.
|
|
|
December 31,
|
||||||
(millions)
|
|
2016
|
|
2015
|
||||
Accounts Receivable, Net
|
|
|
|
|
||||
Commodity Sales
|
|
$
|
403
|
|
|
$
|
298
|
|
Joint Interest Billings
|
|
106
|
|
|
20
|
|
||
Proceeds Receivable
(1)
|
|
40
|
|
|
—
|
|
||
Other
|
|
86
|
|
|
151
|
|
||
Allowance for Doubtful Accounts
|
|
(20
|
)
|
|
(19
|
)
|
||
Total
|
|
$
|
615
|
|
|
$
|
450
|
|
Other Current Assets
|
|
|
|
|
|
|
||
Inventories, Materials and Supplies
|
|
$
|
71
|
|
|
$
|
92
|
|
Inventories, Crude Oil
|
|
18
|
|
|
23
|
|
||
Assets Held for Sale
(2)
|
|
18
|
|
|
67
|
|
||
Restricted Cash
(3)
|
|
30
|
|
|
—
|
|
||
Prepaid Expenses and Other Assets, Current
|
|
23
|
|
|
34
|
|
||
Total
|
|
$
|
160
|
|
|
$
|
216
|
|
Other Noncurrent Assets
|
|
|
|
|
||||
Equity Method Investments
|
|
$
|
400
|
|
|
$
|
453
|
|
Mutual Fund Investments
|
|
71
|
|
|
90
|
|
||
Other Assets, Noncurrent
|
|
37
|
|
|
77
|
|
||
Total
|
|
$
|
508
|
|
|
$
|
620
|
|
Other Current Liabilities
|
|
|
|
|
||||
Production and Ad Valorem Taxes
|
|
$
|
115
|
|
|
$
|
166
|
|
Commodity Derivative Liabilities, Current
|
|
102
|
|
|
—
|
|
||
Income Taxes Payable
|
|
53
|
|
|
86
|
|
||
Asset Retirement Obligations, Current
|
|
160
|
|
|
128
|
|
||
Interest Payable
|
|
76
|
|
|
83
|
|
||
Current Portion of Capital Lease and Other Obligations
|
|
63
|
|
|
53
|
|
||
Other Liabilities, Current
|
|
173
|
|
|
161
|
|
||
Total
|
|
$
|
742
|
|
|
$
|
677
|
|
Other Noncurrent Liabilities
|
|
|
|
|
||||
Deferred Compensation Liabilities, Noncurrent
|
|
$
|
218
|
|
|
$
|
217
|
|
Asset Retirement Obligations, Noncurrent
|
|
775
|
|
|
861
|
|
||
Production and Ad Valorem Taxes
|
|
47
|
|
|
68
|
|
||
Other Liabilities, Noncurrent
|
|
63
|
|
|
73
|
|
||
Total
|
|
$
|
1,103
|
|
|
$
|
1,219
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Cash Paid During the Year For
|
|
|
|
|
|
|
||||||
Interest, Net of Amount Capitalized
|
|
$
|
327
|
|
|
$
|
260
|
|
|
$
|
189
|
|
Income Taxes Paid, Net
|
|
236
|
|
|
202
|
|
|
150
|
|
|||
Non-Cash Financing and Investing Activities
|
|
|
|
|
|
|
||||||
Increase in Capital Lease and Other Obligations
|
|
5
|
|
|
55
|
|
|
110
|
|
•
|
entered an agreement to divest certain producing and non-producing properties covering approximately
33,100
net acres in the DJ Basin for proceeds of
$505 million
. We closed the sale on a portion of the properties in 2016, receiving proceeds of
$486 million
. We expect to close the sale of the remaining properties, which are classified as held for sale at December 31, 2016, and receive the remai
n
ing proceeds, subject to post-close adjustments, in mid-2017. Proceeds were applied to reduce field basis with no recognition of gain or loss.
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
•
|
sold additional DJ Basin non-producing properties, certain Eagle Ford properties, our Bowdoin property in northern Montana, and certain other smaller onshore US properties, generating total net proceeds of
$152 million
, a net loss of
$23 million
on the Bowdoin sale, and no further gain or loss recognized on the remaining transactions.
|
•
|
sold our
47%
interest in the Alon A and Alon C licenses, offshore Israel, which included the Karish and Tanin fields, for a total sales price of
$73 million
(
$67 million
for asset consideration and
$6 million
from cost adjustments). Proceeds were applied to reduce field basis with no recognition of gain or loss.
|
•
|
sold a
3.5%
working interest in the Tamar field, offshore Israel, in compliance with the terms of the Israel Natural Gas Framework, which requires us to reduce our ownership interest in Tamar to
25%
by year-end 2021. The sales price totaled
$431 million
, and we received net cash proceeds of
$316 million
, after consideration of timing and tax adjustments, at closing. Proceeds were ratably applied to the field's basis and resulted in the recognition of a
$261 million
gain.
|
•
|
received proceeds of
$131 million
related to a farm-out agreement for a
35%
interest in Block 12, offshore Cyprus, which includes the Aphrodite natural gas discovery. We received the remaining proceeds of $
40 million
in January 2017. Proceeds were applied to reduce field basis with no recognition of gain or loss.
|
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Sales Proceeds
|
|
$
|
1,241
|
|
|
$
|
151
|
|
|
$
|
321
|
|
Less
|
|
|
|
|
|
|
||||||
Net Book Value of Assets Sold
|
|
(993
|
)
|
|
(156
|
)
|
|
(297
|
)
|
|||
Asset Retirement Obligations Associated with Assets Sold
|
|
7
|
|
|
8
|
|
|
48
|
|
|||
Goodwill Allocated to Assets Sold
|
|
—
|
|
|
(4
|
)
|
|
(7
|
)
|
|||
Other Closing Adjustments
|
|
(17
|
)
|
|
1
|
|
|
8
|
|
|||
Gain on Divestitures, Net
|
|
$
|
238
|
|
|
$
|
—
|
|
|
$
|
73
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
(in millions, except stock price)
|
||
Shares of Noble Energy common stock issued to Rosetta shareholders
|
41
|
|
|
Noble Energy common stock price on July 20, 2015
|
$
|
36.97
|
|
Fair value of common stock issued
|
$
|
1,518
|
|
Plus: fair value of Rosetta's restricted stock awards and performance awards assumed
|
10
|
|
|
Plus: Rosetta stock options assumed
|
1
|
|
|
Total purchase price
|
$
|
1,529
|
|
Plus: liabilities assumed by Noble Energy
|
|
||
Accounts Payable
|
100
|
|
|
Current Liabilities
|
37
|
|
|
Long-Term Debt
|
1,992
|
|
|
Other Long Term Liabilities
|
23
|
|
|
Asset Retirement Obligation
|
27
|
|
|
Total purchase price plus liabilities assumed
|
$
|
3,708
|
|
|
|
||
Fair Value of Rosetta Assets
|
|
||
Cash and Equivalents
|
$
|
61
|
|
Other Current Assets
|
76
|
|
|
Derivative Instruments
|
209
|
|
|
Oil and Gas Properties:
|
|
||
Proved Properties
|
1,613
|
|
|
Undeveloped Leaseholds
|
1,355
|
|
|
Gathering and Processing Assets
|
207
|
|
|
Asset Retirement Obligation
|
27
|
|
|
Other Property Plant and Equipment
|
5
|
|
|
Long Term Deferred Tax Asset
|
17
|
|
|
Implied Goodwill
(1)
|
138
|
|
|
Total Asset Value
|
$
|
3,708
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
Year Ended December 31,
|
||||||||||
(in millions, except per share amounts)
|
2016
(1)
|
|
2015
|
|
2014
|
||||||
Revenues
|
$
|
3,491
|
|
|
$
|
3,478
|
|
|
$
|
6,126
|
|
Net (Loss) Income Attributable to Noble Energy
|
(998
|
)
|
|
(2,393
|
)
|
|
1,607
|
|
|||
|
|
|
|
|
|
||||||
Earnings (Loss) Per Share
|
|
|
|
|
|
||||||
Basic
|
$
|
(2.32
|
)
|
|
$
|
(5.64
|
)
|
|
$
|
4.01
|
|
Diluted
|
(2.32
|
)
|
|
(5.64
|
)
|
|
3.94
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
•
|
1,527,584
common units, representing a
4.8%
limited partner interest in Noble Midstream Partners;
|
•
|
15,902,584
subordinated units, representing an approximate
50.0%
limited partner interest in Noble Midstream Partners;
|
•
|
incentive distribution rights in Noble Midstream Partners; and
|
•
|
the right to receive a cash distribution from Noble Midstream Partners.
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
2016
|
|
2015
|
|
2014
|
||||||
Onshore US
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
42
|
|
Deepwater Gulf of Mexico
|
—
|
|
|
158
|
|
|
350
|
|
|||
Israel
|
88
|
|
|
36
|
|
|
14
|
|
|||
Equatorial Guinea
|
—
|
|
|
339
|
|
|
—
|
|
|||
North Sea
|
—
|
|
|
—
|
|
|
94
|
|
|||
Other International and Corporate
|
4
|
|
|
—
|
|
|
—
|
|
|||
Total
|
$
|
92
|
|
|
$
|
533
|
|
|
$
|
500
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
2016
|
|
2015
|
|
2014
|
||||||
Capitalized Exploratory Well Costs, Beginning of Period
|
$
|
1,353
|
|
|
$
|
1,337
|
|
|
$
|
1,301
|
|
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves
|
84
|
|
|
123
|
|
|
316
|
|
|||
Divestitures and Other
(1)
|
(143
|
)
|
|
—
|
|
|
—
|
|
|||
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves or to Assets Held for Sale
(2)
|
(1
|
)
|
|
(19
|
)
|
|
(196
|
)
|
|||
Capitalized Exploratory Well Costs Charged to Expense
(3)
|
(525
|
)
|
|
(88
|
)
|
|
(84
|
)
|
|||
Capitalized Exploratory Well Costs, End of Period
|
$
|
768
|
|
|
$
|
1,353
|
|
|
$
|
1,337
|
|
|
December 31,
|
||||||||||
(millions)
|
2016
|
|
2015
|
|
2014
|
||||||
Exploratory Well Costs Capitalized for a Period of One Year or Less
|
$
|
69
|
|
|
$
|
95
|
|
|
$
|
247
|
|
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling
|
699
|
|
|
1,258
|
|
|
1,090
|
|
|||
Balance at End of Period
|
$
|
768
|
|
|
$
|
1,353
|
|
|
$
|
1,337
|
|
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling
|
10
|
|
|
14
|
|
|
13
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
|
Suspended Since
|
|
|
||||||||||||||
Country/Project
(millions)
|
Total
|
|
2014 - 2015
|
|
2012 - 2013
|
|
2011 & Prior
|
|
Progress
|
||||||||||
Deepwater Gulf of Mexico
|
|
|
|
|
|
|
|
|
|
||||||||||
Troubadour
|
52
|
|
|
5
|
|
|
47
|
|
|
—
|
|
|
Evaluating development scenarios for this 2013 natural gas discovery including subsea tieback to existing infrastructure.
|
||||||
Katmai
|
98
|
|
|
98
|
|
|
—
|
|
|
—
|
|
|
Evaluating development scenarios for this 2014 crude oil discovery. In second quarter 2016, drilling operations at the Katmai 2 appraisal well, located in Green Canyon Block 39, were temporarily abandoned as a result of encountering high pressure in the untested fault block. We are assessing plans to progress appraisal and are evaluating tie-back options.
|
||||||
Offshore Equatorial Guinea
|
|
|
|
|
|
|
|
|
|
||||||||||
Felicita (Block O)
|
45
|
|
|
7
|
|
—
|
|
9
|
|
—
|
|
29
|
|
|
Evaluating regional development scenarios for this 2008 gas discovery. During 2014, we conducted additional seismic activity over Blocks I and O and in early 2016, we began analyzing, interpreting and evaluating the acquired seismic data.
|
||||
Yolanda (Block I)
|
22
|
|
|
3
|
|
|
5
|
|
|
14
|
|
|
A data exchange agreement for the 2007 Yolanda condensate and natural gas discovery has been executed between the governments of Equatorial Guinea and Cameroon. Our natural gas development team is working with the governments of Equatorial Guinea and Cameroon to evaluate natural gas monetization options for both Yolanda and YoYo (Cameroon) discoveries.
|
||||||
Offshore Cameroon
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
YoYo (YoYo Block)
|
54
|
|
|
6
|
|
|
13
|
|
|
35
|
|
|
A data exchange agreement for the 2007 YoYo condensate and natural gas discovery has been executed between the governments of Equatorial Guinea and Cameroon. Our natural gas development team is working with the governments of Equatorial Guinea and Cameroon to evaluate natural gas monetization options for both Yolanda (Equatorial Guinea) and YoYo discoveries.
|
||||||
Offshore Israel
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Leviathan
|
199
|
|
|
18
|
|
|
77
|
|
|
104
|
|
|
Our development plan was approved by the Government of Israel and we are engaged in natural gas marketing activities to meet both Israeli domestic and regional export demands. We anticipate near-term project sanction and commencement of development activities.
|
||||||
Leviathan-1 Deep
|
85
|
|
|
7
|
|
|
51
|
|
|
27
|
|
|
The well did not reach the target interval in 2012. We are developing future drilling plans to test this deep oil concept, which is held by the Leviathan Development and Production Leases.
|
||||||
Dalit
|
31
|
|
|
4
|
|
|
7
|
|
|
20
|
|
|
Our development plan was approved by the Government of Israel to develop this 2009 natural gas discovery with a tie-in to existing infrastructure at Tamar.
|
||||||
Offshore Cyprus
|
|
|
|
|
|
|
|
|
|
||||||||||
Cyprus
|
89
|
|
|
12
|
|
|
54
|
|
|
23
|
|
|
During first quarter 2016, we received proceeds of $131 million from our 35% farm-down of interest with a partner in Block 12. In second quarter 2016, we submitted an updated development plan and continue to work with the Government of Cyprus to obtain approval of the development plan and the subsequent issuance of an Exploitation License. Receiving an Exploitation License will allow us and our partners to perform the necessary engineering and design studies and progress the project to final investment decision.
|
||||||
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Projects less than $20 million
|
24
|
|
|
23
|
|
|
—
|
|
|
1
|
|
|
Continuing to assess and evaluate wells.
|
||||||
Total
|
$
|
699
|
|
|
$
|
183
|
|
|
$
|
263
|
|
|
$
|
253
|
|
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
•
|
50%
interest in CONE Gathering LLC (CONE Gathering), which owns and operates natural gas gathering facilities servicing our properties in the Marcellus Shale;
|
•
|
33.5%
interest in CONE Midstream Partners, LP (CONE Midstream), a public master limited partnership, which constructs, owns and operates natural gas gathering and other midstream energy assets in support of our Marcellus Shale activities;
|
•
|
45%
interest in Atlantic Methanol Production Company, LLC (AMPCO), which owns and operates a methanol plant and related facilities in Equatorial Guinea; and
|
•
|
28%
interest in Alba Plant LLC (Alba Plant), which owns and operates a liquefied petroleum gas processing plant in Equatorial Guinea.
|
|
|
December 31,
|
||||||
(millions)
|
|
2016
|
|
2015
|
||||
Equity Method Investments
|
|
|
|
|
||||
CONE Investments
(1)
|
|
$
|
172
|
|
|
$
|
214
|
|
AMPCO
|
|
120
|
|
|
120
|
|
||
Alba Plant
|
|
82
|
|
|
87
|
|
||
Other
|
|
26
|
|
|
32
|
|
||
Total Equity Method Investments
|
|
$
|
400
|
|
|
$
|
453
|
|
(1)
|
CONE Investments include CONE Midstream and CONE Gathering.
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
December 31,
|
||||||
(millions)
|
|
2016
|
|
2015
|
||||
Balance Sheet Information
|
|
|
|
|
||||
Current Assets
|
|
$
|
313
|
|
|
$
|
343
|
|
Noncurrent Assets
|
|
1,390
|
|
|
1,418
|
|
||
Current Liabilities
|
|
149
|
|
|
229
|
|
||
Noncurrent Liabilities
|
|
256
|
|
|
108
|
|
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Statements of Operations Information
|
|
|
|
|
|
|
||||||
Operating Revenues
|
|
$
|
667
|
|
|
$
|
645
|
|
|
$
|
1,142
|
|
Operating Expenses
|
|
355
|
|
|
393
|
|
|
405
|
|
|||
Operating Income
|
|
312
|
|
|
252
|
|
|
737
|
|
|||
Other (Income) Net
|
|
(7
|
)
|
|
(9
|
)
|
|
(9
|
)
|
|||
Income Before Income Taxes
|
|
319
|
|
|
261
|
|
|
746
|
|
|||
Income Tax Provision
|
|
60
|
|
|
46
|
|
|
172
|
|
|||
Net Income
|
|
$
|
259
|
|
|
$
|
215
|
|
|
$
|
574
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
|
|
Swaps
|
|
Collars
|
||||||||||
Settlement
Period
|
Type of Contract
|
Index
|
Bbls Per
Day
|
Weighted
Average
Fixed
Price
|
|
Weighted
Average
Short Put
Price
|
Weighted
Average
Floor
Price
|
Weighted
Average
Ceiling
Price
|
||||||||
1H17
(1)
|
Swaps
|
NYMEX WTI
|
6,000
|
$
|
55.08
|
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
1H17
(1)
|
Two-Way Collars
|
NYMEX WTI
|
2,000
|
—
|
|
|
—
|
|
40.00
|
|
50.44
|
|
||||
1H17
(1)
|
Swaps
|
Dated Brent
|
3,000
|
62.80
|
|
|
—
|
|
—
|
|
—
|
|
||||
2H17
(1)
|
Call Option
(2)
|
NYMEX WTI
|
3,000
|
—
|
|
|
—
|
|
—
|
|
60.12
|
|
||||
2H17
(1)
|
Swaptions
(3)
|
NYMEX WTI
|
3,000
|
50.05
|
|
|
—
|
|
—
|
|
—
|
|
||||
2H17
(1)
|
Swaptions
(3)
|
Dated Brent
|
3,000
|
62.80
|
|
|
—
|
|
—
|
|
—
|
|
||||
2017
|
Three-Way Collars
|
NYMEX WTI
|
24,000
|
—
|
|
|
39.08
|
|
47.71
|
|
61.20
|
|
||||
2017
|
Two-Way Collars
|
NYMEX WTI
|
7,000
|
—
|
|
|
—
|
|
40.00
|
|
53.29
|
|
||||
2017
|
Swaps
|
NYMEX WTI
|
4,000
|
50.90
|
|
|
—
|
|
—
|
|
—
|
|
||||
2017
|
Call Option
(2)
|
NYMEX WTI
|
3,000
|
—
|
|
|
—
|
|
—
|
|
57.00
|
|
||||
2017
|
Three-Way Collars
|
ICE Brent
|
2,000
|
—
|
|
|
43.00
|
|
50.00
|
|
63.15
|
|
||||
2017
|
Three-Way Collars
|
Dated Brent
|
2,000
|
—
|
|
|
35.00
|
|
45.00
|
|
66.33
|
|
||||
2018
|
Three-Way Collars
|
NYMEX WTI
|
5,000
|
—
|
|
|
43.00
|
|
50.00
|
|
68.50
|
|
||||
2018
|
Swaps
|
NYMEX WTI
|
5,000
|
54.03
|
|
|
—
|
|
—
|
|
—
|
|
||||
2018
|
Swaptions
(3)
|
NYMEX WTI
|
3,000
|
56.10
|
|
|
—
|
|
—
|
|
—
|
|
||||
2018
|
Three-Way Collars
|
Dated Brent
|
3,000
|
—
|
|
|
40.00
|
|
50.00
|
|
70.41
|
|
(1)
|
We traditionally enter into a hedge contract term of one year. For 2017 we have entered into various derivative hedging arrangements with a contract term of six months resulting in non-uniform annual volumes and weighted average prices.
|
(2)
|
We have entered into crude oil derivative enhanced swaps with strike prices that are above the market value as of trade commencement. To effect the enhanced non-cash swap structure, we sold call options to the applicable counterparty to receive the above market terms.
|
(3)
|
We have entered into certain derivative contracts (swaptions), which give counterparties the option to extend with similar terms for an additional 6-month or 12-month period.
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
(1)
|
We traditionally enter into a hedge contract term of one year. For 2017 we have entered into various derivative hedging arrangements with a contract term of six months resulting in non-uniform annual volumes and weighted average prices.
|
(2)
|
We have entered into certain derivative contracts (swaptions), which give counterparties the option to extend with similar terms for an additional 6-month or 12-month period.
|
Fair Value of Derivative Instruments
|
|||||||||||||||||||||||
|
Asset Derivative Instruments
|
|
Liability Derivative Instruments
|
||||||||||||||||||||
|
December 31,
2016 |
|
December 31,
2015 |
|
December 31,
2016 |
|
December 31,
2015 |
||||||||||||||||
|
Balance
Sheet
Location
|
|
Fair
Value
|
|
Balance Sheet Location
|
|
Fair
Value
|
|
Balance Sheet Location
|
|
Fair
Value
|
|
Balance Sheet Location
|
|
Fair
Value
|
||||||||
(millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Commodity Derivative
Instruments
|
Current
Assets
|
|
$
|
—
|
|
|
Current Assets
|
|
$
|
582
|
|
|
Current Liabilities
|
|
$
|
102
|
|
|
Current Liabilities
|
|
$
|
—
|
|
|
Noncurrent Assets
|
|
—
|
|
|
Noncurrent Assets
|
|
10
|
|
|
Noncurrent Liabilities
|
|
14
|
|
|
Noncurrent Liabilities
|
|
—
|
|
||||
Total
|
|
|
$
|
—
|
|
|
|
|
$
|
592
|
|
|
|
|
$
|
116
|
|
|
|
|
$
|
—
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
2016
|
|
2015
|
|
2014
|
||||||
Cash (Received) Paid in Settlement of Commodity Derivative Instruments
|
|
|
|
|
|
||||||
Crude Oil
|
$
|
(499
|
)
|
|
$
|
(844
|
)
|
|
$
|
(34
|
)
|
Natural Gas
|
(70
|
)
|
|
(147
|
)
|
|
5
|
|
|||
NGLs
(1)
|
—
|
|
|
(18
|
)
|
|
—
|
|
|||
Total Cash Received in Settlement of Commodity Derivative Instruments
|
(569
|
)
|
|
(1,009
|
)
|
|
(29
|
)
|
|||
Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments
|
|
|
|
|
|
||||||
Crude Oil
|
582
|
|
|
423
|
|
|
(863
|
)
|
|||
Natural Gas
|
126
|
|
|
65
|
|
|
(84
|
)
|
|||
NGLs
(1)
|
—
|
|
|
20
|
|
|
—
|
|
|||
Total Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments
|
708
|
|
|
508
|
|
|
(947
|
)
|
|||
Loss (Gain) on Commodity Derivative Instruments
|
|
|
|
|
|
||||||
Crude Oil
|
83
|
|
|
(421
|
)
|
|
(897
|
)
|
|||
Natural Gas
|
56
|
|
|
(82
|
)
|
|
(79
|
)
|
|||
NGLs
(1)
|
—
|
|
|
2
|
|
|
—
|
|
|||
Total Loss (Gain) on Commodity Derivative Instruments
|
$
|
139
|
|
|
$
|
(501
|
)
|
|
$
|
(976
|
)
|
(1)
|
Amounts for NGLs relate to commodity derivative instruments, acquired in the Rosetta Merger, which expired as of December 31, 2015.
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
Year Ended December 31,
|
||||||
(millions)
|
2016
|
|
2015
|
||||
Asset Retirement Obligations, Beginning Balance
|
$
|
989
|
|
|
$
|
751
|
|
Liabilities Incurred
|
21
|
|
|
67
|
|
||
Liabilities Settled
|
(120
|
)
|
|
(38
|
)
|
||
Revision of Estimate
|
(3
|
)
|
|
166
|
|
||
Accretion Expense
|
48
|
|
|
43
|
|
||
Asset Retirement Obligations, Ending Balance
|
$
|
935
|
|
|
$
|
989
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
December 31,
2016 |
|
December 31,
2015 |
||||||||||
(millions, except percentages)
|
Debt
|
|
Interest Rate
|
|
Debt
|
|
Interest Rate
|
||||||
Revolving Credit Facility, due August 27, 2020
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
Noble Midstream Revolving Credit Facility, due September 20, 2021
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||
Capital Lease and Other Obligations
|
375
|
|
|
—
|
|
|
403
|
|
|
—
|
|
||
Term Loan Facility, due January 6, 2019
|
550
|
|
|
2.01
|
%
|
|
—
|
|
|
—
|
|
||
8.25% Senior Notes, due March 1, 2019
|
1,000
|
|
|
8.25
|
%
|
|
1,000
|
|
|
8.25
|
%
|
||
5.625% Senior Notes, due May 1, 2021
(1)
|
379
|
|
|
5.63
|
%
|
|
693
|
|
|
5.63
|
%
|
||
4.15% Senior Notes, due December 15, 2021
|
1,000
|
|
|
4.15
|
%
|
|
1,000
|
|
|
4.15
|
%
|
||
5.875% Senior Notes, due June 1, 2022
(1)
|
18
|
|
|
5.88
|
%
|
|
597
|
|
|
5.88
|
%
|
||
7.25% Senior Notes, due October 15, 2023
|
100
|
|
|
7.25
|
%
|
|
100
|
|
|
7.25
|
%
|
||
5.875% Senior Notes, due June 1, 2024
(1)
|
8
|
|
|
5.88
|
%
|
|
499
|
|
|
5.88
|
%
|
||
3.90% Senior Notes, due November 15, 2024
|
650
|
|
|
3.90
|
%
|
|
650
|
|
|
3.90
|
%
|
||
8.00% Senior Notes, due April 1, 2027
|
250
|
|
|
8.00
|
%
|
|
250
|
|
|
8.00
|
%
|
||
6.00% Senior Notes, due March 1, 2041
|
850
|
|
|
6.00
|
%
|
|
850
|
|
|
6.00
|
%
|
||
5.25% Senior Notes, due November 15, 2043
|
1,000
|
|
|
5.25
|
%
|
|
1,000
|
|
|
5.25
|
%
|
||
5.05% Senior Notes, due November 15, 2044
|
850
|
|
|
5.05
|
%
|
|
850
|
|
|
5.05
|
%
|
||
7.25% Senior Debentures, due August 1, 2097
|
84
|
|
|
7.25
|
%
|
|
84
|
|
|
7.25
|
%
|
||
Total
|
$
|
7,114
|
|
|
|
|
|
$
|
7,976
|
|
|
|
|
Unamortized Discount
|
(23
|
)
|
|
|
|
|
(24
|
)
|
|
|
|
||
Unamortized Premium
(2)
|
17
|
|
|
|
|
113
|
|
|
|
||||
Unamortized Debt Issuance Costs
|
(34
|
)
|
|
|
|
(36
|
)
|
|
|
||||
Total Debt, Net of Discount
|
$
|
7,074
|
|
|
|
|
|
$
|
8,029
|
|
|
|
|
Less Amounts Due Within One Year
|
|
|
|
|
|
|
|
|
|
|
|
||
Capital Lease and Other Obligations
|
(63
|
)
|
|
|
|
|
(53
|
)
|
|
|
|
||
Long-Term Debt Due After One Year
|
$
|
7,011
|
|
|
|
|
|
$
|
7,976
|
|
|
|
|
(1)
|
Represents senior notes assumed in the Rosetta Merger. See
Note
3. Acquisitions, Divestitures and Merger
.
|
(2)
|
Debt premium is attributable to senior notes assumed in the Rosetta Merger.
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
•
|
in the case of base rate borrowings, a rate equal to the highest of (1) the prime rate, (2) the greater of the federal funds rate or the overnight bank funding rate, plus
0.5%
and (3) the LIBOR for an interest period of one month plus
1.00%
; or
|
•
|
in the case of London interbank offered rate (LIBOR) borrowings, the offered rate per annum for deposits of dollars for the applicable interest period.
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Domestic
|
|
$
|
(1,859
|
)
|
|
$
|
(2,338
|
)
|
|
$
|
282
|
|
Foreign
|
|
87
|
|
|
119
|
|
|
1,428
|
|
|||
Total
|
|
$
|
(1,772
|
)
|
|
$
|
(2,219
|
)
|
|
$
|
1,710
|
|
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Current Taxes
|
|
|
|
|
|
|
||||||
Federal
|
|
$
|
(4
|
)
|
|
$
|
(1
|
)
|
|
$
|
19
|
|
State
|
|
5
|
|
|
—
|
|
|
1
|
|
|||
Foreign
|
|
196
|
|
|
107
|
|
|
208
|
|
|||
Total Current
|
|
$
|
197
|
|
|
$
|
106
|
|
|
$
|
228
|
|
Deferred Taxes
|
|
|
|
|
|
|
|
|
|
|||
Federal
|
|
$
|
(784
|
)
|
|
$
|
216
|
|
|
$
|
237
|
|
State
|
|
(24
|
)
|
|
(5
|
)
|
|
13
|
|
|||
Foreign
|
|
(176
|
)
|
|
(95
|
)
|
|
18
|
|
|||
Total Deferred
|
|
$
|
(984
|
)
|
|
$
|
116
|
|
|
$
|
268
|
|
Total Income Tax Provision (Benefit) Attributable to Noble Energy
|
|
$
|
(787
|
)
|
|
$
|
222
|
|
|
$
|
496
|
|
Effective Tax Rate
|
|
44.4
|
%
|
|
(10.0
|
)%
|
|
29.0
|
%
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
December 31,
|
||||||
(millions)
|
|
2016
|
|
2015
|
||||
Deferred Tax Assets
|
|
|
|
|
||||
Loss Carryforwards
|
|
$
|
474
|
|
|
$
|
468
|
|
Employee Compensation and Benefits
|
|
150
|
|
|
151
|
|
||
Other
|
|
49
|
|
|
81
|
|
||
Total Deferred Tax Assets
|
|
$
|
673
|
|
|
$
|
700
|
|
Valuation Allowance - Foreign Loss Carryforwards
|
|
(242
|
)
|
|
(206
|
)
|
||
Net Deferred Tax Assets
|
|
$
|
431
|
|
|
$
|
494
|
|
Deferred Tax Liabilities
|
|
|
|
|
|
|
||
Mark to Market of Commodity Derivative Instruments
|
|
44
|
|
|
(128
|
)
|
||
Accumulated Undistributed Foreign Earnings
|
|
(240
|
)
|
|
(368
|
)
|
||
Property, Plant and Equipment, Principally Due to Differences in Depreciation, Amortization, Lease Impairment and Abandonments
|
|
(2,054
|
)
|
|
(2,824
|
)
|
||
Total Deferred Tax Liability
|
|
$
|
(2,250
|
)
|
|
$
|
(3,320
|
)
|
Net Deferred Tax Liability
|
|
$
|
(1,819
|
)
|
|
$
|
(2,826
|
)
|
|
|
December 31,
|
||||||
(millions)
|
|
2016
|
|
2015
|
||||
Deferred Income Tax Liability - Current
|
|
$
|
—
|
|
|
$
|
—
|
|
Deferred Income Tax Liability - Noncurrent
|
|
(1,819
|
)
|
|
(2,826
|
)
|
||
Net Deferred Tax Liability
|
|
$
|
(1,819
|
)
|
|
$
|
(2,826
|
)
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
(millions)
|
|
Twelve Months Ended December 31, 2016
|
||
Unrecognized Tax Benefits, Beginning Balance
|
|
$
|
8
|
|
Additions for Tax Positions Related to Current Year
|
|
—
|
|
|
Additions for Tax Positions of Prior Years
|
|
—
|
|
|
Reductions for Tax Positions of Prior Years
|
|
(3
|
)
|
|
Settlements
|
|
(2
|
)
|
|
Unrecognized Tax Benefits, Ending Balance
|
|
$
|
3
|
|
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Stock-Based Compensation Expense Included in
|
|
|
|
|
|
|
||||||
General and Administrative Expense
|
|
$
|
62
|
|
|
$
|
50
|
|
|
$
|
63
|
|
Exploration Expense and Other
|
|
15
|
|
|
36
|
|
|
24
|
|
|||
Total Stock-Based Compensation Expense
|
|
$
|
77
|
|
|
$
|
86
|
|
|
$
|
87
|
|
Tax Benefit Recognized
|
|
$
|
(27
|
)
|
|
$
|
(30
|
)
|
|
$
|
(31
|
)
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
•
|
Expected term
The expected term represents the period of time that options granted are expected to be outstanding, which is the grant date to the date of expected exercise or other expected settlement for options granted. The hypothetical midpoint scenario we use considers our actual exercise and post-vesting cancellation history and expectations for future periods, which assumes that all vested, outstanding options are settled halfway between the current date and their expiration date.
|
•
|
Expected volatility
The expected volatility represents the extent to which our stock price is expected to fluctuate between the grant date and the expected term of the award. We use the historical volatility of our common stock for a period equal to the expected term of the option prior to the date of grant. We believe that historical volatility produces an estimate that is representative of our expectations about the future volatility of our common stock over the expected term.
|
•
|
Risk-free rate
The risk-free rate is the implied yield available on US Treasury securities with a remaining term equal to the expected term of the option. We base our risk-free rate on a weighting of
five
and
seven
year US Treasury securities as of the date of grant.
|
•
|
Dividend yield
The dividend yield represents the value of our stock’s annualized dividend as compared to our stock’s average price for the
three
-year period ended prior to the date of grant. It is calculated by dividing
one
full year of our expected dividends by our average stock price over the
three
-year period ended prior to the date of grant.
|
|
|
Year Ended December 31,
|
||||||||||
(weighted averages)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Expected Term (in Years)
|
|
6.3
|
|
|
6.0
|
|
|
5.9
|
|
|||
Expected Volatility
|
|
32.4
|
%
|
|
32.6
|
%
|
|
35.1
|
%
|
|||
Risk-Free Rate
|
|
1.6
|
%
|
|
1.4
|
%
|
|
1.8
|
%
|
|||
Expected Dividend Yield
|
|
0.7
|
%
|
|
1.2
|
%
|
|
1.1
|
%
|
|||
Weighted Average Grant-Date Fair Value
|
|
$
|
10.10
|
|
|
$
|
13.93
|
|
|
$
|
20.31
|
|
|
|
Options
|
|
Weighted
Average
Exercise
Price
|
|
Weighted
Average
Remaining
Contractual Term
|
|
Aggregate
Intrinsic Value
|
|||||
|
|
|
|
(per share)
|
|
(in years)
|
|
(in millions)
|
|||||
Outstanding at December 31, 2015
|
|
14,571,012
|
|
|
$
|
44.59
|
|
|
|
|
|
||
Granted
|
|
2,441,042
|
|
|
31.66
|
|
|
|
|
|
|||
Exercised
|
|
(954,898
|
)
|
|
25.96
|
|
|
|
|
|
|||
Forfeited
|
|
(968,294
|
)
|
|
47.27
|
|
|
|
|
|
|||
Outstanding at December 31, 2016
|
|
15,088,862
|
|
|
$
|
43.49
|
|
|
5.4
|
|
$
|
40
|
|
Exercisable at December 31, 2016
|
|
10,999,318
|
|
|
$
|
44.54
|
|
|
4.3
|
|
$
|
26
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
Year Ended December 31,
|
||||
|
2016
|
|
2015
|
||
Number of Simulations
|
500,000
|
|
|
500,000
|
|
Expected Volatility
|
38
|
%
|
|
30
|
%
|
Risk-Free Rate
|
1.0
|
%
|
|
0.8
|
%
|
|
|
Subject to Time Vesting
|
|
Subject to Market Conditions
|
||||||||||
|
|
Number of Shares
|
|
Weighted
Average
Award Date
Fair Value
|
|
Number of Shares
|
|
Weighted Average Award Date Fair Value
|
||||||
|
|
|
|
(per share)
|
|
|
|
(per share)
|
||||||
Outstanding at December 31, 2015
|
|
1,019,470
|
|
|
$
|
45.55
|
|
|
1,929,922
|
|
|
$
|
28.50
|
|
Awarded
|
|
898,916
|
|
|
31.67
|
|
|
363,256
|
|
|
24.80
|
|
||
Vested
|
|
(421,227
|
)
|
|
52.50
|
|
|
(340,410
|
)
|
|
42.71
|
|
||
Forfeited
|
|
(125,379
|
)
|
|
35.54
|
|
|
(449,776
|
)
|
|
37.86
|
|
||
Outstanding at December 31, 2016
|
|
1,371,780
|
|
|
$
|
36.37
|
|
|
1,502,992
|
|
|
$
|
27.43
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
Subject to Time Vesting
|
|
Subject to Market Conditions
|
||||||||||
|
|
Number of Units
|
|
Weighted
Average Award Date Fair Value |
|
Number of Units
|
|
Weighted Average Award Date Fair Value
|
||||||
|
|
|
|
(per share)
|
|
|
|
(per share)
|
||||||
Outstanding at December 31, 2015
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
Awarded
|
|
791,000
|
|
|
31.65
|
|
|
218,180
|
|
|
6.82
|
|
||
Vested
|
|
(2,501
|
)
|
|
31.65
|
|
|
—
|
|
|
—
|
|
||
Forfeited
|
|
(76,410
|
)
|
|
31.65
|
|
|
(8,676
|
)
|
|
6.82
|
|
||
Outstanding at December 31, 2016
|
|
712,089
|
|
|
$
|
31.65
|
|
|
209,504
|
|
|
$
|
6.82
|
|
|
|
December 31,
|
||||||
(millions, except share amounts)
|
|
2016
|
|
2015
|
||||
Rabbi Trust Assets
|
|
|
|
|
||||
Mutual Fund Investments
|
|
$
|
62
|
|
|
$
|
63
|
|
Noble Energy Common Stock (at Fair Value)
|
|
26
|
|
|
35
|
|
||
Total Rabbi Trust Assets
|
|
$
|
88
|
|
|
$
|
98
|
|
Liability Under Related Deferred Compensation Plan
|
|
$
|
88
|
|
|
$
|
98
|
|
Number of Shares of Noble Energy Common Stock Held by Rabbi Trust
|
|
671,269
|
|
|
872,277
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
Fair Value Measurements Using
|
|
|
|
|
|||||||||||||||
(millions)
|
Quoted Prices in Active Markets
(Level 1)
(1)
|
|
Significant Other
Observable Inputs
(Level 2)
(1)
|
|
Significant
Unobservable
Inputs (Level 3)
(1)
|
|
Adjustment
(2)
|
|
Fair Value Measurement
|
|||||||||||
December 31, 2016
|
|
|
|
|
|
|
|
|
|
|||||||||||
Financial Assets
|
|
|
|
|
|
|
|
|
|
|||||||||||
Mutual Fund Investments
|
$
|
71
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
71
|
|
|
Commodity Derivative Instruments
|
—
|
|
|
5
|
|
|
—
|
|
|
(5
|
)
|
|
—
|
|
||||||
Financial Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Commodity Derivative Instruments
|
—
|
|
|
(121
|
)
|
|
—
|
|
|
5
|
|
|
(116
|
)
|
||||||
Portion of Deferred Compensation Liability Measured at Fair Value
|
(88
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(88
|
)
|
||||||
Stock Based Compensation Liability Measured at Fair Value
|
(9
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
—
|
|
(9
|
)
|
|||||
December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Financial Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Mutual Fund Investments
|
$
|
90
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
90
|
|
|
Commodity Derivative Instruments
|
—
|
|
|
600
|
|
|
|
|
|
(8
|
)
|
|
592
|
|
||||||
Financial Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Commodity Derivative Instruments
|
—
|
|
|
(8
|
)
|
|
—
|
|
|
8
|
|
|
—
|
|
||||||
Portion of Deferred Compensation Liability Measured at Fair Value
|
(98
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(98
|
)
|
(1)
|
See
Note
1. Summary of Significant Accounting Policies
- Fair Value Measurements
for a description of the fair value hierarchy.
|
(2)
|
Amount represents the impact of netting clauses within our master agreements that allow us to net cash settle asset and liability positions with the same counterparty.
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
Fair Value Measurements Using
|
|
|
|
|
||||||||||||||
Description
|
Quoted Prices in Active Markets (Level 1)
(1)
|
|
Significant Other Observable Inputs
(Level 2)
(1)
|
|
Significant Unobservable Inputs (Level 3)
(1)
|
|
Net Book Value
(2)
|
|
Total Pre-tax (Non-cash) Impairment Loss
|
||||||||||
(millions)
|
|
|
|
|
|
|
|
|
|
||||||||||
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|||||||||||
Impaired Oil and Gas Properties
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
92
|
|
|
$
|
92
|
|
Impaired Materials and Supplies Inventory
|
—
|
|
|
—
|
|
|
91
|
|
|
105
|
|
|
14
|
|
|||||
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
|
|||||||||||
Impaired Oil and Gas Properties
|
—
|
|
|
—
|
|
|
752
|
|
|
1,285
|
|
|
533
|
|
|||||
Impaired Materials and Supplies Inventory
|
—
|
|
|
—
|
|
|
61
|
|
|
81
|
|
|
20
|
|
|||||
Year Ended December 31, 2014
|
|
|
|
|
|
|
|
|
|||||||||||
Impaired Oil and Gas Properties
|
—
|
|
|
—
|
|
|
100
|
|
|
600
|
|
|
500
|
|
(1)
|
See
Note
1. Summary of Significant Accounting Policies
- Fair Value Measurements
for a description of the fair value hierarchy.
|
(2)
|
Amount represents net book value at the date of assessment.
|
|
December 31,
2016 |
|
December 31,
2015 |
||||||||||||
(millions)
|
Carrying Amount
|
|
Fair Value
|
|
Carrying Amount
|
|
Fair Value
|
||||||||
Long-Term Debt, Net
(1)
|
$
|
6,699
|
|
|
$
|
7,112
|
|
|
$
|
7,626
|
|
|
$
|
7,105
|
|
(1)
|
Net of unamortized discount, premium and debt issuance costs and excludes capital lease and other obligations.
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
Year Ended December 31,
|
||||||||||
(millions, except per share amounts)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Net Income (Loss) Attributable to Noble Energy
|
|
$
|
(998
|
)
|
|
$
|
(2,441
|
)
|
|
$
|
1,214
|
|
Earnings Adjustment from Assumed Conversion of Dilutive Shares of Common Stock in Rabbi Trust
(1)
|
|
—
|
|
|
—
|
|
|
(17
|
)
|
|||
Net Income (Loss) Used for Diluted Earnings (Loss) Per Share Calculation
|
|
$
|
(998
|
)
|
|
$
|
(2,441
|
)
|
|
$
|
1,197
|
|
|
|
|
|
|
|
|
||||||
Weighted Average Number of Shares Outstanding, Basic
(2)
|
|
430
|
|
|
402
|
|
|
361
|
|
|||
Incremental Shares From Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust
(1)
|
|
—
|
|
|
—
|
|
|
6
|
|
|||
Weighted Average Number of Shares Outstanding, Diluted
|
|
430
|
|
|
402
|
|
|
367
|
|
|||
Earnings (Loss) Attributable to Noble Energy Per Share, Basic
|
|
$
|
(2.32
|
)
|
|
$
|
(6.07
|
)
|
|
$
|
3.36
|
|
Earnings (Loss) Attributable to Noble Energy Per Share, Diluted
|
|
(2.32
|
)
|
|
(6.07
|
)
|
|
3.27
|
|
|||
|
|
|
|
|
|
|
||||||
Additional Information
|
|
|
|
|
|
|
||||||
Number of antidilutive stock options, shares of restricted stock and shares of common stock in rabbi trust excluded from calculation above
|
|
14
|
|
|
10
|
|
|
3
|
|
|||
Weighted average option exercise price per share
|
|
$
|
45.69
|
|
|
$
|
52.39
|
|
|
$
|
60.30
|
|
(1)
|
For the years ended December 31, 2016 and 2015, all outstanding options and non-vested restricted shares have been excluded from the calculation of diluted earnings (loss) per share as Noble Energy incurred a loss. Therefore, inclusion of outstanding options and non-vested restricted shares in the calculation of diluted earnings (loss) per share would be anti-dilutive.
|
(2)
|
The weighted average number of shares outstanding for the year ended December 31, 2015 includes the weighted average shares of common stock issued in connection with the underwritten public offering of
24.15 million
shares of Noble Energy common stock in first quarter 2015 and issued in connection with the exchange of approximately
41 million
shares for all outstanding shares of Rosetta common stock on July 20, 2015.
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
Consolidated
|
|
United
States
|
|
Eastern
Mediter-ranean
|
|
West
Africa
|
|
Other Int'l &
Corporate
|
||||||||||
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues from Third Parties
(1)
|
$
|
3,389
|
|
|
$
|
2,416
|
|
|
$
|
540
|
|
|
$
|
433
|
|
|
$
|
—
|
|
Income from Equity Method Investees
|
102
|
|
|
52
|
|
|
—
|
|
|
50
|
|
|
—
|
|
|||||
Total Revenues
|
3,491
|
|
|
2,468
|
|
|
540
|
|
|
483
|
|
|
—
|
|
|||||
Exploration Expense
|
925
|
|
|
245
|
|
|
34
|
|
|
483
|
|
|
163
|
|
|||||
DD&A
|
2,454
|
|
|
2,122
|
|
|
81
|
|
|
205
|
|
|
46
|
|
|||||
Asset Impairments
|
92
|
|
|
—
|
|
|
88
|
|
|
—
|
|
|
4
|
|
|||||
Loss on Commodity Derivative Instruments
|
139
|
|
|
126
|
|
|
—
|
|
|
13
|
|
|
—
|
|
|||||
Income (Loss) Before Income Taxes
|
(1,772
|
)
|
|
(1,052
|
)
|
|
543
|
|
|
(338
|
)
|
|
(925
|
)
|
|||||
Equity Method Investments
|
400
|
|
|
183
|
|
|
—
|
|
|
217
|
|
|
—
|
|
|||||
Additions to Long-Lived Assets
|
1,526
|
|
|
1,359
|
|
|
88
|
|
|
54
|
|
|
25
|
|
|||||
Total Assets at End of Year
(2)
|
21,011
|
|
|
17,029
|
|
|
2,233
|
|
|
1,479
|
|
|
270
|
|
|||||
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Revenues from Third Parties
(1)
|
$
|
3,093
|
|
|
$
|
2,011
|
|
|
$
|
497
|
|
|
$
|
580
|
|
|
$
|
5
|
|
Income from Equity Method Investees
|
90
|
|
|
51
|
|
|
—
|
|
|
39
|
|
|
—
|
|
|||||
Total Revenues
|
3,183
|
|
|
2,062
|
|
|
497
|
|
|
619
|
|
|
5
|
|
|||||
Exploration Expense
|
488
|
|
|
203
|
|
|
12
|
|
|
46
|
|
|
227
|
|
|||||
DD&A
|
2,131
|
|
|
1,692
|
|
|
70
|
|
|
326
|
|
|
43
|
|
|||||
Asset Impairments
|
533
|
|
|
158
|
|
|
36
|
|
|
339
|
|
|
—
|
|
|||||
Goodwill Impairment
|
779
|
|
|
779
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Gain on Commodity Derivative Instruments
|
(501
|
)
|
|
(347
|
)
|
|
—
|
|
|
(154
|
)
|
|
—
|
|
|||||
Income (Loss) Before Income Taxes
|
(2,219
|
)
|
|
(1,553
|
)
|
|
306
|
|
|
(77
|
)
|
|
(895
|
)
|
|||||
Equity Method Investments
|
453
|
|
|
226
|
|
|
—
|
|
|
227
|
|
|
—
|
|
|||||
Additions to Long-Lived Assets
|
3,062
|
|
|
2,534
|
|
|
147
|
|
|
124
|
|
|
257
|
|
|||||
Goodwill at End of Year
(3)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Total Assets at End of Year
(2)
|
24,196
|
|
|
18,831
|
|
|
2,677
|
|
|
2,299
|
|
|
389
|
|
|||||
Year Ended December 31, 2014
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues from Third Parties
(1)
|
$
|
4,945
|
|
|
$
|
3,189
|
|
|
$
|
479
|
|
|
$
|
1,177
|
|
|
$
|
100
|
|
Income from Equity Method Investees
|
170
|
|
|
9
|
|
|
—
|
|
|
161
|
|
|
—
|
|
|||||
Total Revenues
|
5,115
|
|
|
3,198
|
|
|
479
|
|
|
1,338
|
|
|
100
|
|
|||||
Exploration Expense
|
498
|
|
|
268
|
|
|
17
|
|
|
26
|
|
|
187
|
|
|||||
DD&A
|
1,759
|
|
|
1,318
|
|
|
63
|
|
|
299
|
|
|
79
|
|
|||||
Asset Impairments
|
500
|
|
|
392
|
|
|
14
|
|
|
—
|
|
|
94
|
|
|||||
Gain on Divestitures
|
(73
|
)
|
|
(34
|
)
|
|
—
|
|
|
—
|
|
|
(39
|
)
|
|||||
Loss on Commodity Derivative Instruments
|
(976
|
)
|
|
(604
|
)
|
|
—
|
|
|
(372
|
)
|
|
—
|
|
|||||
Income (Loss) Before Income Taxes
|
1,710
|
|
|
1,150
|
|
|
284
|
|
|
1,222
|
|
|
(946
|
)
|
|||||
Equity Method Investments
|
325
|
|
|
82
|
|
|
—
|
|
|
223
|
|
|
20
|
|
|||||
Additions to Long-Lived Assets
|
5,152
|
|
|
4,389
|
|
|
201
|
|
|
261
|
|
|
301
|
|
|||||
Goodwill at End of Year
(3)
|
620
|
|
|
620
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Total Assets at End of Year
(2)
|
22,518
|
|
|
16,365
|
|
|
2,806
|
|
|
2,763
|
|
|
584
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
Percentage of Crude Oil Sales
|
|
Percentage of Total Oil, Gas & NGL Sales
|
||
Year Ended December 31, 2016
|
|
|
|
|
||
Glencore Energy UK Ltd
|
|
22
|
%
|
|
12
|
%
|
Shell
(1)
|
|
24
|
%
|
|
13
|
%
|
Year Ended December 31, 2015
|
|
|
|
|
|
|
Glencore Energy UK Ltd
|
|
30
|
%
|
|
18
|
%
|
Shell
(1)
|
|
18
|
%
|
|
11
|
%
|
Year Ended December 31, 2014
|
|
|
|
|
|
|
Glencore Energy UK Ltd
|
|
32
|
%
|
|
22
|
%
|
Shell
(1)
|
|
15
|
%
|
|
10
|
%
|
(1)
|
Includes sales to Shell Trading (US) Company and/or Shell International Trading and Shipping Limited.
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
Year Ended December 31,
|
||||
|
|
2016
|
|
2015
|
||
Common Stock Shares Issued
|
|
|
|
|
|
|
Shares, Beginning of Period
|
|
469,718,512
|
|
|
402,329,325
|
|
Exercise of Common Stock Options
|
|
954,898
|
|
|
343,145
|
|
Restricted Stock Awards, Net of Forfeitures
|
|
687,017
|
|
|
1,847,802
|
|
Public Equity Offering
|
|
—
|
|
|
24,150,000
|
|
Shares Exchanged in Rosetta Merger
|
|
—
|
|
|
41,048,240
|
|
Shares, End of Period
|
|
471,360,427
|
|
|
469,718,512
|
|
Treasury Stock
|
|
|
|
|
|
|
Shares, Beginning of Period
|
|
37,925,625
|
|
|
37,635,890
|
|
Shares Received From Employees in Payment of Withholding Taxes Due on Vesting of Shares of Restricted Stock
|
|
236,700
|
|
|
490,744
|
|
Rabbi Trust Shares Distributed and/or Sold
|
|
(201,009
|
)
|
|
(201,009
|
)
|
Shares, End of Period
|
|
37,961,316
|
|
|
37,925,625
|
|
|
Accumulated Other Comprehensive Loss
|
|||||||||||
(millions)
|
|
Interest Rate
Cash Flow
Hedges
|
|
Pension-
Related and
Other
|
|
Total
|
||||||
December 31, 2013
|
|
$
|
(24
|
)
|
|
$
|
(93
|
)
|
|
$
|
(117
|
)
|
Realized Amounts Reclassified Into Earnings
|
|
1
|
|
|
11
|
|
|
12
|
|
|||
Unrealized Change in Fair Value
|
|
—
|
|
|
15
|
|
|
15
|
|
|||
December 31, 2014
|
|
(23
|
)
|
|
(67
|
)
|
|
(90
|
)
|
|||
Realized Amounts Reclassified Into Earnings
|
|
1
|
|
|
62
|
|
|
63
|
|
|||
Unrealized Change in Fair Value
|
|
—
|
|
|
(6
|
)
|
|
(6
|
)
|
|||
December 31, 2015
|
|
(22
|
)
|
|
(11
|
)
|
|
(33
|
)
|
|||
Realized Amounts Reclassified Into Earnings
|
|
1
|
|
|
4
|
|
|
5
|
|
|||
Unrealized Change in Fair Value
|
|
—
|
|
|
(3
|
)
|
|
(3
|
)
|
|||
December 31, 2016
|
|
$
|
(21
|
)
|
|
$
|
(10
|
)
|
|
$
|
(31
|
)
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
(millions)
|
|
Drilling, Equipment,
and Purchase Obligations
|
|
Transportation
and Gathering Obligations
|
|
Operating
Lease
Obligations
|
|
Capital
Lease and Other Obligations
(1)
|
|
Total
|
||||||||||
2017
|
|
$
|
255
|
|
|
$
|
250
|
|
|
$
|
30
|
|
|
$
|
77
|
|
|
$
|
612
|
|
2018
|
|
96
|
|
|
312
|
|
|
42
|
|
|
79
|
|
|
529
|
|
|||||
2019
|
|
52
|
|
|
314
|
|
|
30
|
|
|
52
|
|
|
448
|
|
|||||
2020
|
|
27
|
|
|
275
|
|
|
28
|
|
|
52
|
|
|
382
|
|
|||||
2021
|
|
9
|
|
|
237
|
|
|
28
|
|
|
38
|
|
|
312
|
|
|||||
2022 and Thereafter
|
|
30
|
|
|
1,566
|
|
|
188
|
|
|
163
|
|
|
1,947
|
|
|||||
Total
|
|
$
|
469
|
|
|
$
|
2,954
|
|
|
$
|
346
|
|
|
$
|
461
|
|
|
$
|
4,230
|
|
(1)
|
Annual lease payments, net to our interest, exclude regular maintenance and operational costs. See
Note
10. Long-Term Debt
.
|
Noble Energy, Inc.
|
|
|
Supplemental Oil and Gas Information
|
|
|
|
(Unaudited)
|
|
Noble Energy, Inc.
|
|
|
Supplemental Oil and Gas Information
|
|
|
|
(Unaudited)
|
|
|
|
Crude Oil and Condensate (MMBbls)
|
||||||||||
|
|
United
States
|
|
Equatorial
Guinea
|
|
Other
Int'l
(1)
|
|
Total
|
||||
Proved Reserves as of:
|
|
|
|
|
|
|
|
|
||||
December 31, 2013
|
|
236
|
|
|
77
|
|
|
9
|
|
|
322
|
|
Revisions of Previous Estimates
(2)
|
|
(5
|
)
|
|
1
|
|
|
—
|
|
|
(4
|
)
|
Extensions, Discoveries and Other Additions
(3)
|
|
30
|
|
|
—
|
|
|
—
|
|
|
30
|
|
Purchase of Minerals in Place
(4)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Sale of Minerals in Place
(5)
|
|
—
|
|
|
—
|
|
|
(5
|
)
|
|
(5
|
)
|
Production
(6)
|
|
(25
|
)
|
|
(13
|
)
|
|
(1
|
)
|
|
(39
|
)
|
December 31, 2014
|
|
236
|
|
|
65
|
|
|
3
|
|
|
304
|
|
Revisions of Previous Estimates
(2)
|
|
(56
|
)
|
|
(5
|
)
|
|
—
|
|
|
(61
|
)
|
Extensions, Discoveries and Other Additions
(3)
|
|
42
|
|
|
—
|
|
|
—
|
|
|
42
|
|
Purchase of Minerals in Place
(4)
|
|
65
|
|
|
—
|
|
|
—
|
|
|
65
|
|
Sale of Minerals in Place
(5)
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
Production
(6)
|
|
(29
|
)
|
|
(12
|
)
|
|
—
|
|
|
(41
|
)
|
December 31, 2015
|
|
256
|
|
|
48
|
|
|
3
|
|
|
307
|
|
Revisions of Previous Estimates
(2)
|
|
14
|
|
|
(4
|
)
|
|
—
|
|
|
10
|
|
Extensions, Discoveries and Other Additions
(3)
|
|
66
|
|
|
—
|
|
|
—
|
|
|
66
|
|
Purchase of Minerals in Place
(4)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Sale of Minerals in Place
(5)
|
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
Production
(6)
|
|
(36
|
)
|
|
(10
|
)
|
|
—
|
|
|
(46
|
)
|
December 31, 2016
|
|
296
|
|
|
34
|
|
|
3
|
|
|
333
|
|
Proved Developed Reserves as of
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2013
|
|
102
|
|
|
64
|
|
|
8
|
|
|
174
|
|
December 31, 2014
|
|
119
|
|
|
52
|
|
|
3
|
|
|
174
|
|
December 31, 2015
|
|
137
|
|
|
34
|
|
|
3
|
|
|
174
|
|
December 31, 2016
|
|
138
|
|
|
34
|
|
|
3
|
|
|
175
|
|
Proved Undeveloped Reserves as of
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2013
|
|
134
|
|
|
12
|
|
|
2
|
|
|
148
|
|
December 31, 2014
|
|
117
|
|
|
13
|
|
|
—
|
|
|
130
|
|
December 31, 2015
|
|
119
|
|
|
14
|
|
|
—
|
|
|
133
|
|
December 31, 2016
|
|
158
|
|
|
—
|
|
|
—
|
|
|
158
|
|
(1)
|
Other International includes China (through June 2014), the North Sea (through 2014) and Israel.
|
(2)
|
The 2014 US revisions were primarily associated with positive performance revisions to our Marcellus Shale program and our deepwater Gulf of Mexico Swordfish field, offset by DJ Basin negative revisions due to a revised drilling plan in response to the current commodity price environment.
|
(3)
|
The 2014 increase in US reserves included an increase of 21 MMBbls in the DJ Basin and 2 MMBbls from Marcellus Shale development as well as 7 MMBbls in the deepwater Gulf of Mexico due to sanction of the Dantzler development project.
|
Noble Energy, Inc.
|
|
|
Supplemental Oil and Gas Information
|
|
|
|
(Unaudited)
|
|
(4)
|
The 2015 increase is attributable to reserves acquired in the Rosetta Merger.
|
(5)
|
In 2014, we sold our China assets.
|
(6)
|
Equatorial Guinea production includes sales from the Alba LPG plant of approximately
3
MMBbl in each of the years 2016, 2015, and 2014.
|
Noble Energy, Inc.
|
|
|
Supplemental Oil and Gas Information
|
|
|
|
(Unaudited)
|
|
|
|
Natural Gas and Casinghead Gas (Bcf)
|
|||||||||||||
|
|
United States
|
|
Israel
(1)
|
|
Equatorial Guinea
|
|
Other Int'l
(2)
|
|
Total
|
|||||
Proved Reserves as of:
|
|
|
|
|
|
|
|
|
|
|
|||||
December 31, 2013
|
|
2,656
|
|
|
2,479
|
|
|
691
|
|
|
2
|
|
|
5,828
|
|
Revisions of Previous Estimates
(3)
|
|
58
|
|
|
21
|
|
|
11
|
|
|
—
|
|
|
90
|
|
Extensions, Discoveries and Other Additions
(4)
|
|
433
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
433
|
|
Purchase of Minerals in Place
(5)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Sale of Minerals in Place
(6)
|
|
(154
|
)
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
(156
|
)
|
Production
|
|
(189
|
)
|
|
(84
|
)
|
|
(89
|
)
|
|
—
|
|
|
(362
|
)
|
December 31, 2014
|
|
2,804
|
|
|
2,416
|
|
|
613
|
|
|
—
|
|
|
5,833
|
|
Revisions of Previous Estimates
(3)
|
|
(705
|
)
|
|
(20
|
)
|
|
4
|
|
|
—
|
|
|
(721
|
)
|
Extensions, Discoveries and Other Additions
(4)
|
|
257
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
257
|
|
Purchase of Minerals in Place
(5)
|
|
629
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
629
|
|
Sale of Minerals in Place
(6)
|
|
(16
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(16
|
)
|
Production
|
|
(258
|
)
|
|
(92
|
)
|
|
(83
|
)
|
|
—
|
|
|
(433
|
)
|
December 31, 2015
|
|
2,711
|
|
|
2,304
|
|
|
534
|
|
|
—
|
|
|
5,549
|
|
Revisions of Previous Estimates
(3)
|
|
181
|
|
|
(3
|
)
|
|
38
|
|
|
—
|
|
|
216
|
|
Extensions, Discoveries and Other Additions
(4)
|
|
492
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
492
|
|
Purchase of Minerals in Place
(5)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Sale of Minerals in Place
(6)
|
|
(224
|
)
|
|
(214
|
)
|
|
—
|
|
|
—
|
|
|
(438
|
)
|
Production
|
|
(322
|
)
|
|
(103
|
)
|
|
(86
|
)
|
|
—
|
|
|
(511
|
)
|
December 31, 2016
|
|
2,838
|
|
|
1,984
|
|
|
486
|
|
|
—
|
|
|
5,308
|
|
Proved Developed Reserves as of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2013
|
|
1,212
|
|
|
2,046
|
|
|
457
|
|
|
2
|
|
|
3,717
|
|
December 31, 2014
|
|
1,459
|
|
|
1,973
|
|
|
377
|
|
|
—
|
|
|
3,809
|
|
December 31, 2015
|
|
1,813
|
|
|
1,879
|
|
|
247
|
|
|
—
|
|
|
3,939
|
|
December 31, 2016
|
|
1,817
|
|
|
1,600
|
|
|
486
|
|
|
—
|
|
|
3,903
|
|
Proved Undeveloped Reserves as of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2013
|
|
1,444
|
|
|
433
|
|
|
234
|
|
|
—
|
|
|
2,111
|
|
December 31, 2014
|
|
1,345
|
|
|
443
|
|
|
236
|
|
|
—
|
|
|
2,024
|
|
December 31, 2015
|
|
898
|
|
|
425
|
|
|
287
|
|
|
—
|
|
|
1,610
|
|
December 31, 2016
|
|
1,021
|
|
|
384
|
|
|
—
|
|
|
—
|
|
|
1,405
|
|
(1)
|
In accordance with the terms of the Israel Natural Gas Framework, we are required to reduce our ownership in the Tamar field to 25% by year-end 2021.
During 2016, we reduced our ownership to 32.5% through a sale
.
|
(2)
|
Other International includes China.
|
(3)
|
The 2014 US revisions were primarily associated with a positive performance revision to our Marcellus Shale program offset by a negative revision to our DJ Basin program due to a revised drilling program in response to the current commodity price environment. Equatorial Guinea revisions are associated with positive performance revisions to the Alba field. Israel revisions are primarily associated with positive performance revisions to the Tamar field.
|
Noble Energy, Inc.
|
|
|
Supplemental Oil and Gas Information
|
|
|
|
(Unaudited)
|
|
(4)
|
The 2014 increase in US reserves included an increase of 110 Bcf in the DJ Basin and 309 Bcf from Marcellus Shale development as well as 14 Bcf in the deepwater Gulf of Mexico.
|
(5)
|
The 2015 increase is attributable to reserves acquired in the Rosetta Merger.
|
(6)
|
In 2014, we sold onshore US and China assets.
|
Noble Energy, Inc.
|
|
|
Supplemental Oil and Gas Information
|
|
|
|
(Unaudited)
|
|
|
|
NGLs (MMBbls)
|
|||||||
|
|
United
States
|
|
Equatorial
Guinea
|
|
Total
|
|||
Proved Reserves as of:
|
|
|
|
|
|
|
|||
December 31, 2013
|
|
95
|
|
|
18
|
|
|
113
|
|
Revisions of Previous Estimates
|
|
7
|
|
|
—
|
|
|
7
|
|
Extensions, Discoveries and Other Additions
(2)
|
|
18
|
|
|
—
|
|
|
18
|
|
Purchase of Minerals in Place
|
|
—
|
|
|
—
|
|
|
—
|
|
Sale of Minerals in Place
|
|
—
|
|
|
—
|
|
|
—
|
|
Production
(3)
|
|
(7
|
)
|
|
(3
|
)
|
|
(10
|
)
|
December 31, 2014
|
|
113
|
|
|
15
|
|
|
128
|
|
Revisions of Previous Estimates
|
|
(37
|
)
|
|
—
|
|
|
(37
|
)
|
Extensions, Discoveries and Other Additions
(2)
|
|
15
|
|
|
—
|
|
|
15
|
|
Purchase of Minerals in Place
|
|
100
|
|
|
—
|
|
|
100
|
|
Sale of Minerals in Place
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
Production
(3)
|
|
(14
|
)
|
|
(2
|
)
|
|
(16
|
)
|
December 31, 2015
|
|
176
|
|
|
13
|
|
|
189
|
|
Revisions of Previous Estimates
(1)
|
|
16
|
|
|
1
|
|
|
17
|
|
Extensions, Discoveries and Other Additions
(2)
|
|
31
|
|
|
—
|
|
|
31
|
|
Purchase of Minerals in Place
(4)
|
|
4
|
|
|
—
|
|
|
4
|
|
Sale of Minerals in Place
|
|
—
|
|
|
—
|
|
|
—
|
|
Production
(3)
|
|
(20
|
)
|
|
(2
|
)
|
|
(22
|
)
|
December 31, 2016
|
|
207
|
|
|
12
|
|
|
219
|
|
Proved Developed Reserves as of
|
|
|
|
|
|
|
|
|
|
December 31, 2013
|
|
44
|
|
|
11
|
|
|
55
|
|
December 31, 2014
|
|
64
|
|
|
8
|
|
|
72
|
|
December 31, 2015
|
|
101
|
|
|
5
|
|
|
106
|
|
December 31, 2016
|
|
113
|
|
|
12
|
|
|
125
|
|
Proved Undeveloped Reserves as of
|
|
|
|
|
|
|
|
|
|
December 31, 2013
|
|
51
|
|
|
7
|
|
|
58
|
|
December 31, 2014
|
|
49
|
|
|
7
|
|
|
56
|
|
December 31, 2015
|
|
75
|
|
|
8
|
|
|
83
|
|
December 31, 2016
|
|
94
|
|
|
—
|
|
|
94
|
|
(1)
|
The 2015 US revisions were primarily associated with negative price revisions of 44 MMBbls related to our onshore programs due to a decline in the 12-month average price, offset by a positive revision from our Marcellus Shale program due to positive well performance.
|
(2)
|
The 2014 additions in US reserves included an increase of 8 MMBbls in the DJ Basin and 8 MMBbls from Marcellus Shale development.
|
Noble Energy, Inc.
|
|
|
Supplemental Oil and Gas Information
|
|
|
|
(Unaudited)
|
|
|
|
United
States
|
|
Israel
|
|
Equatorial
Guinea
|
|
Other
Int'l
(1)
|
|
Total
|
||||||||||
(millions)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Revenues
|
|
$
|
2,416
|
|
|
$
|
540
|
|
|
$
|
433
|
|
|
$
|
—
|
|
|
$
|
3,389
|
|
Production Costs
(2)
|
|
992
|
|
|
49
|
|
|
118
|
|
|
3
|
|
|
1,162
|
|
|||||
Exploration Expense
(3)
|
|
245
|
|
|
26
|
|
|
469
|
|
|
185
|
|
|
925
|
|
|||||
DD&A
|
|
2,122
|
|
|
81
|
|
|
205
|
|
|
46
|
|
|
2,454
|
|
|||||
Asset Impairments
(4)
|
|
—
|
|
|
88
|
|
|
—
|
|
|
4
|
|
|
92
|
|
|||||
(Loss) Income before Income Taxes
|
|
(943
|
)
|
|
296
|
|
|
(359
|
)
|
|
(238
|
)
|
|
(1,244
|
)
|
|||||
Income Tax Expense (Benefit)
(5)
|
|
(330
|
)
|
|
74
|
|
|
(90
|
)
|
|
—
|
|
|
(346
|
)
|
|||||
Results of Operations
(6)
|
|
$
|
(613
|
)
|
|
$
|
222
|
|
|
$
|
(269
|
)
|
|
$
|
(238
|
)
|
|
$
|
(898
|
)
|
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Revenues
|
|
$
|
2,011
|
|
|
$
|
497
|
|
|
$
|
580
|
|
|
$
|
5
|
|
|
$
|
3,093
|
|
Production Costs
(2)
|
|
817
|
|
|
67
|
|
|
145
|
|
|
15
|
|
|
1,044
|
|
|||||
Exploration Expense
|
|
202
|
|
|
6
|
|
|
1
|
|
|
279
|
|
|
488
|
|
|||||
DD&A
|
|
1,692
|
|
|
70
|
|
|
326
|
|
|
43
|
|
|
2,131
|
|
|||||
Asset Impairments
(4)
|
|
158
|
|
|
36
|
|
|
339
|
|
|
—
|
|
|
533
|
|
|||||
(Loss) Income before Income Taxes
|
|
(858
|
)
|
|
318
|
|
|
(231
|
)
|
|
(332
|
)
|
|
(1,103
|
)
|
|||||
Income Tax Expense (Benefit)
(5)
|
|
(300
|
)
|
|
84
|
|
|
(58
|
)
|
|
(5
|
)
|
|
(279
|
)
|
|||||
Results of Operations
(6)
|
|
$
|
(558
|
)
|
|
$
|
234
|
|
|
$
|
(173
|
)
|
|
$
|
(327
|
)
|
|
$
|
(824
|
)
|
Year Ended December 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Revenues
|
|
$
|
3,189
|
|
|
$
|
479
|
|
|
$
|
1,177
|
|
|
$
|
100
|
|
|
$
|
4,945
|
|
Production Costs
(2)
|
|
686
|
|
|
54
|
|
|
147
|
|
|
69
|
|
|
956
|
|
|||||
Exploration Expense
|
|
268
|
|
|
4
|
|
|
18
|
|
|
208
|
|
|
498
|
|
|||||
DD&A
|
|
1,318
|
|
|
63
|
|
|
299
|
|
|
79
|
|
|
1,759
|
|
|||||
Asset Impairments
(4)
|
|
392
|
|
|
14
|
|
|
—
|
|
|
94
|
|
|
500
|
|
|||||
Income (Loss) before Income Taxes
|
|
525
|
|
|
344
|
|
|
713
|
|
|
(350
|
)
|
|
1,232
|
|
|||||
Income Tax Expense
(5)
|
|
184
|
|
|
94
|
|
|
178
|
|
|
18
|
|
|
474
|
|
|||||
Results of Operations
(6)
|
|
$
|
341
|
|
|
$
|
250
|
|
|
$
|
535
|
|
|
$
|
(368
|
)
|
|
$
|
758
|
|
(1)
|
Other International includes the North Sea (through 2014), China (through June 30, 2014) and new ventures.
|
(2)
|
Production costs consist of lease operating expense, production and ad valorem taxes, transportation and gathering expense, and general and administrative expense supporting oil and gas operations.
|
(3)
|
Equatorial Guinea exploration expense includes $468 million for the write off of costs associated with certain discoveries. See
Note
6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs
.
|
(4)
|
Asset impairments relate to certain Leviathan development concepts costs. See
Note
5. Asset Impairments
.
|
(5)
|
Income tax expense is based upon respective corporate statutory tax rates. During 2016, 2015, and 2014, we incurred exploration expense in currently non-commercial other international locations; therefore, no tax benefit was included in income tax expense associated with Other International as we could not conclude it was more likely than not that some portion or all of the deferred tax assets would be realized.
|
(6)
|
Results of operations exclude the mark-to-market gain or loss on commodity derivative instruments, corporate overhead and interest costs. See
Note
8. Derivative Instruments and Hedging Activities
.
|
Noble Energy, Inc.
|
|
|
Supplemental Oil and Gas Information
|
|
|
|
(Unaudited)
|
|
|
|
United
States
|
|
Israel
|
|
Equatorial
Guinea
|
|
Other
Int'l
(2)
|
|
Total
|
||||||||||
(millions)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Property Acquisition Costs
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Proved
(3)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Unproved
(3)
|
|
234
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
234
|
|
|||||
Exploration Costs
(4)
|
|
264
|
|
|
26
|
|
|
25
|
|
|
44
|
|
|
359
|
|
|||||
Development Costs
(5)
|
|
939
|
|
|
109
|
|
|
31
|
|
|
—
|
|
|
1,079
|
|
|||||
Total Consolidated Operations
|
|
$
|
1,437
|
|
|
$
|
135
|
|
|
$
|
56
|
|
|
$
|
44
|
|
|
$
|
1,672
|
|
Company's Share of CONE Gathering Development Costs
|
|
$
|
8
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
8
|
|
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Property Acquisition Costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Proved
(3)
|
|
$
|
1,613
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,613
|
|
Unproved
(3)
|
|
1,478
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
1,480
|
|
|||||
Exploration Costs
(4)
|
|
206
|
|
|
22
|
|
|
22
|
|
|
234
|
|
|
484
|
|
|||||
Development Costs
(5)
|
|
2,455
|
|
|
104
|
|
|
75
|
|
|
10
|
|
|
2,644
|
|
|||||
Total Consolidated Operations
|
|
$
|
5,752
|
|
|
$
|
126
|
|
|
$
|
97
|
|
|
$
|
246
|
|
|
$
|
6,221
|
|
Company's Share of CONE Gathering Development Costs
|
|
$
|
104
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
104
|
|
Year Ended December 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Property Acquisition Costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Unproved
(3)
|
|
$
|
246
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3
|
|
|
$
|
249
|
|
Exploration Costs
(4)
|
|
485
|
|
|
60
|
|
|
61
|
|
|
64
|
|
|
670
|
|
|||||
Development Costs
(5)
|
|
3,685
|
|
|
144
|
|
|
211
|
|
|
78
|
|
|
4,118
|
|
|||||
Total Consolidated Operations
|
|
$
|
4,416
|
|
|
$
|
204
|
|
|
$
|
272
|
|
|
$
|
145
|
|
|
$
|
5,037
|
|
Company's Share of CONE Gathering Development Costs
|
|
$
|
71
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
71
|
|
(1)
|
Costs incurred include capitalized and expensed items.
|
(2)
|
Other International includes the North Sea, China (through June 30, 2014) and new ventures. See
Note
3. Acquisitions, Divestitures and Merger
.
|
(3)
|
2016
unproved property acquisition costs relate to the termination of the Marcellus Shale joint development. See
Note
3. Acquisitions, Divestitures and Merger
.
|
(4)
|
2016
exploration costs include drilling and completion of $1 million in the Marcellus Shale and $44 million in the deepwater Gulf of Mexico.
|
Noble Energy, Inc.
|
|
|
Supplemental Oil and Gas Information
|
|
|
|
(Unaudited)
|
|
(5)
|
Worldwide development costs include amounts spent to develop PUDs of approximately
$656 million
in 2016,
$1.5 billion
in
2015
, and
$2.0 billion
in
2014
.
|
|
|
December 31,
|
||||||
|
|
2016
|
|
2015
|
||||
(millions)
|
|
|
|
|
||||
Unproved Oil and Gas Properties
(1)
|
|
$
|
2,197
|
|
|
$
|
2,151
|
|
Proved Oil and Gas Properties
(2)
|
|
28,158
|
|
|
29,069
|
|
||
Total Oil and Gas Properties
|
|
30,355
|
|
|
31,220
|
|
||
Accumulated DD&A
|
|
(12,325
|
)
|
|
(10,439
|
)
|
||
Net Capitalized Costs
|
|
$
|
18,030
|
|
|
$
|
20,781
|
|
Company's Share of CONE Gathering Net Capitalized Costs
|
|
$
|
440
|
|
|
$
|
433
|
|
(1)
|
Unproved oil and gas property cost at December 31, 2016 include previous acquisition costs of $1.2 billion related to the Eagle Ford Shale and Permian Basin properties and $758 million related to the Marcellus Shale.
|
(2)
|
Proved oil and gas properties at December 31, 2016 include asset retirement costs of $897 million and exclude assets held for sale of $18 million.
|
Noble Energy, Inc.
|
|
|
Supplemental Oil and Gas Information
|
|
|
|
(Unaudited)
|
|
|
|
United
States
|
|
Israel
(1)
|
|
Equatorial
Guinea
|
|
Other
Int'l
(2)
|
|
Total
|
||||||||||
(millions)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Future Cash Inflows
(3)
|
|
$
|
19,924
|
|
|
$
|
10,159
|
|
|
$
|
1,851
|
|
|
$
|
—
|
|
|
$
|
31,934
|
|
Future Production Costs
(4)
|
|
(8,756
|
)
|
|
(764
|
)
|
|
(1,001
|
)
|
|
—
|
|
|
(10,521
|
)
|
|||||
Future Development Costs
(5)
|
|
(4,813
|
)
|
|
(725
|
)
|
|
(83
|
)
|
|
(100
|
)
|
|
(5,721
|
)
|
|||||
Future Income Tax Expense
(6)
|
|
(941
|
)
|
|
(4,228
|
)
|
|
(141
|
)
|
|
—
|
|
|
(5,310
|
)
|
|||||
Future Net Cash Flows
|
|
5,414
|
|
|
4,442
|
|
|
626
|
|
|
(100
|
)
|
|
10,382
|
|
|||||
10% Annual Discount for Estimated Timing of Cash Flows
|
|
(2,308
|
)
|
|
(2,329
|
)
|
|
(84
|
)
|
|
25
|
|
|
(4,696
|
)
|
|||||
Standardized Measure of Discounted Future Net Cash Flows
|
|
$
|
3,106
|
|
|
$
|
2,113
|
|
|
$
|
542
|
|
|
$
|
(75
|
)
|
|
$
|
5,686
|
|
December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Future Cash Inflows
(3)
|
|
$
|
19,099
|
|
|
$
|
11,835
|
|
|
$
|
2,965
|
|
|
$
|
—
|
|
|
$
|
33,899
|
|
Future Production Costs
(4)
|
|
(8,728
|
)
|
|
(1,128
|
)
|
|
(1,351
|
)
|
|
—
|
|
|
(11,207
|
)
|
|||||
Future Development Costs
(5)
|
|
(4,092
|
)
|
|
(682
|
)
|
|
(101
|
)
|
|
(100
|
)
|
|
(4,975
|
)
|
|||||
Future Income Tax Expense
|
|
(837
|
)
|
|
(5,281
|
)
|
|
(189
|
)
|
|
—
|
|
|
(6,307
|
)
|
|||||
Future Net Cash Flows
|
|
5,442
|
|
|
4,744
|
|
|
1,324
|
|
|
(100
|
)
|
|
11,410
|
|
|||||
10% Annual Discount for Estimated Timing of Cash Flows
|
|
(2,100
|
)
|
|
(2,452
|
)
|
|
(262
|
)
|
|
32
|
|
|
(4,782
|
)
|
|||||
Standardized Measure of Discounted Future Net Cash Flows
|
|
$
|
3,342
|
|
|
$
|
2,292
|
|
|
$
|
1,062
|
|
|
$
|
(68
|
)
|
|
$
|
6,628
|
|
December 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Future Cash Inflows
(3)
|
|
$
|
36,352
|
|
|
$
|
15,110
|
|
|
$
|
7,402
|
|
|
$
|
11
|
|
|
$
|
58,875
|
|
Future Production Costs
(4)
|
|
(10,337
|
)
|
|
(1,829
|
)
|
|
(2,294
|
)
|
|
(8
|
)
|
|
(14,468
|
)
|
|||||
Future Development Costs
(5)
|
|
(7,272
|
)
|
|
(724
|
)
|
|
(186
|
)
|
|
(100
|
)
|
|
(8,282
|
)
|
|||||
Future Income Tax Expense
|
|
(5,448
|
)
|
|
(2,365
|
)
|
|
(1,075
|
)
|
|
—
|
|
|
(8,888
|
)
|
|||||
Future Net Cash Flows
|
|
13,295
|
|
|
10,192
|
|
|
3,847
|
|
|
(97
|
)
|
|
27,237
|
|
|||||
10% Annual Discount for Estimated Timing of Cash Flows
|
|
(6,040
|
)
|
|
(6,240
|
)
|
|
(995
|
)
|
|
17
|
|
|
(13,258
|
)
|
|||||
Standardized Measure of Discounted Future Net Cash Flows
|
|
$
|
7,255
|
|
|
$
|
3,952
|
|
|
$
|
2,852
|
|
|
$
|
(80
|
)
|
|
$
|
13,979
|
|
(1)
|
In accordance with the Israel Natural Gas Framework, we are required to reduce our ownership in the Tamar field to 25% by year-end 2021.
During 2016, we reduced our ownership to 32.5% through a sale. Therefore, 2016 amounts reflect a 32.5% working interest, while 2015 and 2014 amounts reflect a 36% working interest.
See
Note 3. Acquisitions, Divestitures and Merger
.
|
(2)
|
Other International represents North Sea abandonment costs.
|
(3)
|
The standardized measure of discounted future net cash flows does not include cash flows relating to anticipated future methanol sales.
|
(4)
|
Production costs include lease operating expense, production and ad valorem taxes, transportation expense and general and administrative expense supporting crude oil and natural gas operations.
|
(5)
|
Future development costs include future abandonment costs for each location. See
Note
9. Asset Retirement Obligations
.
|
(6)
|
Future income tax expense includes the effect of statutory tax rates and the impact of tax deductions, tax credits and allowances relating to our proved reserves. For 2016 and 2015, future income tax expense for Israel also includes the effect of estimated future profit levy taxes and changes to corporate income tax rates.
|
Noble Energy, Inc.
|
|
|
Supplemental Oil and Gas Information
|
|
|
|
(Unaudited)
|
|
|
|
United
States
|
|
Israel
|
|
Equatorial
Guinea
|
|
Other
Int'l
|
|
Total
|
||||||||||
December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Average Crude Oil and Condensate Price per Bbl
|
|
$
|
37.36
|
|
|
$
|
36.05
|
|
|
$
|
42.45
|
|
|
$
|
—
|
|
|
$
|
37.87
|
|
Average Natural Gas Price per Mcf
|
|
2.07
|
|
|
5.07
|
|
|
0.27
|
|
|
—
|
|
|
3.02
|
|
|||||
Average NGL Price per Bbl
|
|
14.30
|
|
|
—
|
|
|
26.12
|
|
|
—
|
|
|
14.94
|
|
|||||
December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Average Crude Oil and Condensate Price per Bbl
|
|
$
|
42.03
|
|
|
$
|
48.23
|
|
|
$
|
51.03
|
|
|
$
|
—
|
|
|
$
|
43.50
|
|
Average Natural Gas Price per Mcf
|
|
2.16
|
|
|
5.08
|
|
|
0.27
|
|
|
—
|
|
|
3.18
|
|
|||||
Average NGL Price per Bbl
|
|
14.15
|
|
|
—
|
|
|
29.92
|
|
|
—
|
|
|
15.23
|
|
|||||
December 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Average Crude Oil and Condensate Price per Bbl
|
|
$
|
86.88
|
|
|
$
|
90.88
|
|
|
$
|
97.88
|
|
|
$
|
102.28
|
|
|
$
|
89.27
|
|
Average Natural Gas Price per Mcf
|
|
3.99
|
|
|
6.14
|
|
|
0.27
|
|
|
—
|
|
|
4.49
|
|
|||||
Average NGL Price per Bbl
|
|
41.58
|
|
|
—
|
|
|
59.96
|
|
|
—
|
|
|
43.85
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
(millions)
|
|
|
|
|
|
|
||||||
Imbalance Receivables
(1)
|
|
$
|
—
|
|
|
$
|
34
|
|
|
$
|
34
|
|
Imbalance Liabilities
(1)
|
|
—
|
|
|
34
|
|
|
33
|
|
(1)
|
Imbalance receivables and liabilities for 2015 and 2014 related primarily to onshore US assets which were sold in 2016.
|
Noble Energy, Inc.
|
|
|
Supplemental Oil and Gas Information
|
|
|
|
(Unaudited)
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2016
|
|
2015
|
|
2014
|
||||||
(millions)
|
|
|
|
|
|
|
||||||
Standardized Measure of Discounted Future Net Cash Flows, Beginning of Year
|
|
$
|
6,628
|
|
|
$
|
13,979
|
|
|
$
|
14,090
|
|
Changes in Standardized Measure of Discounted Future Net Cash Flows
|
|
|
|
|
|
|
|
|||||
Sales of Oil and Gas Produced, Net of Production Costs
|
|
(2,230
|
)
|
|
(2,026
|
)
|
|
(4,027
|
)
|
|||
Net Changes in Prices and Production Costs
(1)
|
|
(593
|
)
|
|
(12,603
|
)
|
|
(1,090
|
)
|
|||
Extensions, Discoveries and Improved Recovery, Less Related Costs
|
|
463
|
|
|
442
|
|
|
1,457
|
|
|||
Changes in Estimated Future Development Costs
|
|
(373
|
)
|
|
1,135
|
|
|
(2,179
|
)
|
|||
Development Costs Incurred During the Period
|
|
1,090
|
|
|
2,639
|
|
|
4,042
|
|
|||
Revisions of Previous Quantity Estimates
|
|
364
|
|
|
(1,051
|
)
|
|
162
|
|
|||
Purchases of Minerals in Place
(2)
|
|
161
|
|
|
2,747
|
|
|
—
|
|
|||
Sales of Minerals in Place
|
|
(951
|
)
|
|
(46
|
)
|
|
(268
|
)
|
|||
Accretion of Discount
|
|
919
|
|
|
1,789
|
|
|
1,919
|
|
|||
Net Change in Income Taxes
(3)
|
|
414
|
|
|
2,075
|
|
|
671
|
|
|||
Change in Timing of Estimated Future Production and Other
(4)
|
|
(206
|
)
|
|
(2,452
|
)
|
|
(798
|
)
|
|||
Aggregate Change in Standardized Measure of Discounted Future Net Cash Flows
|
|
$
|
(942
|
)
|
|
$
|
(7,351
|
)
|
|
$
|
(111
|
)
|
Standardized Measure of Discounted Future Net Cash Flows, End of Year
|
|
$
|
5,686
|
|
|
$
|
6,628
|
|
|
$
|
13,979
|
|
(1)
|
The decrease in 2015 is driven primarily by lower 12-month average commodity prices.
|
(2)
|
Purchase of minerals in 2015 relates to reserves acquired in the Rosetta Merger.
|
(3)
|
The increase in 2015 reflects lower estimated future income tax expense primarily driven by lower 12-month average commodity prices. For 2015, future income tax expense for Israel includes the effect of estimated future profit levy taxes which partially offset the increase in future net cash flows.
|
(4)
|
The decrease in 2015 reflects revisions in our estimated timing of production and development activity.
|
|
|
Quarter Ended
|
||||||||||||||||||
|
|
March 31,
|
|
June 30,
|
|
Sep 30,
|
|
Dec 31,
|
|
Total
|
||||||||||
(millions except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
2016
(1) (3)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues
|
|
$
|
724
|
|
|
$
|
847
|
|
|
$
|
910
|
|
|
$
|
1,010
|
|
|
$
|
3,491
|
|
Income (Loss) Before Income Taxes
|
|
(453
|
)
|
|
(498
|
)
|
|
(280
|
)
|
|
(541
|
)
|
|
(1,772
|
)
|
|||||
Net Income (Loss)
|
|
(287
|
)
|
|
(315
|
)
|
|
(143
|
)
|
|
(240
|
)
|
|
(985
|
)
|
|||||
Less: Net Income Attributable to Noncontrolling Interests
|
|
—
|
|
|
—
|
|
|
1
|
|
|
12
|
|
|
13
|
|
|||||
Net Loss Attributable to Noble Energy
|
|
(287
|
)
|
|
(315
|
)
|
|
(144
|
)
|
|
(252
|
)
|
|
(998
|
)
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Loss Per Share, Basic
|
|
(0.67
|
)
|
|
(0.73
|
)
|
|
(0.33
|
)
|
|
(0.59
|
)
|
|
(2.32
|
)
|
|||||
Loss Per Share, Diluted
|
|
(0.67
|
)
|
|
(0.73
|
)
|
|
(0.33
|
)
|
|
(0.59
|
)
|
|
(2.32
|
)
|
|||||
2015
(2) (3)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues
|
|
$
|
767
|
|
|
$
|
738
|
|
|
$
|
819
|
|
|
$
|
859
|
|
|
$
|
3,183
|
|
Loss Before Income Taxes
|
|
(42
|
)
|
|
(293
|
)
|
|
(259
|
)
|
|
(1,625
|
)
|
|
(2,219
|
)
|
|||||
Net Loss Attributable to Noble Energy
|
|
(22
|
)
|
|
(109
|
)
|
|
(283
|
)
|
|
(2,027
|
)
|
|
(2,441
|
)
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Loss Per Share, Basic
|
|
(0.06
|
)
|
|
(0.28
|
)
|
|
(0.67
|
)
|
|
(4.73
|
)
|
|
(6.07
|
)
|
|||||
Loss Per Share, Diluted
|
|
(0.06
|
)
|
|
(0.28
|
)
|
|
(0.67
|
)
|
|
(4.73
|
)
|
|
(6.07
|
)
|
•
|
$44 million gain on commodity derivative instruments, including non-cash portion of loss on commodity derivative instruments of $134 million (See
Note
8. Derivative Instruments and Hedging Activities
); and
|
•
|
$80 million gain on extinguishment of debt.
|
•
|
$151 million loss on commodity derivative instruments, including non-cash portion of loss on commodity derivative instruments of $295 million (See
Note
8. Derivative Instruments and Hedging Activities
); and
|
•
|
$25 million purchase price allocation adjustment related to Rosetta Merger (See
Note
3. Merger, Acquisitions and Divestitures
).
|
•
|
$81 million undeveloped leasehold impairment expense (See
Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs
);
|
•
|
$55 million gain on commodity derivative instruments, including non-cash portion of loss on commodity derivative instruments of $77 million (See
Note
8. Derivative Instruments and Hedging Activities
).
|
•
|
$579 million dry hole costs included in exploration expense (See
Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs
);
|
•
|
$87 million loss on commodity derivative instruments, including non-cash portion of loss on commodity derivative instruments of $201 million (See
Note
8. Derivative Instruments and Hedging Activities
); and
|
•
|
$92 million property impairment charges (See
Note
5. Asset Impairments
)
|
•
|
$150 million gain on commodity derivative instruments, including non-cash portion of loss on commodity derivative instruments of $60 million (See
Note
8. Derivative Instruments and Hedging Activities
); and
|
•
|
$27 million property impairment charges (See
Note
5. Asset Impairments
).
|
•
|
$87 million loss on commodity derivative instruments, including non-cash portion of loss on commodity derivative instruments of $274 million (See
Note
8. Derivative Instruments and Hedging Activities
); and
|
•
|
$15 million property impairment charges (See
Note
5. Asset Impairments
).
|
•
|
$267 million gain on commodity derivative instruments, including non-cash portion of loss on commodity derivative instruments of $17 million (See
Note
8. Derivative Instruments and Hedging Activities
); and
|
•
|
$71 million of other operating expenses associated with the Rosetta Merger.
|
•
|
$171 million gain on commodity derivative instruments, including non-cash portion of loss on commodity derivative instruments of $157 million (See
Note
8. Derivative Instruments and Hedging Activities
);
|
•
|
$779 million goodwill impairment charge (See
Note
1. Summary of Significant Accounting Policies
); and
|
•
|
$490 million property impairment charges (See
Note
5. Asset Impairments
).
|
(3)
|
T
he sum of the individual quarterly earnings (loss) may not agree with year-to-date earnings as each quarterly computation is based on the earnings for the individual quarter as reported with rounding applied.
|
(3)
|
Exhibits: The exhibits required to be filed by this Item 15 are set forth in the Index to Exhibits accompanying this report.
|
|
|
NOBLE ENERGY, INC.
|
|
|
(Registrant)
|
|
|
|
Date:
|
February 14, 2017
|
By: /s/ David L. Stover
|
|
|
David L. Stover,
|
|
|
Chairman of the Board, President and Chief Executive Officer
|
|
|
|
Date:
|
February 14, 2017
|
By: /s/ Kenneth M. Fisher
|
|
|
Kenneth M. Fisher,
|
|
|
Executive Vice President, Chief Financial Officer
|
|
|
|
Date:
|
February 14, 2017
|
By: /s/ Dustin A. Hatley
|
|
|
Dustin A. Hatley,
|
|
|
Vice President, Chief Accounting Officer and Controller
|
Signature
|
|
Capacity in which signed
|
|
Date
|
|
|
|
|
|
/s/ David L. Stover
|
|
Chairman of the Board, President and Chief Executive Officer
|
|
February 14, 2017
|
David L. Stover
|
|
(Principal Executive Officer)
|
|
|
|
|
|
|
|
/s/ Kenneth M. Fisher
|
|
Executive Vice President, Chief Financial Officer
|
|
February 14, 2017
|
Kenneth M. Fisher
|
|
(Principal Financial Officer)
|
|
|
|
|
|
|
|
/s/ Dustin A. Hatley
|
|
Vice President, Chief Accounting Officer and Controller
|
|
February 14, 2017
|
Dustin A. Hatley
|
|
(Principal Accounting Officer)
|
|
|
|
|
|
|
|
/s/ Jeffrey L. Berenson
|
|
Director
|
|
February 14, 2017
|
Jeffrey L. Berenson
|
|
|
|
|
|
|
|
|
|
/s/ Michael A. Cawley
|
|
Director
|
|
February 14, 2017
|
Michael A. Cawley
|
|
|
|
|
|
|
|
|
|
/s/ Edward F. Cox
|
|
Director
|
|
February 14, 2017
|
Edward F. Cox
|
|
|
|
|
|
|
|
|
|
/s/ James E. Craddock
|
|
Director
|
|
February 14, 2017
|
James E. Craddock
|
|
|
|
|
|
|
|
|
|
/s/ Thomas J. Edelman
|
|
Director
|
|
February 14, 2017
|
Thomas J. Edelman
|
|
|
|
|
|
|
|
|
|
/s/ Eric P. Grubman
|
|
Director
|
|
February 14, 2017
|
Eric P. Grubman
|
|
|
|
|
|
|
|
|
|
/s/ Kirby L. Hedrick
|
|
Director
|
|
February 14, 2017
|
Kirby L. Hedrick
|
|
|
|
|
|
|
|
|
|
/s/ Scott D. Urban
|
|
Director
|
|
February 14, 2017
|
Scott D. Urban
|
|
|
|
|
|
|
|
|
|
/s/ William T. Van Kleef
|
|
Director
|
|
February 14, 2017
|
William T. Van Kleef
|
|
|
|
|
|
|
|
|
|
/s/ Molly K. Williamson
|
|
Director
|
|
February 14, 2017
|
Molly K. Williamson
|
|
|
|
|
Exhibit Number
|
Exhibit **
|
|
2.1
|
—
|
Agreement and Plan of Merger, dated as of January 13, 2017, by and among Noble Energy, Inc., Wild West Merger Sub Inc., NBL Permian LLC, and Clayton Williams Energy, Inc. (filed as Exhibit 2.1 to the Registrant’s Current Report on Form 8-K (Date of Report: January 13, 2017) filed on January 17, 2017 and incorporated herein by reference).
|
2.2
|
—
|
Agreement and Plan of Merger, dated as of May 10, 2015, by and among Noble Energy, Inc., Bluebonnet Merger Sub Inc. and Rosetta Resources Inc. (filed as Exhibit 2.1 of the Registrant’s Current Report on Form 8-K (Date of Report: May 10, 2015) filed on May 11, 2015 and incorporated herein by reference).
|
2.3
|
—
|
Exchange Agreement, executed October 29, 2016, by and between CNX Gas Company LLC and Noble Energy, Inc. (filed as Exhibit 2.3 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2016 and incorporated herein by reference).
|
3.1
|
—
|
Restated Certificate of Incorporation of Noble Energy Inc., (filed as Exhibit 3.3 to the Registrant’s Current Report on Form 8-K (Date of Report: July 26, 2016) filed on July 28, 2016 and incorporated herein by reference).
|
3.2
|
—
|
By-Laws of Noble Energy, Inc. (as amended through July 27, 2016) (filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K (Date of Report: July 27, 2016) filed on July 29, 2016 and incorporated herein by reference).
|
3.3
|
—
|
Certificate of Elimination of the Series A Junior Participating Preferred Stock of Noble Energy, Inc. (filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K (Date of Report: July 26, 2016) filed on July 28, 2016 and incorporated herein by reference).
|
3.4
|
—
|
Certificate of Elimination of the Series B Mandatorily Convertible Preferred Stock of Noble Energy, Inc. (filed as Exhibit 3.2 to the Registrant’s Current Report on Form 8-K (Date of Report: July 26, 2016) filed on July 28, 2016 and incorporated herein by reference).
|
4.1
|
—
|
Indenture dated as of February 27, 2009 between Noble Energy, Inc. and Wells Fargo Bank, National Association, as Trustee, relating to senior debt securities of Noble Energy, Inc. (filed as Exhibit 4.1 to the Registrant’s Current Report on Form 8-K (Date of Report: February 24, 2009) filed February 27, 2009 and incorporated herein by reference).
|
4.2
|
—
|
First Supplemental Indenture dated as of February 27, 2009, to Indenture dated as of February 27, 2009 between Noble Energy, Inc. and Wells Fargo Bank, National Association, as Trustee, relating to the Registrant’s 8.25% Notes due 2019. (including the form of 2019 Notes) (filed as Exhibit 4.2 to the Registrant’s Current Report on Form 8-K (Date of Report: February 24, 2009) filed February 27, 2009 and incorporated herein by reference).
|
4.3
|
—
|
Second Supplemental Indenture dated as of February 18, 2011, to Indenture dated as of February 27, 2009 between Noble Energy, Inc. and Wells Fargo Bank, National Association, as Trustee, relating to the Registrant's 6.000% Notes due 2041 (including the form of 2041 Notes) (filed as Exhibit 4.1 to the Registrant’s Current Report on Form 8-K (Date of Report: February 15, 2011) filed February 22, 2011 and incorporated herein by reference).
|
4.4
|
—
|
Third Supplemental Indenture dated as of December 8, 2011, to Indenture dated as of February 27, 2009 between Noble Energy, Inc. and Wells Fargo Bank, National Association, as Trustee, relating to the Registrant's 4.15% Notes due 2021 (including the form of 2021 Notes) (filed as Exhibit 4.2 to the Registrant’s Current Report on Form 8-K (Date of Report: December 5, 2011) filed December 8, 2011 and incorporated herein by reference).
|
4.5
|
—
|
Fourth Supplemental Indenture dated as of November 8, 2013, to Indenture dated as of February 27, 2009 between Noble Energy, Inc. and Wells Fargo Bank, National Association, as Trustee, relating to the Registrant's 5.25% Notes due 2043 (including the form of 2043 Notes) (filed as Exhibit 4.1 to the Registrant’s Current Report on Form 8-K (Date of Report: November 5, 2013) filed November 8, 2013 and incorporated herein by reference).
|
4.6
|
—
|
Fifth Supplemental Indenture dated as of November 7, 2014, to Indenture dated as of February 27, 2009 between Noble Energy, Inc. and Wells Fargo Bank, National Association, as Trustee, relating the Registrant’s 3.900% Notes due 2024 and 5.050% Notes due 2044 (including the forms of 2024 Notes and 2044 Notes) (filed as Exhibit 4.1 to the Registrant’s Current Report on Form 8-K (Date of Report: November 4, 2014) filed November 7, 2014 and incorporated herein by reference).
|
4.7
|
—
|
Sixth Supplemental Indenture dated as of July 29, 2015, to Indenture dated as of February 27, 2009 between Noble Energy, Inc. and Wells Fargo Bank, National Association, as Trustee, relating the Registrant’s 5.625% Notes due 2021, 5.875% Senior Notes due 2022 and 5.875% Notes due 2024 (including the forms of 2021 Notes, 2022 Notes and 2024 Notes) (filed as Exhibit 4.2 to the Registrant’s Current Report on Form 8-K (Date of Report: July 29, 2015) filed July 31, 2015 and incorporated herein by reference).
|
4.8
|
—
|
Indenture dated as of October 14, 1993 between the Registrant and U.S. Trust Company of Texas, N.A., as Trustee, relating to the Registrant’s 7¼% Notes Due 2023 (including the form of 2023 Notes) (filed as Exhibit 4.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1993 and incorporated herein by reference).
|
4.9
|
—
|
Indenture dated as of April 1, 1997 between the Registrant and U.S. Trust Company of Texas, N.A., as Trustee, relating to senior debt securities of Noble Energy, Inc. (filed as Exhibit 4.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1997 and incorporated herein by reference).
|
4.1
|
—
|
First Indenture Supplement dated as of April 2, 1997, to Indenture dated as of April 1, 1997, between the Registrant and U.S. Trust Company of Texas, N.A., as Trustee, relating to the Registrant’s 8% Senior Notes Due 2027 (including the form of 2027 Notes) (filed as Exhibit 4.2 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1997 and incorporated herein by reference).
|
4.11
|
—
|
Second Indenture Supplement, dated as of August 1, 1997, to Indenture dated as of April 1, 1997, between the Registrant and U.S. Trust Company of Texas, N.A. as trustee, relating to the Registrant’s 7¼% Senior Debentures Due 2097 (including the form of 2097 Notes) (filed as Exhibit 4.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1997 and incorporated herein by reference).
|
10.1
|
—
|
Credit Agreement, dated October 14, 2011, among Noble Energy, Inc., JPMorgan Chase Bank, N.A., as administrative agent, Citibank N.A., as syndication agent, Bank of America, N.A., Mizuho Corporate Bank, LTD., and Morgan Stanley MUFG Loan Partners, LLC, as documentation agents, and certain other commercial lending institutions named therein (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Report: October 14, 2011) filed October 18, 2011 and incorporated herein by reference).
|
10.2
|
—
|
Commitment Increase Agreement (Existing Lenders) dated September 28, 2012, among Noble Energy, Inc., JPMorgan Chase Bank, N.A., as administrative agent, and certain other commercial lending institutions party thereto (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Report: September 28, 2012), filed October 2, 2012 and incorporated herein by reference).
|
10.3
|
—
|
Commitment Increase Agreement (New Lenders) dated September 28, 2012, among Noble Energy, Inc., JPMorgan Chase Bank, N.A., as administrative agent, and certain other commercial lending institutions party thereto (filed as Exhibit 10.2 to the Registrant’s Current Report on Form 8-K (Date of Report: September 28, 2012), filed October 2, 2012 and incorporated herein by reference).
|
10.4
|
—
|
First Amendment to Credit Agreement, dated October 3, 2013, by and among Noble Energy, Inc., NBL International Finance B.V., JPMorgan Chase Bank, N.A., as administrative agent, Citibank N.A., as syndication agent, and Bank of America, N.A., Bank of Tokyo-Mitsubishi UFJ, Ltd., Mizuho Bank, Ltd. and DNB Bank ASA, New York Branch as documentation agents, and the other commercial lending institutions party thereto (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Report: October 3, 2013) filed October 9, 2013 and incorporated herein by reference).
|
10.5
|
—
|
Second Amendment to Credit Agreement, dated August 27, 2015, by and among Noble Energy, Inc., JPMorgan Chase Bank, N.A., as administrative agent, Citibank N.A., as syndication agent, and Bank of America, N.A., Bank of Tokyo-Mitsubishi UFJ, Ltd., Mizuho Bank, Ltd. and DNB Bank ASA, New York Branch as documentation agents, and the other commercial lending institutions party thereto (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Report: August 27, 2015) filed August 31, 2015 and incorporated herein by reference).
|
10.6
|
—
|
Term Loan Agreement as of January 6, 2016 among Noble Energy, Inc., Citibank, N.A., as administrative agent, Mizuho Bank, Ltd., as syndication agent and certain financial institutions as are or may become parties thereto (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Report: January 6, 2016) filed on January 7, 2016 and incorporated herein by reference).
|
10.7*
|
—
|
Noble Energy, Inc. Retirement Restoration Plan dated effective as of January 1, 2009 (filed as Exhibit 10.1 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2008 and incorporated herein by reference).
|
10.8*
|
—
|
Amendment No. 1 to the Noble Energy, Inc. Retirement Restoration Plan, dated effective as of December 31, 2013 (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Report: December 20, 2013) filed December 23, 2013 and incorporated herein by reference).
|
10.9*
|
—
|
Noble Energy, Inc. Restoration Trust effective August 1, 2002 (filed as Exhibit 10.3 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002 and incorporated herein by reference).
|
10.10*
|
—
|
Form of Indemnity Agreement entered into between the Registrant and each of the Registrant’s directors and bylaw officers (filed as Exhibit 10.18 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 1995 and incorporated herein by reference).
|
10.11*
|
—
|
Noble Energy, Inc. 2005 Non-Employee Director Fee Deferral Plan, dated December 11, 2008, and effective as of January 1, 2009 (filed as Exhibit 10.20 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2008 and incorporated herein by reference).
|
10.12*
|
—
|
2015 Stock Plan for Non-Employee Directors of Noble Energy, Inc. (as amended and restated effective October 20, 2015) (filed as Exhibit 10.4 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2015 and incorporated herein by reference).
|
10.13*
|
—
|
Form of Stock Option Agreement under the Noble Energy, Inc. 2015 Non-Employee Director Stock Plan (filed as Exhibit 10.7 to the Registrant’s Current Report on Form 8-K (Date of Report: January 25, 2016) filed January 29, 2016 and incorporated herein by reference).
.
|
10.14*
|
—
|
Form of Restricted Stock Agreement under the Noble Energy, Inc. 2015 Non-Employee Director Stock Plan (filed as Exhibit 10.6 to the Registrant’s Current Report on Form 8-K (Date of Report: January 25, 2016) filed January 29, 2016 and incorporated herein by reference).
.
|
10.15*
|
—
|
2005 Stock Plan for Non-Employee Directors of Noble Energy, Inc. (as amended and restated effective October 20, 2015) (filed as Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2015 and incorporated herein by reference).
|
10.16*
|
—
|
Form of Stock Option Agreement under the Noble Energy, Inc. 2005 Non-Employee Director Stock Plan (filed as Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 and incorporated herein by reference).
|
10.17*
|
—
|
Form of Restricted Stock Agreement under the Noble Energy, Inc. 2005 Non-Employee Director Stock Plan (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Report: January 27, 2009) filed on February 2, 2009 and incorporated herein by reference).
|
10.18*
|
—
|
Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan (as amended and restated effective October 20, 2015) (filed as Exhibit 10.2 to Registrant’s Quarterly report on Form 10-Q for the quarter ended September 30, 2015 and incorporated herein by reference).
|
10.19*
|
—
|
Form of Nonqualified Stock Option Agreement under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Event: February 1, 2005) filed February 7, 2005 and incorporated herein by reference).
|
10.20*
|
—
|
Form of Non-Qualified Stock Option Agreement under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan (filed as Exhibit 10.24 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2012 and incorporated herein by reference).
|
10.21*
|
—
|
Form of Restricted Stock Agreement (two-year vested) under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan (filed as Exhibit 10.25 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2012 and incorporated herein by reference).
|
10.22*
|
—
|
Form of Restricted Stock Agreement (three-year vested awards) under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan (filed as Exhibit 10.26 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2012 and incorporated herein by reference).
|
10.23*
|
—
|
Form of Restricted Stock Agreement (performance-vested) under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan (filed as Exhibit 10.27 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2012 and incorporated herein by reference).
|
10.24*
|
—
|
Form of Non-Qualified Stock Option Agreement under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan (effective February 1, 2016) (filed as Exhibit 10.5 to the Registrant’s Current Report on Form 8-K (Date of Report: January 25, 2016) filed January 29, 2016 and incorporated herein by reference).
.
|
10.25*
|
—
|
Form of Restricted Stock Agreement (two-year time vested for non-PEO executive officers) under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan (effective February 1, 2016) (filed as Exhibit 10.2 to the Registrant’s Current Report on Form 8-K (Date of Report: January 25, 2016) filed January 29, 2016 and incorporated herein by reference).
.
|
10.26*
|
—
|
Form of Restricted Stock Agreement (two-year time vested) under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan (effective February 1, 2016) filed herewith.
|
10.27*
|
—
|
Form of Performance Award Agreement (3-year performance vested stock and cash) under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan (effective February 1, 2016) (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Report: January 25, 2016) filed January 29, 2016 and incorporated herein by reference).
.
|
10.28*
|
—
|
Form of Cash Award Agreement (two-year vested) under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan (effective February 1, 2016) (filed as Exhibit 10.4 to the Registrant’s Current Report on Form 8-K (Date of Report: January 25, 2016) filed January 29, 2016 and incorporated herein by reference).
.
|
10.29*
|
|
Form of Restricted Stock Agreement (three-year performance-vested) under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan (effective February 1, 2016) (filed as Exhibit 10.8 to the Registrant's Current Report on Form 8-K/A (Date of Report: January 25, 2016), filed February 4, 2015 and incorporated herein by reference).
|
10.30*
|
—
|
Amendment to the Noble Energy, Inc. Change of Control Agreement dated effective February 1, 2011 (filed as Exhibit 10.2 to the Registrant’s Current Report on Form 8-K (Date of Report: February 1, 2011), filed February 4, 2011 and incorporated herein by reference).
|
10.31*
|
—
|
Form of Noble Energy, Inc. Change of Control Agreement (as amended effective January 1, 2008), (filed as Exhibit 10.41 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2007 and incorporated herein by reference).
|
10.32*
|
—
|
Noble Energy, Inc. Change of Control Severance Plan for Executives (effective December 7, 2016) filed herewith.
|
10.33*
|
—
|
Termination of Change of Control Agreement dated effective October 21, 2014 by and between Noble Energy, Inc. and David L. Stover (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Report: October 21, 2014) filed October 27, 2014 and incorporated herein by reference).
|
10.34*
|
—
|
Noble Energy, Inc. Deferred Compensation Plan (formerly known as the Noble Affiliates, Inc. Deferred Compensation Plan) as restated effective August 1, 2001 (filed as Exhibit 10.4 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002 and incorporated herein by reference).
|
10.35*
|
—
|
Amendment No. 1 to the Noble Energy, Inc. Deferred Compensation Plan (formerly known as the Noble Affiliates, Inc. Deferred Compensation Plan), dated effective as of January 1, 2014 (filed as Exhibit 10.2 to the Registrant’s Current Report on Form 8-K (Date of Report: December 20, 2013) filed December 23, 2013 and incorporated herein by reference).
|
10.36*
|
—
|
Noble Energy, Inc. 2005 Deferred Compensation Plan (as amended effective January 1, 2009), (filed as Exhibit 10.31 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2008 and incorporated herein by reference).
|
10.37*
|
—
|
Amendment No. 1 to the Noble Energy, Inc. 2005 Deferred Compensation Plan, dated effective as of January 1, 2014 (filed as Exhibit 10.3 to the Registrant’s Current Report on Form 8-K (Date of Report: December 20, 2013) filed December 23, 2013 and incorporated herein by reference).
|
10.38*
|
—
|
Amendment No. 2 to the Noble Energy, Inc. 2005 Deferred Compensation Plan, dated effective as of January 1, 2015, (filed as Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016 and incorporated herein by reference).
|
10.39*
|
—
|
Amendment No. 3 to the Noble Energy, Inc. 2005 Deferred Compensation Plan, dated effective as of August 1, 2016, (filed as Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016 and incorporated herein by reference).
|
10.40
|
—
|
Gas Sale and Purchase Agreement dated March 14, 2012, by and between Noble Energy Mediterranean Ltd. Isramco Negev 2 Limited Partnership, Delek Drilling Limited Partnership, Avner Oil Exploration Limited Partnership, and Dor Gas Exploration Limited Partnership (Sellers) and The Israel Electric Corporation Limited (Purchaser), (filed as Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q/A for the quarter ended March 31, 2012 and incorporated herein by reference).
|
10.41
|
—
|
Amendment No. 1 dated July 22, 2012 to the Gas Sale and Purchase Agreement dated March 14, 2012, by and between Noble Energy Mediterranean Ltd. Isramco Negev 2 Limited Partnership, Delek Drilling Limited Partnership, Avner Oil Exploration Limited Partnership, and Dor Gas Exploration Limited Partnership (Sellers) and The Israel Electric Corporation Limited (Purchaser), (filed as Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012 and incorporated herein by reference).
|
10.42*
|
—
|
Retention and Confidentiality Agreement between Noble Energy, Inc. and Charles D. Davidson, Chairman and Chief Executive Officer, effective as of August 14, 2014 (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Report: August 14, 2014), filed August 19, 2014 and incorporated herein by reference).
|
10.43
|
—
|
Support Agreement, dated as of January 13, 2017, by and among certain stockholders affiliated with Ares
Management, LLC, Noble Energy, Inc., and solely for certain purposes specified therein, Clayton Williams
Energy, Inc. (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Report: January
13, 2017) filed on January 17, 2017 and incorporated herein by reference).
|
10.44
|
—
|
Agreement Not to Dissent, dated as of January 13, 2017, by and among Clayton W. Williams, Jr., Noble
Energy, Inc., and solely for certain purposes specified therein, Clayton Williams Energy, Inc. (filed as Exhibit 10.2 to the Registrant’s Current Report on Form 8-K (Date of Report: January 13, 2017) filed on January 17, 2017 and incorporated herein by reference).
|
10.45
|
—
|
Agreement Not to Dissent, dated as of January 13, 2017, by and among The Williams Children’s Partnership, Ltd., Noble Energy, Inc., and solely for certain purposes specified therein, Clayton Williams Energy, Inc. (filed as Exhibit 10.3 to the Registrant’s Current Report on Form 8-K (Date of Report: January 13, 2017) filed on January 17, 2017 and incorporated herein by reference).
|
12.1
|
—
|
Calculation of ratio of earnings to fixed charges, filed herewith.
|
21
|
—
|
Subsidiaries, filed herewith.
|
23.1
|
—
|
Consent of Independent Registered Public Accounting Firm—KPMG LLP, filed herewith.
|
23.2
|
—
|
Consent of Independent Petroleum Engineers and Geologists—Netherland, Sewell & Associates, Inc., filed herewith.
|
31.1
|
—
|
Certification of the Registrant's Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241), filed herewith.
|
31.2
|
—
|
Certification of the Registrant's Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241), filed herewith.
|
32.1
|
—
|
Certification of the Registrant’s Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350), filed herewith.
|
32.2
|
—
|
Certification of the Registrant’s Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350), filed herewith.
|
99.1
|
—
|
Report of Netherland, Sewell & Associates, Inc., filed herewith.
|
101.INS
|
—
|
XBRL Instance Document
|
101.SCH
|
—
|
XBRL Schema Document
|
101.CAL
|
—
|
XBRL Calculation Linkbase Document
|
101.LAB
|
—
|
XBRL Label Linkbase Document
|
101.PRE
|
—
|
XBRL Presentation Linkbase Document
|
101.DEF
|
—
|
XBRL Definition Linkbase Document
|
*
|
Management contract or compensatory plan or arrangement required to be filed as an exhibit hereto.
|
**
|
Copies of exhibits will be furnished upon prepayment of 25 cents per page. Requests should be addressed to the Executive Vice President and Chief Financial Officer, Noble Energy, Inc., 1001 Noble Energy Way, Houston, Texas 77070.
|
Bbl
|
|
Barrel
|
BBoe
|
|
Billion barrels oil equivalent
|
Bcf
|
|
Billion cubic feet
|
Bcf/d
|
|
Billion cubic feet per day
|
BCM
|
|
Billion cubic meters
|
BOE
|
|
Barrels oil equivalent. Natural gas is converted on the basis of six Mcf of gas per one barrel of crude oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Given commodity price disparities, the price for a barrel of crude oil equivalent for natural gas is significantly less than the price for a barrel of crude oil. The price for a barrel of NGL is also less than the price for a barrel of crude oil.
|
Boe/d
|
|
Barrels oil equivalent per day
|
Btu
|
|
British thermal unit
|
FPSO
|
|
Floating production, storage and offloading vessel
|
GSPA
|
|
Gas Sales Purchase Agreement
|
GHG
|
|
Greenhouse gas emissions
|
HH
|
|
Henry Hub index
|
LNG
|
|
Liquefied natural gas
|
LPG
|
|
Liquefied petroleum gas
|
MBbl/d
|
|
Thousand barrels per day
|
MBoe/d
|
|
Thousand barrels oil equivalent per day
|
Mcf
|
|
Thousand cubic feet
|
MMBbls
|
|
Million barrels
|
MMBoe
|
|
Million barrels oil equivalent
|
MMBtu
|
|
Million British thermal units
|
MMBtu/d
|
|
Million British thermal units per day
|
MMcf/d
|
|
Million cubic feet per day
|
MMcfe/d
|
|
Million cubic feet equivalent per day
|
MMgal
|
|
Million gallons
|
NGL
|
|
Natural gas liquids
|
NYMEX
|
|
The New York Mercantile Exchange
|
OPEC
|
|
The Organization of Petroleum Exporting Countries
|
PSC
|
|
Production sharing contract
|
Tcf
|
|
Trillion cubic feet
|
US GAAP
|
|
United States generally accepted accounting principles
|
WTI
|
|
West Texas Intermediate index
|
Noble Energy, Inc.
|
||||||||||||||||||||
Calculation of Ratio of Earnings to Fixed Charges
|
||||||||||||||||||||
|
|
Year Ended December 31,
|
||||||||||||||||||
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
(millions)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Income (Loss) From Continuing Operations Before Income Tax, Non-controlling Interests and Income From Equity Investees
|
|
$
|
(1,887
|
)
|
|
$
|
(2,309
|
)
|
|
$
|
1,540
|
|
|
$
|
1,138
|
|
|
$
|
1,170
|
|
Add (Deduct)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed Charges
|
|
440
|
|
|
435
|
|
|
349
|
|
|
296
|
|
|
288
|
|
|||||
Capitalized Interest
|
|
(84
|
)
|
|
(144
|
)
|
|
(116
|
)
|
|
(121
|
)
|
|
(151
|
)
|
|||||
Distributed Income From Equity Investees
|
|
83
|
|
|
77
|
|
|
226
|
|
|
204
|
|
|
204
|
|
|||||
Earnings as Defined
|
|
$
|
(1,448
|
)
|
|
$
|
(1,941
|
)
|
|
$
|
1,999
|
|
|
$
|
1,517
|
|
|
$
|
1,511
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net Interest Expense
|
|
328
|
|
|
263
|
|
|
210
|
|
|
158
|
|
|
125
|
|
|||||
Capitalized Interest
|
|
84
|
|
|
144
|
|
|
116
|
|
|
121
|
|
|
151
|
|
|||||
Interest Portion of Rental Expense
|
|
28
|
|
|
28
|
|
|
23
|
|
|
17
|
|
|
12
|
|
|||||
Fixed Charges as Defined
|
|
$
|
440
|
|
|
$
|
435
|
|
|
$
|
349
|
|
|
$
|
296
|
|
|
$
|
288
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Ratio of Earnings to Fixed Charges
|
|
—
|
|
|
—
|
|
|
5.7
|
|
|
5.1
|
|
|
5.2
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Amount by Which Earnings Were Insufficient to Cover Fixed Charges
|
|
$
|
1,888
|
|
|
$
|
2,376
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
NAME
|
|
JURISDICTION OF ORGANIZATION
|
AMPCO Marketing, L.L.C.
|
|
Michigan
|
AMPCO Services, L.L.C.
|
|
Michigan
|
Ardmore Real Estate, LLC
|
|
Delaware
|
Atlantic Methanol Associates LLC
|
|
Cayman Islands
|
Blanco River DevCo GP LLC
|
|
Delaware
|
Blanco River DevCo LP
|
|
Delaware
|
Colorado River DevCo GP LLC
|
|
Delaware
|
Colorado River DevCo LP
|
|
Delaware
|
Comin 1989 Partnership LLP
|
|
Oklahoma
|
Comin-Temin LLC
|
|
Oklahoma
|
CONE Gathering LLC (Partnership)
|
|
Delaware
|
CONE Midstream GP LLC
|
|
Delaware
|
EDC Ecuador Ltd.
|
|
Delaware
|
EDC South America Limited
|
|
Cayman Islands
|
Energy Development Corporation (Argentina), Inc.
|
|
Delaware
|
Energy Development Corporation (China), Inc.
|
|
Delaware
|
Green River DevCo GP LLC
|
|
Delaware
|
Green River DevCo LP
|
|
Delaware
|
Gunnison River DevCo GP LLC
|
|
Delaware
|
Gunnison River DevCo LP
|
|
Delaware
|
Laramie River DevCo GP LLC
|
|
Delaware
|
Laramie River DevCo LP
|
|
Delaware
|
MachalaPower Cia. Ltda.
|
|
Cayman Islands
|
NBL C.V.
|
|
Netherlands
|
NBL Cheetah Limited
|
|
Cayman Islands
|
NBL Congo Holding LLC (fka NBL Nicaragua Holding, LLC)
|
|
Delaware
|
NBL Congo Limited (fka NBL Nicaragua Limited)
|
|
Cayman Islands
|
NBL Eastern Mediterranean Marketing Limited
|
|
Cayman Islands
|
NBL Energy Royalties, Inc. (fka NBL Royalties, Inc.)
|
|
Delaware
|
NBL Gabon Holding, LLC
|
|
Delaware
|
NBL Gabon Limited
|
|
Cayman Islands
|
NBL Gabon LLC
|
|
Delaware
|
NBL Humpback Limited
|
|
Cayman Islands
|
NBL International C.V.
|
|
Netherlands
|
NBL International Finance B.V.
|
|
Netherlands
|
NBL International Holdings, LLC
|
|
Delaware
|
NBL International Risk Management Limited
|
|
Cayman Islands
|
NBL Mexico Holding, LLC
|
|
Delaware
|
NBL Mexico, Inc.
|
|
Delaware
|
NBL Midstream Holdings, LLC
|
|
Delaware
|
NBL Midstream, LLC
|
|
Delaware
|
NBL Netherlands B.V.
|
|
Netherlands
|
NBL North American Risk Management, LLC
|
|
Delaware
|
NBL Rhea Limited
|
|
Cayman Islands
|
NBL Suriname B.V.
|
|
Netherlands
|
NBL Suriname Holding, LLC
|
|
Delaware
|
NBL Texas, LLC
|
|
Delaware
|
NBL UK C.V.
|
|
Netherlands
|
NCWYO Assets LLC
|
|
Delaware
|
Noble Energy (Cyprus) Limited
|
|
Cyprus
|
Noble Energy (ISE) Limited
|
|
United Kingdom
|
Noble Energy (Oilex) Limited
|
|
United Kingdom
|
Noble Energy Cameroon Limited
|
|
Cayman Islands
|
Noble Energy Canada Inc.
|
|
Delaware
|
Noble Energy Canada ULC
|
|
British Columbia
|
Noble Energy Capital Limited
|
|
United Kingdom
|
Noble Energy Cyprus LNG Ltd (fka Noble Energy Cyprus Oil & Gas Ltd)
|
|
Cyprus
|
Noble Energy Cyprus Midstream Holding, LLC (fka NBL Cameroon Holdings LLC)
|
|
Delaware
|
Noble Energy Cyprus Midstream Limited (fka NBL Cameroon Limited)
|
|
Cayman Islands
|
Noble Energy EG Ltd.
|
|
Cayman Islands
|
Noble Energy EMEA Ventures Limited (fka EDC Ireland)
|
|
Cayman Islands
|
Noble Energy Falklands Holding, LLC
|
|
Delaware
|
Noble Energy Falklands Limited
|
|
United Kingdom
|
Noble Energy Gabon Holding Company, LLC (fka Noble Energy EG Holding Company, LLC)
|
|
Delaware
|
Noble Energy Gabon Limited (fka Noble Energy EG II Limited)
|
|
Cayman Islands
|
Noble Energy Global Ventures Ltd. (fka Noble Energy India Ltd.)
|
|
Cayman Islands
|
Noble Energy International Holdings, Inc.
|
|
Delaware
|
Noble Energy International Holdings, LLC
|
|
Delaware
|
Noble Energy International Ltd. (fka Samedan International)
|
|
Cyprus
|
Noble Energy Mediterranean Ltd. (fka Samedan Mediterranean Sea)
|
|
Cayman Islands
|
Noble Energy Mexico, S. de R.L. de C.V.
|
|
Delaware
|
Noble Energy New Ventures, LLC
|
|
Delaware
|
Noble Energy Nicaragua Ltd.
|
|
Cayman Islands
|
Noble Energy Services, Inc.
|
|
Delaware
|
Noble Energy Sierra Leone Holdings, LLC
|
|
Delaware
|
Noble Energy SL Limited
|
|
United Kingdom
|
Noble Energy US Holdings, LLC
|
|
Delaware
|
Noble Energy Wyco, LLC
|
|
Delaware
|
Noble Energy, Inc. (fka Noble Affiliates, Inc.)
|
|
Delaware
|
Noble Midstream GP LLC (fka Noble Energy Midstream GP LLC)
|
|
Delaware
|
Noble Midstream Partners LP (fka Noble Energy Midstream LP)
|
|
Delaware
|
Noble Midstream Services, LLC (fka Noble DJ Midstream Services Company, LLC)
|
|
Delaware
|
Oil Insurance Company
|
|
Bermuda
|
Rosetta Resources Holdings, LLC
|
|
Delaware
|
Rosetta Resources Michigan Limited Partnership
|
|
Delaware
|
Rosetta Resources Offshore, LLC
|
|
Delaware
|
Rosetta Resources Operating GP, LLC
|
|
Delaware
|
Rosetta Resources Operating LP
|
|
Delaware
|
Samedan Methanol
|
|
Cayman Islands
|
Samedan of North Africa, LLC
|
|
Delaware
|
Samedan Pipe Line Corporation
|
|
Delaware
|
Samedan Royalty, LLC
|
|
Delaware
|
San Juan River DevCo GP LLC
|
|
Delaware
|
San Juan River DevCo LP
|
|
Delaware
|
Seven Oaks Insurance Limited
|
|
Bermuda
|
SNS (E&P) Limited
|
|
United Kingdom
|
Temin 1987 Partnership LLP
|
|
Oklahoma
|
Trinity River DevCo LLC
|
|
Delaware
|
White Star Insurance LLC
|
|
Texas
|
|
|
|
|
|
NETHERLAND, SEWELL & ASSOCIATES, INC.
|
||
|
|
|
|
|
By:
|
/s/ Danny D. Simmons
|
|
|
|
Danny D. Simmons, P.E.
|
|
|
|
President and Chief Operating Officer
|
|
|
|
|
|
Houston, Texas
|
|
|
|
February 14, 2017
|
|
|
|
1.
|
I have reviewed this annual report on Form 10-K of Noble Energy, Inc.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
Date:
|
February 14, 2017
|
|
|
|
|
|
|
/s/ David L. Stover
|
|
||
David L. Stover
|
|
||
Chief Executive Officer
|
|
1.
|
I have reviewed this annual report on Form 10-K of Noble Energy, Inc.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
Date:
|
February 14, 2017
|
|
|
|
|
|
|
/s/ Kenneth M. Fisher
|
|
||
Kenneth M. Fisher
|
|
||
Chief Financial Officer
|
|
(1)
|
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and
|
(2)
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
Date:
|
February 14, 2017
|
|
/s/ David L. Stover
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David L. Stover
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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 (15 U.S.C. 78m or 78o(d)); 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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Date:
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February 14, 2017
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/s/ Kenneth M. Fisher
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Kenneth M. Fisher
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Chief Financial Officer
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Net Reserves
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|||||||
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Oil
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NGL
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Gas
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|||
Category
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(MBBL)
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(MBBL)
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(MMCF)
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|||
|
|
|
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|
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|||
Proved Developed Producing
|
|
163,890.656
|
|
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119,495.898
|
|
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3,224,921.500
|
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Proved Developed Non-Producing
|
|
10,065.754
|
|
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5,347.180
|
|
|
678,023.812
|
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Proved Undeveloped
|
|
158,578.969
|
|
|
94,459.719
|
|
|
1,409,110.375
|
|
|
|
|
|
|
|
|
|||
Total Proved
|
|
332,535.375
|
|
|
219,302.781
|
|
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5,312,055.500
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