Delaware
|
|
73-0785597
|
(State of incorporation)
|
|
(I.R.S. employer identification number)
|
1001 Noble Energy Way
|
|
|
Houston, Texas
|
|
77070
|
(Address of principal executive offices)
|
|
(Zip Code)
|
Title of each class
|
|
Name of each exchange on which registered
|
Common Stock, $0.01 par value
|
|
New York Stock Exchange
|
Large accelerated filer
x
|
Accelerated filer
o
|
Non-accelerated filer
o
|
Smaller reporting company
o
|
Emerging growth company
o
|
|
(Do not check if a smaller reporting company)
|
|
PART I
|
||
Items 1. and 2.
|
||
Item 1A.
|
||
Item 1B.
|
||
Item 3.
|
||
Item 4.
|
||
PART II
|
||
Item 5.
|
||
Item 6.
|
||
Item 7.
|
||
Item 7A.
|
||
Item 8.
|
||
Item 9.
|
||
Item 9A.
|
||
Item 9B.
|
||
PART III
|
||
Item 10.
|
||
Item 11.
|
||
Item 12.
|
||
Item 13.
|
||
Item 14.
|
||
PART IV
|
||
Item 15.
|
||
Item 16.
|
•
|
our growth strategies;
|
•
|
our future results of operations;
|
•
|
our liquidity and ability to finance our exploration and development activities;
|
•
|
our ability to successfully and economically explore for and develop crude oil, natural gas and natural gas liquids (NGLs) resources;
|
•
|
anticipated trends in our business;
|
•
|
market conditions in the oil and gas industry;
|
•
|
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;
|
•
|
our ability to make and integrate acquisitions; and
|
•
|
access to resources.
|
|
|
December 31, 2017
|
||||||||||
|
|
Proved Reserves
|
||||||||||
|
|
Crude Oil and
Condensate
|
|
NGLs
|
|
Natural Gas
|
|
Total
|
||||
Reserves Category
|
|
(MMBbls)
|
|
(MMBbls)
|
|
(Bcf)
|
|
(MMBoe)
(1)
|
||||
Proved Developed
|
|
|
|
|
|
|
|
|
||||
United States
|
|
176
|
|
|
119
|
|
|
983
|
|
|
458
|
|
Israel
|
|
3
|
|
|
—
|
|
|
1,793
|
|
|
302
|
|
Equatorial Guinea
|
|
29
|
|
|
11
|
|
|
411
|
|
|
108
|
|
Total Proved Developed Reserves
|
|
208
|
|
|
130
|
|
|
3,187
|
|
|
868
|
|
Proved Undeveloped
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
243
|
|
|
99
|
|
|
838
|
|
|
482
|
|
Israel
|
|
6
|
|
|
—
|
|
|
3,655
|
|
|
615
|
|
Total Proved Undeveloped Reserves
|
|
249
|
|
|
99
|
|
|
4,493
|
|
|
1,097
|
|
Total Proved Reserves
|
|
457
|
|
|
229
|
|
|
7,680
|
|
|
1,965
|
|
•
|
revisions of
135
MMBoe, including positive revisions of
105
MMBoe driven by performance related to the US onshore horizontal drilling programs and offshore Israel associated with the enhanced geologic modeling across the Tamar reservoir, as well as an increase of
30
MMBoe driven by positive price revisions;
|
•
|
extensions, discoveries and other additions of
736
MMboe, including additions of
551
MMBoe related to the sanction of the first phase of development of the Leviathan natural gas project, as well as extensions of
185
MMBoe related to US onshore horizontal drilling programs due to successful expansion of our extended reach lateral well programs;
|
•
|
acquisition of
57
MMBoe primarily related to the Clayton Williams Energy Acquisition;
|
•
|
production volumes of
139
MMBoe; and
|
•
|
divestiture of reserves of
261
MMBoe, primarily due to the Marcellus Shale upstream divestiture and other smaller US onshore divestitures.
|
|
|
Year Ended December 31, 2017
|
|
December 31, 2017
|
||||||||||||||||||||
|
|
Sales Volumes
|
|
Proved Reserves
|
||||||||||||||||||||
|
|
Crude Oil &
Condensate
|
|
NGLs
|
|
Natural
Gas |
|
Total
|
|
Crude Oil &
Condensate
|
|
NGLs
|
|
Natural
Gas |
|
Total
|
||||||||
|
|
(MBbl/d)
|
|
(MBbl/d)
|
|
(MMcf/d)
|
|
(MBoe/d)
|
|
(MMBbls)
|
|
(MMBbls)
|
|
(Bcf)
|
|
(MMBoe)
|
||||||||
DJ Basin
|
|
59
|
|
|
19
|
|
|
193
|
|
|
110
|
|
|
203
|
|
|
99
|
|
|
1,094
|
|
|
484
|
|
Delaware Basin
|
|
17
|
|
|
4
|
|
|
24
|
|
|
26
|
|
|
166
|
|
|
38
|
|
|
199
|
|
|
238
|
|
Eagle Ford Shale
|
|
11
|
|
|
28
|
|
|
186
|
|
|
70
|
|
|
29
|
|
|
79
|
|
|
501
|
|
|
191
|
|
Marcellus Shale
(1)
|
|
1
|
|
|
5
|
|
|
174
|
|
|
34
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Gulf of Mexico
|
|
21
|
|
|
2
|
|
|
21
|
|
|
26
|
|
|
18
|
|
|
2
|
|
|
21
|
|
|
23
|
|
Other US Onshore
|
|
2
|
|
|
—
|
|
|
9
|
|
|
4
|
|
|
3
|
|
|
—
|
|
|
6
|
|
|
4
|
|
Total
|
|
111
|
|
|
58
|
|
|
607
|
|
|
270
|
|
|
419
|
|
|
218
|
|
|
1,821
|
|
|
940
|
|
|
|
Year Ended December 31, 2017
|
|
December 31, 2017
|
||
|
|
Gross Wells Completed
or Participated in
|
|
Gross Productive
Wells
|
||
DJ Basin
|
|
138
|
|
|
6,226
|
|
Delaware Basin
|
|
75
|
|
|
1,898
|
|
Eagle Ford Shale
|
|
47
|
|
|
344
|
|
Gulf of Mexico
|
|
—
|
|
|
14
|
|
Other US Onshore
|
|
12
|
|
|
1
|
|
Total
|
|
272
|
|
|
8,483
|
|
|
|
Year Ended December 31, 2017
|
|
December 31, 2017
|
||
|
|
Gross Wells Completed
or Participated in
(1)
|
|
Gross Productive
Wells
|
||
International
|
|
|
|
|
||
Israel
|
|
1
|
|
|
7
|
|
Equatorial Guinea
|
|
—
|
|
|
28
|
|
Total International
|
|
1
|
|
|
35
|
|
(1)
|
Excludes the Araku-1 exploration well, offshore Suriname.
|
•
|
completion of a produced water expansion project servicing the Wells Ranch IDP area;
|
•
|
completion of crude oil and produced water gathering systems servicing the Greeley Crescent IDP area;
|
•
|
completion of the connection from the CGF in the Delaware Basin to the Advantage Pipeline, which began allowing crude oil to flow from the completed facility to the Advantage Pipeline in third quarter 2017;
|
•
|
completion of the construction of two CGFs in the Delaware Basin; and
|
•
|
continued construction activities on expansion of our freshwater system servicing the Mustang IDP area and the commencement of construction of the backbone gathering infrastructure build-out, which is expected to be completed in early 2018.
|
•
|
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,
|
|||||||
|
|
2017
|
|
2016
|
|
2015
|
|||
(MMBoe)
|
|
|
|
|
|
|
|||
Proved Reserves Beginning of Year
|
|
1,437
|
|
|
1,421
|
|
|
1,404
|
|
Revisions of Previous Estimates
|
|
135
|
|
|
64
|
|
|
(216
|
)
|
Extensions, Discoveries and Other Additions
|
|
736
|
|
|
179
|
|
|
100
|
|
Purchase of Minerals in Place
|
|
57
|
|
|
4
|
|
|
269
|
|
Sale of Minerals in Place
|
|
(261
|
)
|
|
(77
|
)
|
|
(6
|
)
|
Production
|
|
(139
|
)
|
|
(154
|
)
|
|
(130
|
)
|
Proved Reserves End of Year
|
|
1,965
|
|
|
1,437
|
|
|
1,421
|
|
•
|
positive price revisions of 30 MMBoe globally, as well as positive performance revisions of 49 MMBoe for the Tamar field, offshore Israel, 30 MMBoe for the Delaware Basin and 22 MMBoe for the Eagle Ford Shale, partially offset by abandonment cost increases for US onshore in
2017
;
|
•
|
positive revisions of 43 MMBoe for the DJ Basin, 42 MMBoe for the Marcellus Shale, 11 MMBoe for the Delaware Basin, and 10 MMBoe for the 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 in
2016
; and
|
•
|
negative price revisions of 307 MMBoe, partially offset by positive performance revisions of 81 MMBoe for the Marcellus Shale and 17 MMBoe for the Delaware Basin in
2015
.
|
•
|
increases primarily relate to 99 MMBoe in the DJ Basin and 77 MMBoe in the Delaware Basin as a result of enhanced completion techniques in our horizontal drilling programs and an increase of 551 MMBoe due to the sanction of the first phase of development at the Leviathan natural gas field in
2017
;
|
•
|
increases of 83 MMBoe in the DJ Basin, 42 MMBoe in the Marcellus Shale, 33 MMBoe in the Delaware Basin and 21 MMBoe in the Eagle Ford Shale, all associated with our horizontal drilling programs in
2016
; and
|
•
|
increases of 86 MMBoe in the DJ Basin and 14 MMBoe in the Marcellus Shale associated with our horizontal drilling programs in
2015
.
|
•
|
an increase of
57
MMBoe in the Delaware Basin primarily as a result of the Clayton Williams Energy Acquisition in 2017; and
|
•
|
the acquisition of additional acreage, primarily in the Eagle Ford Shale and Delaware Basin in Texas in 2015 in connection with the Rosetta Merger.
|
•
|
a reduction of 241 MMBoe related to the Marcellus Shale upstream divestiture, as well as 20 MMBoe associated with divestment of non-strategic US onshore assets in 2017;
|
•
|
a reduction of 36 MMBoe in Israel driven by our 3.5% sale of Tamar working interest, as well as a 29 MMBoe divestment in the Marcellus Shale in 2016; and
|
•
|
the sale of non-strategic US onshore assets in 2015.
|
|
|
United
States
|
|
Israel
|
|
Total
|
|||
(MMBoe)
|
|
|
|
|
|
|
|||
Proved Undeveloped Reserves Beginning of Year
|
|
422
|
|
|
64
|
|
|
486
|
|
Revisions of Previous Estimates
|
|
26
|
|
|
—
|
|
|
26
|
|
Extensions, Discoveries and Other Additions
|
|
174
|
|
|
551
|
|
|
725
|
|
Purchase of Minerals in Place
|
|
36
|
|
|
—
|
|
|
36
|
|
Sale of Minerals in Place
|
|
(54
|
)
|
|
—
|
|
|
(54
|
)
|
Conversion to Proved Developed
|
|
(122
|
)
|
|
—
|
|
|
(122
|
)
|
Proved Undeveloped Reserves End of Year
|
|
482
|
|
|
615
|
|
|
1,097
|
|
•
|
94 MMBoe in the DJ Basin;
|
•
|
74 MMBoe in the Delaware Basin;
|
•
|
6 MMBoe in the Eagle Ford Shale; and
|
•
|
551 MMBoe in the Leviathan field.
|
•
|
34 MMBoe in the DJ Basin;
|
•
|
17 MMBoe in the Delaware Basin;
|
•
|
60 MMBoe in the Eagle Ford Shale; and
|
•
|
11 MMBoe in the Marcellus Shale, prior to divestiture.
|
•
|
263
MMBoe in the DJ Basin;
|
•
|
181
MMBoe in the Delaware Basin; and
|
•
|
38
MMBoe in the Eagle Ford 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 – Supplemental Oil and Gas Information (Unaudited)
for additional information regarding estimates of crude oil, NGL and natural gas 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
|
|
NGLs
MBbl
|
|
Natural Gas
MMcf |
|
Crude Oil &
Condensate
Per Bbl
|
|
NGLs Per
Bbl
|
|
Natural Gas
Per Mcf |
|
Per BOE
|
|||||||||||
Year Ended December 31, 2017
(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
DJ Basin
|
|
21,564
|
|
|
6,911
|
|
|
70,660
|
|
|
$
|
50.20
|
|
|
$
|
25.22
|
|
|
$
|
2.96
|
|
|
$
|
4.46
|
|
Marcellus Shale
|
|
233
|
|
|
1,654
|
|
|
63,443
|
|
|
36.91
|
|
|
23.81
|
|
|
3.15
|
|
|
1.05
|
|
||||
Other US
|
|
18,757
|
|
|
12,521
|
|
|
87,364
|
|
|
48.01
|
|
|
22.34
|
|
|
2.99
|
|
|
6.48
|
|
||||
Total US
|
|
40,554
|
|
|
21,086
|
|
|
221,467
|
|
|
49.11
|
|
|
23.40
|
|
|
3.02
|
|
|
4.81
|
|
||||
Israel
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Tamar Field
|
|
130
|
|
|
—
|
|
|
96,894
|
|
|
46.95
|
|
|
—
|
|
|
5.37
|
|
|
2.02
|
|
||||
Other Israel
|
|
—
|
|
|
—
|
|
|
2,346
|
|
|
—
|
|
|
—
|
|
|
3.56
|
|
|
N/M
|
|
||||
Total Israel
|
|
130
|
|
|
—
|
|
|
99,240
|
|
|
46.95
|
|
|
—
|
|
|
5.32
|
|
|
2.01
|
|
||||
Equatorial Guinea
(3)
|
|
6,460
|
|
|
—
|
|
|
87,269
|
|
|
53.68
|
|
|
—
|
|
|
0.27
|
|
|
4.30
|
|
||||
Total Consolidated Operations
|
|
47,144
|
|
|
21,086
|
|
|
407,976
|
|
|
49.73
|
|
|
23.40
|
|
|
3.01
|
|
|
$
|
4.31
|
|
|||
Equity Investee
(4)
|
|
662
|
|
|
2,162
|
|
|
—
|
|
|
55.13
|
|
|
38.48
|
|
|
—
|
|
|
N/M
|
|
||||
Total
|
|
47,806
|
|
|
23,248
|
|
|
407,976
|
|
|
$
|
49.84
|
|
|
$
|
24.81
|
|
|
$
|
3.01
|
|
|
N/M
|
|
|
Year Ended December 31, 2016
(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
DJ Basin
|
|
20,342
|
|
|
7,651
|
|
|
82,431
|
|
|
$
|
40.85
|
|
|
$
|
14.66
|
|
|
$
|
2.80
|
|
|
$
|
3.99
|
|
Marcellus Shale
|
|
431
|
|
|
3,094
|
|
|
177,872
|
|
|
28.25
|
|
|
16.34
|
|
|
1.68
|
|
|
0.90
|
|
||||
Other US
|
|
15,572
|
|
|
9,087
|
|
|
62,017
|
|
|
38.26
|
|
|
14.65
|
|
|
2.42
|
|
|
6.65
|
|
||||
Total US
|
|
36,345
|
|
|
19,832
|
|
|
322,320
|
|
|
39.59
|
|
|
14.92
|
|
|
2.11
|
|
|
3.74
|
|
||||
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
(3)
|
|
9,415
|
|
|
—
|
|
|
85,987
|
|
|
43.54
|
|
|
—
|
|
|
0.27
|
|
|
4.40
|
|
||||
Total Consolidated Operations
|
|
45,900
|
|
|
19,832
|
|
|
511,115
|
|
|
40.39
|
|
|
14.92
|
|
|
2.42
|
|
|
$
|
3.72
|
|
|||
Equity Investee
(4)
|
|
629
|
|
|
1,993
|
|
|
—
|
|
|
45.44
|
|
|
26.30
|
|
|
—
|
|
|
N/M
|
|
||||
Total
|
|
46,529
|
|
|
21,825
|
|
|
511,115
|
|
|
$
|
40.46
|
|
|
$
|
15.96
|
|
|
$
|
2.42
|
|
|
N/M
|
|
|
Year Ended December 31, 2015
(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
DJ Basin
|
|
20,909
|
|
|
6,910
|
|
|
85,369
|
|
|
$
|
44.37
|
|
|
$
|
14.21
|
|
|
$
|
2.53
|
|
|
$
|
5.75
|
|
Marcellus Shale
|
|
673
|
|
|
3,480
|
|
|
143,465
|
|
|
22.39
|
|
|
14.04
|
|
|
1.75
|
|
|
1.38
|
|
||||
Other US
|
|
7,680
|
|
|
3,705
|
|
|
29,806
|
|
|
42.83
|
|
|
13.25
|
|
|
2.56
|
|
|
7.15
|
|
||||
Total US
|
|
29,262
|
|
|
14,095
|
|
|
258,640
|
|
|
43.46
|
|
|
13.91
|
|
|
2.10
|
|
|
4.46
|
|
||||
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
(3)
|
|
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
|
|
|
14,095
|
|
|
433,438
|
|
|
45.00
|
|
|
13.91
|
|
|
2.44
|
|
|
$
|
4.54
|
|
|||
Equity Investee
(4)
|
|
554
|
|
|
1,850
|
|
|
—
|
|
|
48.85
|
|
|
28.40
|
|
|
—
|
|
|
N/M
|
|
||||
Total
|
|
41,441
|
|
|
15,945
|
|
|
433,438
|
|
|
$
|
45.05
|
|
|
$
|
15.59
|
|
|
$
|
2.44
|
|
|
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)
|
For each respective year, reserves associated with the Delaware Basin or the Eagle Ford Shale did not comprise 15% or more of total reserves on a BOE basis.
|
(3)
|
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.
|
(4)
|
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
|
|
3,565
|
|
|
2,682
|
|
|
4,918
|
|
|
4,382
|
|
|
8,483
|
|
|
7,064
|
|
Israel
|
|
—
|
|
|
—
|
|
|
7
|
|
|
2
|
|
|
7
|
|
|
2
|
|
Equatorial Guinea
|
|
5
|
|
|
2
|
|
|
23
|
|
|
8
|
|
|
28
|
|
|
10
|
|
Total
|
|
3,570
|
|
|
2,684
|
|
|
4,948
|
|
|
4,392
|
|
|
8,518
|
|
|
7,076
|
|
|
|
Developed Acreage
|
|
Undeveloped Acreage
|
||||||||
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||
(thousands of acres)
|
|
|
|
|
|
|
|
|
||||
United States
|
|
|
|
|
|
|
|
|
||||
Onshore
|
|
754
|
|
|
504
|
|
|
564
|
|
|
358
|
|
Gulf of Mexico
|
|
93
|
|
|
52
|
|
|
247
|
|
|
171
|
|
Total United States
|
|
847
|
|
|
556
|
|
|
811
|
|
|
529
|
|
International
|
|
|
|
|
|
|
|
|
|
|
|
|
Israel
|
|
185
|
|
|
78
|
|
|
284
|
|
|
116
|
|
Equatorial Guinea
(1)
|
|
284
|
|
|
118
|
|
|
81
|
|
|
30
|
|
Suriname
|
|
—
|
|
|
—
|
|
|
2,095
|
|
|
419
|
|
Newfoundland, Canada
|
|
—
|
|
|
—
|
|
|
2,331
|
|
|
681
|
|
Gabon
|
|
—
|
|
|
—
|
|
|
671
|
|
|
403
|
|
Cyprus
|
|
—
|
|
|
—
|
|
|
95
|
|
|
33
|
|
Cameroon
|
|
—
|
|
|
—
|
|
|
168
|
|
|
168
|
|
Other International
|
|
2
|
|
|
—
|
|
|
284
|
|
|
211
|
|
Total International
|
|
471
|
|
|
196
|
|
|
6,009
|
|
|
2,061
|
|
Total
|
|
1,318
|
|
|
752
|
|
|
6,820
|
|
|
2,590
|
|
(1)
|
Undeveloped acreage includes an exploration lease totaling approximately 55,000 gross (19,000 net) acres which had expired in 2016. The lease was subsequently negotiated with the government of Equatorial Guinea in 2017 and was extended.
|
|
|
Net Exploratory Wells
|
|
Net Development Wells
|
|
|
|||||||||||||||
|
|
Productive
|
|
Dry
|
|
Total
|
|
Productive
|
|
Dry
|
|
Total
|
|
Total
|
|||||||
Year Ended December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
United States
|
|
—
|
|
|
—
|
|
|
—
|
|
|
185.3
|
|
|
—
|
|
|
185.3
|
|
|
185.3
|
|
Israel
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.3
|
|
|
—
|
|
|
0.3
|
|
|
0.3
|
|
Suriname
|
|
—
|
|
|
0.2
|
|
|
0.2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.2
|
|
Total
|
|
—
|
|
|
0.2
|
|
|
0.2
|
|
|
185.6
|
|
|
—
|
|
|
185.6
|
|
|
185.8
|
|
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
|
|
Cameroon
|
|
—
|
|
|
0.5
|
|
|
0.5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.5
|
|
Other International
|
|
—
|
|
|
0.4
|
|
|
0.4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.4
|
|
Total
|
|
1.5
|
|
|
4.9
|
|
|
6.4
|
|
|
212.8
|
|
|
—
|
|
|
212.8
|
|
|
219.2
|
|
|
|
Exploratory
(1)
|
|
Development
(2)
|
|
Total
|
||||||||||||
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
United States
|
|
1
|
|
|
0.5
|
|
|
114
|
|
|
105.0
|
|
|
115
|
|
|
105.5
|
|
Israel
|
|
1
|
|
|
0.3
|
|
|
5
|
|
|
2.0
|
|
|
6
|
|
|
2.3
|
|
Equatorial Guinea
|
|
2
|
|
|
0.9
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
0.9
|
|
Cameroon
|
|
1
|
|
|
1.0
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
1.0
|
|
Cyprus
|
|
1
|
|
|
0.4
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
0.4
|
|
Total
|
|
6
|
|
|
3.1
|
|
|
119
|
|
|
107.0
|
|
|
125
|
|
|
110.1
|
|
(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. Israel development wells include the Leviathan 3, 4, 5 and 7 development wells and the Tamar Southwest well.
|
•
|
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 Energy, 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; and
|
•
|
the Ministry of Energy, Commerce, Industry and Tourism, which regulates our exploration and development activities offshore Cyprus.
|
•
|
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 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, 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 Gulf of Mexico; and
|
•
|
the Department of Transportation, which has certain authority over the transportation of products, equipment and personnel necessary to our US onshore and Gulf of Mexico operations.
|
•
|
•
|
Item 1A. Risk Factors
; and
|
•
|
•
|
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;
|
•
|
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
2018
or 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, including access to sources of capital, such as debt and equity, and/or ability to finance planned capital expenditures and operations;
|
•
|
failure of our partners to fund their share of development costs or obtain financing could result in delay or cancellation of future projects, thus limiting our growth and future cash flows;
|
•
|
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 which 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; and
|
•
|
reduction or suspension of dividends on our common stock.
|
•
|
declines in our stock price;
|
•
|
additional counterparty credit risk exposure on commodity hedges and joint venture receivables; and
|
•
|
a reduction in the carrying value of goodwill.
|
•
|
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, thereby increasing supply;
|
•
|
new technologies that promote fuel efficiency and reduce energy consumption;
|
•
|
developments in the global 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, as well as the availability of battery storage;
|
•
|
the long-term impact on the crude oil market of the use of natural gas and electricity as an alternative fuel for road transportation or the use of natural gas as fuel for electricity generation impacting the demand for electricity;
|
•
|
fuel efficiency regulations, such as the Corporate Average Fuel Economy (CAFE) standards, and its impacts on demand for crude oil as a transportation fuel;
|
•
|
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;
|
•
|
access to government-owned and other lands for exploration and production activities; and
|
•
|
domestic and foreign governmental regulations and taxes.
|
•
|
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;
|
•
|
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;
|
•
|
US and international monetary policies impacting foreign exchange or repatriation restrictions in countries in which we conduct business;
|
•
|
war, piracy, acts of terrorism or civil unrest; 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 or cancel exploration and/or development 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;
|
•
|
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; and/or
|
•
|
restrict our ability to compete with imported volumes of crude oil or natural gas.
|
•
|
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.
|
•
|
new municipal, state or federal 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 and Indian 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.
|
•
|
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 global 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 rigs, 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 of, or damage to, gathering, processing, compression and transportation facilities and equipment and other facilities and equipment utilized in support of our crude oil, natural gas and NGL operations;
|
•
|
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; and
|
•
|
spills, leaks or discharges of fluids used in or produced in the course of operations, especially those that reach surface water or groundwater.
|
•
|
hurricanes, tropical storms, cyclones, windstorms, or “superstorms” which could affect our operations in areas such as Texas and the Gulf of Mexico;
|
•
|
winter storms and snow which could affect our operations in the DJ Basin;
|
•
|
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 and Texas;
|
•
|
harsh weather and rough seas offshore certain international locations, which could limit exploration activities; and
|
•
|
other natural disasters.
|
•
|
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 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.
|
|
|
High
|
|
Low
|
|
Dividends Per Share
|
||||||
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
|
|
|||
2017
|
|
|
|
|
|
|
||||||
First Quarter
|
|
$
|
40.89
|
|
|
$
|
32.33
|
|
|
$
|
0.10
|
|
Second Quarter
|
|
35.74
|
|
|
27.66
|
|
|
0.10
|
|
|||
Third Quarter
|
|
30.06
|
|
|
22.99
|
|
|
0.10
|
|
|||
Fourth Quarter
|
|
29.58
|
|
|
22.99
|
|
|
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)
|
|||||
10/1/2017 - 10/31/2017
|
|
390
|
|
|
$
|
28.33
|
|
|
—
|
|
|
—
|
|
11/1/2017 - 11/30/2017
|
|
85
|
|
|
28.30
|
|
|
—
|
|
|
—
|
|
|
12/1/2017 - 12/31/2017
|
|
20,173
|
|
|
25.68
|
|
|
—
|
|
|
—
|
|
|
Total
|
|
20,648
|
|
|
$
|
25.74
|
|
|
—
|
|
|
—
|
|
Year Ended December 31,
|
2013
|
2014
|
2015
|
2016
|
2017
|
||||||||||
Noble Energy, Inc.
|
$
|
135.07
|
|
$
|
95.06
|
|
$
|
67.16
|
|
$
|
78.54
|
|
$
|
60.93
|
|
S&P 500
|
132.39
|
|
150.51
|
|
152.59
|
|
170.84
|
|
208.14
|
|
|||||
Peer Group
|
131.72
|
|
113.35
|
|
70.13
|
|
101.33
|
|
90.55
|
|
|
|
Year Ended December 31,
|
||||||||||||||||||
(millions, except as noted)
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
||||||||||
Revenues and Income
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total Revenues
|
|
$
|
4,256
|
|
|
$
|
3,491
|
|
|
$
|
3,183
|
|
|
$
|
5,115
|
|
|
$
|
5,015
|
|
(Loss) Income from Continuing Operations Including Noncontrolling Interests
|
|
(1,050
|
)
|
|
(985
|
)
|
|
(2,441
|
)
|
|
1,214
|
|
|
907
|
|
|||||
Net (Loss) Income Including Noncontrolling Interests
|
|
(1,050
|
)
|
|
(985
|
)
|
|
(2,441
|
)
|
|
1,214
|
|
|
978
|
|
|||||
Net (Loss) Income Attributable to Noble Energy
|
|
(1,118
|
)
|
|
(998
|
)
|
|
(2,441
|
)
|
|
1,214
|
|
|
978
|
|
|||||
Per Share Data, Attributable to Noble Energy
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
(Loss) Earnings Per Share - Basic
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
(Loss) Income from Continuing Operations
|
|
$
|
(2.38
|
)
|
|
$
|
(2.32
|
)
|
|
$
|
(6.07
|
)
|
|
$
|
3.36
|
|
|
$
|
2.53
|
|
(Loss) Earnings Per Share - Basic
|
|
(2.38
|
)
|
|
(2.32
|
)
|
|
(6.07
|
)
|
|
3.36
|
|
|
2.72
|
|
|||||
(Loss) Earnings Per Share - Diluted
|
|
|
|
|
|
|
|
|
|
|
||||||||||
(Loss) Income from Continuing Operations
|
|
(2.38
|
)
|
|
(2.32
|
)
|
|
(6.07
|
)
|
|
3.27
|
|
|
2.50
|
|
|||||
(Loss) Earnings Per Share - Diluted
|
|
(2.38
|
)
|
|
(2.32
|
)
|
|
(6.07
|
)
|
|
3.27
|
|
|
2.69
|
|
|||||
Cash Dividends Per Share
|
|
0.40
|
|
|
0.40
|
|
|
0.72
|
|
|
0.68
|
|
|
0.55
|
|
|||||
Year-End Stock Price Per Share
|
|
29.14
|
|
|
38.06
|
|
|
32.93
|
|
|
47.43
|
|
|
68.11
|
|
|||||
Weighted Average Shares Outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Basic
|
|
469
|
|
|
430
|
|
|
402
|
|
|
361
|
|
|
359
|
|
|||||
Diluted
|
|
469
|
|
|
430
|
|
|
402
|
|
|
367
|
|
|
363
|
|
|||||
Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Net Cash Provided by Operating Activities
|
|
$
|
1,951
|
|
|
$
|
1,351
|
|
|
$
|
2,062
|
|
|
$
|
3,506
|
|
|
$
|
2,937
|
|
Additions to Property, Plant and Equipment
|
|
2,649
|
|
|
1,541
|
|
|
2,979
|
|
|
4,871
|
|
|
3,947
|
|
|||||
Proceeds from Divestitures
(1)
|
|
2,073
|
|
|
1,241
|
|
|
151
|
|
|
321
|
|
|
327
|
|
|||||
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
|
|
312
|
|
|
299
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Financial Position
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Cash and Cash Equivalents
|
|
$
|
675
|
|
|
$
|
1,180
|
|
|
$
|
1,028
|
|
|
$
|
1,183
|
|
|
$
|
1,117
|
|
Property, Plant, and Equipment, Net
|
|
17,502
|
|
|
18,548
|
|
|
21,300
|
|
|
18,143
|
|
|
15,725
|
|
|||||
Goodwill
(2)
|
|
1,310
|
|
|
—
|
|
|
—
|
|
|
620
|
|
|
627
|
|
|||||
Total Assets
|
|
21,476
|
|
|
21,011
|
|
|
24,196
|
|
|
22,518
|
|
|
19,642
|
|
|||||
Long-term Obligations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Long-Term Debt
|
|
6,746
|
|
|
7,011
|
|
|
7,976
|
|
|
6,068
|
|
|
4,566
|
|
|||||
Deferred Income Taxes
|
|
1,127
|
|
|
1,819
|
|
|
2,826
|
|
|
2,516
|
|
|
2,441
|
|
|||||
Asset Retirement Obligations, Noncurrent
|
|
824
|
|
|
775
|
|
|
861
|
|
|
670
|
|
|
547
|
|
|||||
Other
|
|
421
|
|
|
328
|
|
|
358
|
|
|
417
|
|
|
562
|
|
|||||
Total Equity
|
|
10,619
|
|
|
9,600
|
|
|
10,370
|
|
|
10,325
|
|
|
9,184
|
|
(1)
|
Proceeds for 2017 relate to the Marcellus Shale upstream divestiture and proceeds received from other transactions. Proceeds for 2016 primarily relate to US onshore non-strategic asset divestiture activity and the sell-down of Tamar interest. See
Item 8. Financial Statements and Supplementary Data –
Note 4. Acquisitions, Divestitures and Merger
|
(2)
|
Goodwill at December 31, 2017 related to the Clayton Williams Energy Acquisition. Our previous goodwill balance 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,
|
||||||||||||||||||
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
||||||||||
Operations Information - Consolidated Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Consolidated Crude Oil Sales (MBbl/d)
|
|
129
|
|
|
125
|
|
|
112
|
|
|
103
|
|
|
99
|
|
|||||
Average Realized Price ($/Bbl)
|
|
$
|
49.73
|
|
|
$
|
40.39
|
|
|
$
|
45.00
|
|
|
$
|
91.58
|
|
|
$
|
100.29
|
|
Consolidated NGL Sales (MBbl/d)
|
|
58
|
|
|
54
|
|
|
39
|
|
|
23
|
|
|
16
|
|
|||||
Average Realized Price ($/Bbl)
|
|
$
|
23.40
|
|
|
$
|
14.92
|
|
|
$
|
13.91
|
|
|
$
|
33.75
|
|
|
$
|
35.53
|
|
Consolidated Natural Gas Sales (MMcf/d)
|
|
1,118
|
|
|
1,397
|
|
|
1,187
|
|
|
992
|
|
|
901
|
|
|||||
Average Realized Price ($/Mcf)
|
|
$
|
3.01
|
|
|
$
|
2.42
|
|
|
$
|
2.44
|
|
|
$
|
3.38
|
|
|
$
|
2.97
|
|
Proved Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Crude Oil and Condensate Reserves (MMBbls)
|
|
457
|
|
|
333
|
|
|
307
|
|
|
304
|
|
|
322
|
|
|||||
NGL Reserves (MMBbls)
|
|
229
|
|
|
219
|
|
|
189
|
|
|
128
|
|
|
113
|
|
|||||
Natural Gas Reserves (Bcf)
|
|
7,680
|
|
|
5,308
|
|
|
5,549
|
|
|
5,833
|
|
|
5,828
|
|
|||||
Total Reserves (MMBoe)
|
|
1,965
|
|
|
1,437
|
|
|
1,421
|
|
|
1,404
|
|
|
1,406
|
|
|||||
Number of Employees
|
|
2,277
|
|
|
2,274
|
|
|
2,395
|
|
|
2,735
|
|
|
2,527
|
|
•
|
•
|
•
|
•
|
•
|
•
|
•
|
•
|
|
|
|
|
|
|
•
|
entered the liquids-rich Eagle Ford Shale and Delaware Basin through the Rosetta Merger;
|
•
|
expanded our Delaware Basin position through the Clayton Williams Energy Acquisition;
|
•
|
exited the Marcellus Shale upstream and are exiting the Marcellus Shale midstream, thereby accelerating monetization of assets not attracting capital;
|
•
|
established the Noble Midstream business, including an initial public offering of Noble Midstream Partners, and executed the first asset drop down transaction; and
|
•
|
accelerated DJ Basin value through numerous acreage exchanges and sales.
|
•
|
focused capital and resources on highest-margin assets within US onshore liquids plays and the Eastern Mediterranean;
|
•
|
sanctioned the initial phase of Leviathan development, with first natural gas sales targeted for the end of 2019;
|
•
|
excluding the impact of the Marcellus Shale upstream divestiture, increased proved reserves by more than 65% from 2016;
|
•
|
excluding the impact of the Marcellus Shale upstream divestiture, increased total US onshore sales volumes by more than 15% from 2016 and shifted to an oilier production mix, with more than 40% of our US onshore consolidated sales volumes attributable to crude oil; and
|
•
|
improved well level and corporate returns with technology advancements and structural cost savings.
|
•
|
proactive and strategic action to manage within cash flows;
|
•
|
made net repayments of debt totaling
$1.69 billion
, since beginning of 2016 through cash on hand, proceeds from asset sales, and cash generated by our midstream business;
|
•
|
maintained a strong liquidity position including cash on hand and unused borrowing capacity; and
|
•
|
maintained our investment grade credit ratings.
|
•
|
Execution of a disciplined capital allocation process by:
|
◦
|
designing a flexible investment program aligned with the current commodity price environment; and
|
◦
|
maintaining a strong balance sheet and liquidity position.
|
•
|
Enhancing capital efficiencies through:
|
◦
|
utilizing our technical competencies and applying historical learnings from unconventional US shale plays to reduce US onshore finding and development costs; and
|
◦
|
driving Delaware Basin economics through development cycle efficiencies.
|
•
|
Leveraging the benefits of our well-positioned and diversified portfolio including:
|
◦
|
exercising investment optionality and flexibility afforded by our assets, which are largely held by production; and
|
◦
|
continuing portfolio optimization actions to maximize strategic value.
|
•
|
Capitalizing on a currently low-cost offshore environment with execution of high-quality, long-cycle development projects, such as:
|
◦
|
progressing Leviathan field development.
|
•
|
Maintaining financial strength through:
|
◦
|
focusing operational activities on high-margin, high-return assets;
|
◦
|
improving overall corporate returns; and
|
◦
|
ensuring cash flow sources and uses remain balanced.
|
•
|
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;
|
•
|
increased drilling activity, which may cause US onshore cost inflation pressure and result in certain current production becoming less profitable or uneconomic;
|
•
|
Israeli industrial and residential demand for electricity, which is largely impacted by weather conditions and the conversion of Israel's electricity portfolio from coal to natural gas;
|
•
|
timing of the divestiture of the remaining 7.5% working interest in the Tamar and Dalit fields, in accordance with the Framework, which will leave us with a 25% working interest and will accelerate value realization, but lower our forward sales volumes;
|
•
|
timing of crude oil and condensate liftings impacting sales volumes in West Africa;
|
•
|
natural field decline in US onshore, Gulf of Mexico and offshore Equatorial Guinea;
|
•
|
additional purchases of producing properties or divestments of operating assets;
|
•
|
potential weather-related volume curtailments due to hurricanes in the Gulf of Mexico and Gulf Coast areas, or winter storms and flooding impacting US onshore operations;
|
•
|
availability or reliability of supplier services, including access to support equipment and facilities, occurrence of pipeline disruptions, and/or potential pipeline and processing facility capacity constraints, which may cause delays, restrictions or interruptions in production and/or midstream processing;
|
•
|
timing and completion of midstream expansion projects by Noble Midstream Partners in areas that provide services to our assets;
|
•
|
malfunctions and/or mechanical failures at terminals or other US onshore delivery points;
|
•
|
impact of enhanced completion efforts for US onshore assets;
|
•
|
potential growth from participation in future, or decline from existing, non-operated wells;
|
•
|
abandonment of low-margin US onshore wells;
|
•
|
shut-in of US producing properties if storage capacity becomes unavailable; and
|
•
|
potential drilling and/or completion permit delays due to future regulatory changes.
|
•
|
commodity prices, including price realizations on specific crude oil, natural gas and NGL production;
|
•
|
operating and development costs;
|
•
|
production, drilling and delivery commitments, or other contractual obligations;
|
•
|
drilling results;
|
•
|
property acquisitions and divestitures;
|
•
|
exploration activity;
|
•
|
cash flows from operations, including cash flows from potential midstream drop-down transactions;
|
•
|
indebtedness levels;
|
•
|
availability of financing or other sources of funding;
|
•
|
impact of new laws and regulations on our business practices, including potential legislative or regulatory changes regarding the use of hydraulic fracturing; and
|
•
|
potential changes in the fiscal regimes of the US and other countries in which we operate.
|
•
|
Exploration Activities and Unproved Properties
We may impair and/or relinquish certain undeveloped leases prior to expiration based upon changes in exploration plans, timing and extent of development activities, availability of capital and suitable rig and drilling equipment, resource potential, comparative economics, changing regulations and/or other factors. In addition, in the event we conclude that an exploratory well did not encounter hydrocarbons or that a discovery or prospect is not economically or operationally viable, the associated capitalized exploratory well costs would be charged to expense.
|
•
|
Development Concept Selection Costs
We may write-off costs related to certain development concepts, including costs of related pre-FEED and FEED studies, associated with significant offshore projects, particularly those in remote or under-developed areas, when such development concepts are eliminated from further consideration based on the
|
•
|
Producing Properties
We may impair a proved property based on a decrease in forward commodity prices, or widening of basis differentials, or an increase in abandonment costs, among other factors.
|
•
|
Divestments
We may periodically divest certain assets to reposition our portfolio. When properties meet the criteria for reclassification as assets held for sale, they are valued at the lower of net book value or anticipated sales proceeds less transaction-related costs to sell. Impairment expense would be recorded for any excess of net book value over anticipated sales proceeds less transaction-related costs to sell. In addition, a further loss, which could be material, could occur upon closing of a sales transaction.
|
•
|
total average daily sales volumes of
381
MBoe/d;
|
•
|
record average daily sales volumes for US onshore crude oil of
90
MBbl/d; and
|
•
|
average daily sales volumes for natural gas of
272
MMcf/d, net, in Israel, and an all-time record for full year average daily gross sales volumes for natural gas of 956 MMcfe/d, primarily from the Tamar field.
|
•
|
average realized crude oil price increase of
23%
as compared to 2016;
|
•
|
average realized NGL price increase of
56%
as compared to 2016;
|
•
|
average realized natural gas price increase of
24%
as compared to 2016;
|
•
|
pre-tax loss of
$1.8 billion
, as compared with pre-tax loss of
$1.3 billion
for 2016; and
|
•
|
capital expenditures of
$2.4 billion
, excluding acquisitions, as compared with
$1.2 billion
for
2016
.
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
2017
|
|
2016
|
|
2015
|
||||||
Oil, NGL and Gas Sales to Third Parties
|
$
|
4,060
|
|
|
$
|
3,389
|
|
|
$
|
3,093
|
|
Income from Equity Method Investees
|
120
|
|
|
50
|
|
|
39
|
|
|||
Total Revenues
|
4,180
|
|
|
3,439
|
|
|
3,132
|
|
|||
Production Expense
|
1,270
|
|
|
1,200
|
|
|
1,067
|
|
|||
Exploration Expense
|
188
|
|
|
925
|
|
|
488
|
|
|||
Depreciation, Depletion and Amortization
|
1,965
|
|
|
2,395
|
|
|
2,073
|
|
|||
Loss on Marcellus Shale Upstream Divestiture
(1)
|
2,379
|
|
|
—
|
|
|
—
|
|
|||
Asset Impairments
(2)
|
70
|
|
|
92
|
|
|
533
|
|
|||
(Gain) Loss on Commodity Derivative Instruments
|
(63
|
)
|
|
139
|
|
|
(501
|
)
|
|||
Goodwill Impairment
|
—
|
|
|
—
|
|
|
779
|
|
|||
Clayton Williams Energy Acquisition Expenses
(3)
|
100
|
|
|
—
|
|
|
—
|
|
|||
Income (Loss) Before Income Taxes
|
(1,803
|
)
|
|
(1,271
|
)
|
|
(1,699
|
)
|
(1)
|
See Item 8. Financial Statements and Supplementary Data –
Note
4. Acquisitions, Divestitures and Merger
.
|
(2)
|
See Item 8. Financial Statements and Supplementary Data –
Note
5. Asset Impairments
.
|
(3)
|
See Item 8. Financial Statements and Supplementary Data –
Note
3. Clayton Williams Energy Acquisition
.
|
|
Sales Volumes
|
|
Average Realized Sales Prices
|
||||||||||||||||||||
|
Crude Oil & Condensate
(MBbl/d)
|
|
NGLs
(MBbl/d) |
|
Natural Gas (MMcf/d)
|
|
Total
(MBoe/d)
(1)
|
|
Crude Oil & Condensate
(Per Bbl)
|
|
NGLs (Per Bbl)
|
|
Natural
Gas (Per Mcf) |
||||||||||
Year Ended December 31, 2017
|
|||||||||||||||||||||||
United States
|
111
|
|
|
58
|
|
|
607
|
|
|
270
|
|
|
$
|
49.11
|
|
|
$
|
23.40
|
|
|
$
|
3.02
|
|
Israel
|
—
|
|
|
—
|
|
|
272
|
|
|
46
|
|
|
—
|
|
|
—
|
|
|
5.32
|
|
|||
Equatorial Guinea
(2)
|
18
|
|
|
—
|
|
|
239
|
|
|
57
|
|
|
53.68
|
|
|
—
|
|
|
0.27
|
|
|||
Total Consolidated Operations
|
129
|
|
|
58
|
|
|
1,118
|
|
|
373
|
|
|
49.73
|
|
|
23.40
|
|
|
3.01
|
|
|||
Equity Investee
(3)
|
2
|
|
|
6
|
|
|
—
|
|
|
8
|
|
|
55.13
|
|
|
38.48
|
|
|
—
|
|
|||
Total
|
131
|
|
|
64
|
|
|
1,118
|
|
|
381
|
|
|
$
|
49.84
|
|
|
$
|
24.81
|
|
|
$
|
3.01
|
|
Year Ended December 31, 2016
|
|||||||||||||||||||||||
United States
|
99
|
|
|
54
|
|
|
881
|
|
|
301
|
|
|
$
|
39.59
|
|
|
$
|
14.92
|
|
|
$
|
2.11
|
|
Israel
|
—
|
|
|
—
|
|
|
281
|
|
|
47
|
|
|
—
|
|
|
—
|
|
|
5.21
|
|
|||
Equatorial Guinea
(2)
|
26
|
|
|
—
|
|
|
235
|
|
|
65
|
|
|
43.54
|
|
|
—
|
|
|
0.27
|
|
|||
Total Consolidated Operations
|
125
|
|
|
54
|
|
|
1,397
|
|
|
413
|
|
|
40.39
|
|
|
14.92
|
|
|
2.42
|
|
|||
Equity Investee
(3)
|
2
|
|
|
5
|
|
|
—
|
|
|
7
|
|
|
45.44
|
|
|
26.30
|
|
|
—
|
|
|||
Total
|
127
|
|
|
59
|
|
|
1,397
|
|
|
420
|
|
|
$
|
40.46
|
|
|
$
|
15.96
|
|
|
$
|
2.42
|
|
Year Ended December 31, 2015
|
|||||||||||||||||||||||
United States
|
81
|
|
|
39
|
|
|
708
|
|
|
237
|
|
|
$
|
43.46
|
|
|
$
|
13.91
|
|
|
$
|
2.10
|
|
Israel
|
—
|
|
|
—
|
|
|
252
|
|
|
42
|
|
|
—
|
|
|
—
|
|
|
5.34
|
|
|||
Equatorial Guinea
(2)
|
31
|
|
|
—
|
|
|
227
|
|
|
69
|
|
|
48.85
|
|
|
—
|
|
|
0.27
|
|
|||
Total Consolidated Operations
|
112
|
|
|
39
|
|
|
1,187
|
|
|
348
|
|
|
45.00
|
|
|
13.91
|
|
|
2.44
|
|
|||
Equity Investee
(3)
|
2
|
|
|
5
|
|
|
—
|
|
|
7
|
|
|
48.85
|
|
|
28.40
|
|
|
—
|
|
|||
Total
|
114
|
|
|
44
|
|
|
1,187
|
|
|
355
|
|
|
$
|
45.05
|
|
|
$
|
15.59
|
|
|
$
|
2.44
|
|
(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 US natural gas and NGLs is significantly less than the price for a barrel of crude oil. In Israel, we sell natural gas under contracts where the majority of the price is fixed, resulting in less commodity price disparity.
|
(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 Alba Plant in Equatorial Guinea.
|
|
|
Crude Oil &
Condensate
|
|
NGLs
|
|
Natural
Gas
|
|
Total
|
||||||||
(millions)
|
|
|
|
|
|
|
|
|
||||||||
2015 Sales Revenues
|
|
$
|
1,840
|
|
|
$
|
197
|
|
|
$
|
1,056
|
|
|
$
|
3,093
|
|
Changes due to
|
|
|
|
|
|
|
|
|
||||||||
Increase in Sales Volumes
|
|
153
|
|
|
84
|
|
|
190
|
|
|
427
|
|
||||
(Decrease) Increase in Sales Prices
|
|
(139
|
)
|
|
15
|
|
|
(7
|
)
|
|
(131
|
)
|
||||
2016 Sales Revenues
|
|
$
|
1,854
|
|
|
$
|
296
|
|
|
$
|
1,239
|
|
|
$
|
3,389
|
|
Changes due to
|
|
|
|
|
|
|
|
|
||||||||
Increase (Decrease) in Sales Volumes
|
|
55
|
|
|
17
|
|
|
(182
|
)
|
|
(110
|
)
|
||||
Increase in Sales Prices
|
|
437
|
|
|
180
|
|
|
164
|
|
|
781
|
|
||||
2017 Sales Revenues
|
|
$
|
2,346
|
|
|
$
|
493
|
|
|
$
|
1,221
|
|
|
$
|
4,060
|
|
•
|
23%
increase in average realized prices due to the partial rebalancing of global supply and demand factors;
|
•
|
higher US onshore sales volumes of 16 MBbl/d, including 5 MBbl/d contributed by recently acquired Clayton Williams Energy assets, primarily attributable to increased development and enhanced well design and completion techniques; and
|
•
|
higher sales volumes of 2 MBbl/d due to full year of production at Gunflint, a Gulf of Mexico project that started production in July 2016;
|
•
|
lower sales volumes of 14 MBbl/d primarily due to natural field decline in the Gulf of Mexico and Equatorial Guinea.
|
•
|
higher sales volumes of 9 MBbl/d in the Eagle Ford Shale and Delaware Basin, primarily attributable to full year consolidation following the Rosetta Merger;
|
•
|
sales volumes from the Big Bend and Dantzler developments (Gulf of Mexico), which began producing fourth quarter 2015 and contributed 12 MBbl/d, net, collectively in 2016; and
|
•
|
sales volume from the start up of the Gulf of Mexico Gunflint development in July 2016 which contributed 3 MBbl/d;
|
•
|
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 the Aseng and Alen fields, offshore Equatorial Guinea.
|
•
|
56%
increase in average realized prices due to the partial rebalancing of global supply and demand factors; and
|
•
|
higher US onshore sales volumes of 7 MBbl/d, including 1 MBbl/d contributed by recently acquired Clayton Williams Energy assets, primarily attributable to increased development and enhanced well design and completion techniques;
|
•
|
lower sales volumes of 4 MBbl/d due to the divestiture of the Marcellus Shale upstream assets in second quarter 2017.
|
•
|
higher sales volumes of 14 MBbl/d in the Eagle Ford Shale and Delaware Basin, primarily attributable to a full year of production as well as increased development activity;
|
•
|
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.
|
•
|
lower sales volumes of 312 MMcf/d due to the divestiture of the Marcellus Shale upstream assets in second quarter 2017; and
|
•
|
lower sales volumes of 29 MMcf/d as a result of the sale of a 3.5% working interest in the Tamar field, offshore Israel, in December 2016, partially offset by higher gross sales volumes from the field;
|
•
|
24%
increase in average realized prices due to the partial rebalancing of global supply and demand factors; and
|
•
|
higher US onshore sales volumes of 40 MMcf/d, including 6 MMcf/d contributed by recently acquired Clayton Williams Energy assets.
|
•
|
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 Delaware 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.
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
Net Income (in millions)
|
|
|
|
|
|
|
||||||
AMPCO and Affiliates
|
|
$
|
58
|
|
|
$
|
16
|
|
|
$
|
8
|
|
Alba Plant
|
|
65
|
|
|
34
|
|
|
31
|
|
|||
Dividends (in millions)
|
|
|
|
|
|
|
||||||
AMPCO and Affiliates
|
|
47
|
|
|
16
|
|
|
31
|
|
|||
Alba Plant
|
|
68
|
|
|
40
|
|
|
29
|
|
|||
Sales Volumes
|
|
|
|
|
|
|
||||||
Methanol (MMgal)
|
|
163
|
|
|
162
|
|
|
117
|
|
|||
Condensate (MBbl/d)
|
|
2
|
|
|
2
|
|
|
2
|
|
|||
LPG (MBbl/d)
|
|
6
|
|
|
5
|
|
|
5
|
|
|||
Average Realized Prices
|
|
|
|
|
|
|
||||||
Methanol (per gallon)
|
|
$
|
0.97
|
|
|
$
|
0.63
|
|
|
$
|
0.92
|
|
Condensate (per Bbl)
|
|
55.13
|
|
|
45.44
|
|
|
48.85
|
|
|||
LPG (per Bbl)
|
|
38.48
|
|
|
26.30
|
|
|
28.40
|
|
•
|
net income from AMPCO and affiliates increased primarily due to higher realized methanol prices; and
|
•
|
net income from Alba Plant increased primarily due to higher LPG sales volumes and higher realized commodity prices.
|
•
|
net income from AMPCO and affiliates increased in 2016 as compared with 2015 primarily due to higher methanol sales volumes, partially offset by lower methanol prices; and
|
•
|
net income from Alba Plant remained relatively flat.
|
(millions, except unit rate)
|
Total per BOE
(1)
|
|
Total
|
|
United
States
(1)
|
|
Israel
|
|
Equatorial Guinea
|
|
Other Int'l
(2)
|
||||||||||||
Year Ended December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Lease Operating Expense
(3)
|
$
|
4.29
|
|
|
$
|
585
|
|
|
$
|
466
|
|
|
$
|
29
|
|
|
$
|
90
|
|
|
$
|
—
|
|
Production and Ad Valorem Taxes
|
0.99
|
|
|
135
|
|
|
135
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Gathering, Transportation and Processing Expense
|
4.04
|
|
|
550
|
|
|
550
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total Production Expense
|
$
|
9.32
|
|
|
$
|
1,270
|
|
|
$
|
1,151
|
|
|
$
|
29
|
|
|
$
|
90
|
|
|
$
|
—
|
|
Total Production Expense per BOE
|
|
|
$
|
9.32
|
|
|
$
|
11.68
|
|
|
$
|
1.74
|
|
|
$
|
4.28
|
|
|
$
|
—
|
|
||
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Lease Operating Expense
(3)
|
$
|
3.72
|
|
|
$
|
560
|
|
|
$
|
418
|
|
|
$
|
37
|
|
|
$
|
105
|
|
|
$
|
—
|
|
Production and Ad Valorem Taxes
|
0.50
|
|
|
76
|
|
|
76
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Gathering, Transportation and Processing Expense
|
3.73
|
|
|
564
|
|
|
564
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total Production Expense
|
$
|
7.95
|
|
|
$
|
1,200
|
|
|
$
|
1,058
|
|
|
$
|
37
|
|
|
$
|
105
|
|
|
$
|
—
|
|
Total Production Expense per BOE
|
|
|
$
|
7.95
|
|
|
$
|
9.63
|
|
|
$
|
2.14
|
|
|
$
|
4.42
|
|
|
$
|
—
|
|
||
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Lease Operating Expense
(3)
|
$
|
4.52
|
|
|
$
|
575
|
|
|
$
|
398
|
|
|
$
|
42
|
|
|
$
|
131
|
|
|
$
|
4
|
|
Production and Ad Valorem Taxes
|
0.99
|
|
|
126
|
|
|
126
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Gathering, Transportation and Processing Expense
|
2.88
|
|
|
366
|
|
|
366
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total Production Expense
|
$
|
8.39
|
|
|
$
|
1,067
|
|
|
$
|
890
|
|
|
$
|
42
|
|
|
$
|
131
|
|
|
$
|
4
|
|
Total Production Expense per BOE
|
|
|
$
|
8.39
|
|
|
$
|
10.29
|
|
|
$
|
2.72
|
|
|
$
|
5.21
|
|
|
N/M
|
|
(1)
|
United States upstream production expense includes charges from our midstream operations that are eliminated on a consolidated basis. See
Item 1. Financial Statements – Note
15. Concentration of Risk
.
|
(2)
|
Other International includes the North Sea in 2015.
|
(3)
|
Lease operating expense includes oil and gas operating costs (labor, fuel, repairs, replacements, saltwater disposal and other related lifting costs) and workover expense.
|
•
|
increase of $82 million in US onshore, primarily in the DJ Basin, Delaware Basin and Eagle Ford Shale due to increased activity;
|
•
|
decrease of $19 million due to natural field decline in the Gulf of Mexico;
|
•
|
decrease of $17 million related to the divestiture of the Marcellus Shale upstream assets in second quarter 2017;
|
•
|
decrease of $15 million due to various cost reduction initiatives offshore West Africa; and
|
•
|
decrease of $11 million due to a 3.5% lower working interest in the Tamar field, offshore Israel, following the partial divestiture in December 2016.
|
•
|
decrease of $92 million in US onshore, 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 US onshore and Gulf of Mexico development activities; and
|
•
|
increase of $38 million related to the acquisition of Eagle Ford Shale and Delaware Basin production third quarter 2015.
|
•
|
decrease of $120 million related to the divestiture of the Marcellus Shale upstream assets in second quarter 2017;
|
•
|
increase of $57 million in the DJ Basin due to the shifting of crude oil volumes onto a new export pipeline and contractual increases of pipeline fees; and
|
•
|
increase of $47 million related to higher production in the Delaware Basin and Eagle Ford Shale.
|
•
|
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 new Gulf of Mexico projects at Big Bend and Dantzler (which began producing fourth quarter 2015) and Gunflint (which began producing in July 2016).
|
(millions)
|
Total
|
|
United States
|
|
Eastern Mediter-ranean
(1)
|
|
West
Africa
(2)
|
|
Other Int'l
(3)
|
||||||||||
Year Ended December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Leasehold Impairment and Amortization
|
$
|
62
|
|
|
$
|
60
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2
|
|
Dry Hole Cost
(4)
|
9
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9
|
|
|||||
Seismic, Geological and Geophysical
|
27
|
|
|
8
|
|
|
—
|
|
|
—
|
|
|
19
|
|
|||||
Staff Expense
|
55
|
|
|
1
|
|
|
2
|
|
|
4
|
|
|
48
|
|
|||||
Other
(5)
|
35
|
|
|
33
|
|
|
—
|
|
|
1
|
|
|
1
|
|
|||||
Total Exploration Expense
|
$
|
188
|
|
|
$
|
102
|
|
|
$
|
2
|
|
|
$
|
5
|
|
|
$
|
79
|
|
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
(4)
|
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
|
|
(1)
|
Eastern Mediterranean includes Israel and Cyprus.
|
(2)
|
West Africa includes Equatorial Guinea, Cameroon and Gabon.
|
(3)
|
Other International includes Newfoundland, Suriname and other new ventures.
|
(4)
|
For a discussion of 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 and Undeveloped Leasehold Costs
.
|
(5)
|
Includes lease rental and other exploration expense.
|
•
|
leasehold impairment expense related primarily to Gulf of Mexico unproved properties; and
|
•
|
dry hole cost of $7 million for the Araku-1 exploration well, offshore Suriname.
|
•
|
leasehold impairment expense including the write-off of leases and licenses of $58 million for the Gulf of Mexico, $25 million for other international locations, and $10 million for other US onshore; and
|
•
|
dry hole cost including costs related to the Silvergate exploratory well, Gulf of Mexico, the Dolphin 1 natural gas discovery, offshore Israel, and certain discoveries offshore West Africa.
|
•
|
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; and
|
•
|
dry hole cost including the Cheetah well, offshore West Africa, and Other International dry hole cost.
|
(millions, except unit rate)
|
Total
|
|
United
States |
|
Eastern
Mediter- ranean |
|
West
Africa |
|
Other Int'l
|
||||||||||
Twelve Months Ended December 31, 2017
|
|
|
|
|
|
|
|
|
|
||||||||||
DD&A Expense
|
$
|
1,965
|
|
|
$
|
1,739
|
|
|
$
|
76
|
|
|
$
|
146
|
|
|
$
|
4
|
|
Unit Rate per BOE
(1)
|
$
|
14.42
|
|
|
$
|
17.65
|
|
|
$
|
4.56
|
|
|
$
|
6.95
|
|
|
N/M
|
|
|
Twelve Months Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
||||||||||
DD&A Expense
|
$
|
2,395
|
|
|
$
|
2,103
|
|
|
$
|
81
|
|
|
$
|
205
|
|
|
$
|
6
|
|
Unit Rate per BOE
(1)
|
$
|
15.87
|
|
|
$
|
19.14
|
|
|
$
|
4.69
|
|
|
$
|
8.63
|
|
|
N/M
|
|
|
Twelve Months Ended December 31, 2015
|
|
|
|
|
|
|
|
|
|
||||||||||
DD&A Expense
|
$
|
2,073
|
|
|
$
|
1,677
|
|
|
$
|
70
|
|
|
$
|
326
|
|
|
$
|
—
|
|
Unit Rate per BOE
(1)
|
$
|
16.29
|
|
|
$
|
19.40
|
|
|
$
|
4.53
|
|
|
$
|
12.93
|
|
|
N/M
|
|
(1)
|
DD&A expense includes accretion of discount on asset retirement obligations of $
47 million
in
2017
, $
48 million
in
2016
, and $
43 million
in
2015
.
|
•
|
year-end reserve additions, primarily in US onshore due to enhanced well design and completion techniques in our horizontal drilling program and globally due to positive price revisions. For more information, see reserves discussion in
Supplemental Oil and Gas Information (Unaudited)
;
|
•
|
slightly lower sales volumes in the DJ Basin and the impact of certain property divestitures since the second quarter 2016;
|
•
|
the Marcellus Shale upstream divestiture in second quarter 2017, which reduced 2017 DD&A expense by $291 million;
|
•
|
the sale of a 3.5% working interest in the Tamar field, offshore Israel, in December 2016, which reduced 2017 DD&A expense by approximately $7 million;
|
•
|
a reduction in depletable costs of $153 million in the second quarter 2017 due to the reallocation of common asset costs from the Alen field, offshore Equatorial Guinea, to the West Africa natural gas monetization development project, which reduced 2017 DD&A expense by $37 million; and
|
•
|
lower sales volumes in the Gulf of Mexico due to natural field decline and reduction in the depletable costs due to downward revisions in estimates of asset retirement costs;
|
•
|
higher US onshore sales volumes of 29 MBoe/d during 2017, including 7 MBoe/d contributed by recently acquired Clayton Williams Energy assets;
|
•
|
an increase in sales volumes from the Gunflint development, Gulf of Mexico, which commenced production in July 2016; and
|
•
|
higher gross sales volumes from the Tamar field, offshore Israel, due to higher domestic demand.
|
•
|
increase of $178 million related to higher sales volumes resulting from commencement of production from the Big Bend, Dantzler and Gunflint development projects in the Gulf of Mexico in 2016 and 2015;
|
•
|
increase of $134 million related to the acquisition of Eagle Ford Shale and Delaware Basin production in 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, the Aseng and Alen fields, to a lower DD&A rate asset, the Alba field.
|
•
|
progressed the construction and development of multiple major projects in the DJ and Delaware Basins;
|
•
|
began providing crude oil and produced water gathering services to an unaffiliated third party;
|
•
|
entered into the Advantage Joint Venture; and
|
•
|
entered into the Black Diamond Gathering arrangement with definitive agreements to acquire the Saddle Butte system.
|
•
|
pre-tax income of
$233 million
, as compared with pre-tax income of
$176 million
for 2016; and
|
•
|
capital expenditures, excluding acquisitions, of
$399 million
compared with capital expenditures of
$42 million
for
2016
.
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
2017
|
|
2016
|
|
2015
|
||||||
Midstream Services Revenues – Third Party
|
$
|
19
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Income from Equity Method Investees
|
57
|
|
|
52
|
|
|
51
|
|
|||
Intersegment Revenues
|
277
|
|
|
200
|
|
|
119
|
|
|||
Total Revenues
|
353
|
|
|
252
|
|
|
170
|
|
|||
Gathering, Transportation and Processing Expense
|
70
|
|
|
44
|
|
|
25
|
|
|||
Depreciation, Depletion and Amortization
|
30
|
|
|
19
|
|
|
14
|
|
|||
Income Before Income Taxes
|
233
|
|
|
176
|
|
|
123
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
Net Income (in millions)
|
|
|
|
|
|
|
||||||
CONE Gathering and CONE Midstream
|
|
$
|
51
|
|
|
$
|
48
|
|
|
$
|
46
|
|
Advantage Pipeline
|
|
2
|
|
|
—
|
|
|
—
|
|
|||
White Cliffs
|
|
4
|
|
|
5
|
|
|
—
|
|
|||
Dividends (in millions)
|
|
|
|
|
|
|
||||||
CONE Gathering and CONE Midstream
|
|
25
|
|
|
27
|
|
|
17
|
|
•
|
an increase of $20 million in water services expense due to increased services provided by third parties as well as higher throughput volumes associated with fresh water services; and
|
•
|
an increase of $6 million in gathering and facilities operating expense due to higher gathered volumes, as well as due to new systems placed in service and expansion of the gathering infrastructure in 2017.
|
•
|
an increase of $12 million in water services expense due to an expanded scope of water services delivered; and
|
•
|
an increase of $7 million in gathering systems and facilities operating expense associated with higher gathered volumes as well as general repairs and maintenance of our gathering systems and facilities.
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
G&A Expense (millions)
|
$
|
415
|
|
|
$
|
399
|
|
|
$
|
396
|
|
Unit Rate per BOE
(1)
|
$
|
3.05
|
|
|
$
|
2.64
|
|
|
$
|
3.11
|
|
(1)
|
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.
|
|
|
Year Ended December 31,
|
||||||||||
(millions, except per unit)
|
|
2017
|
|
2016
|
|
2015
|
||||||
Interest Expense
|
|
$
|
403
|
|
|
$
|
412
|
|
|
$
|
407
|
|
Capitalized Interest
|
|
(49
|
)
|
|
(84
|
)
|
|
(144
|
)
|
|||
Interest Expense, Net
|
|
$
|
354
|
|
|
$
|
328
|
|
|
$
|
263
|
|
Unit Rate per BOE
(1)
|
|
$
|
2.60
|
|
|
$
|
2.17
|
|
|
$
|
2.07
|
|
(1)
|
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.
|
|
December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
(millions, except percentages)
|
|
|
|
|
|
|
|||||
Total Cash
(1)
|
$
|
713
|
|
|
$
|
1,209
|
|
|
$
|
1,028
|
|
Amount Available to be Borrowed Under Revolving Credit Facility
(2)
|
3,770
|
|
|
4,000
|
|
|
4,000
|
|
|||
Total Liquidity
|
$
|
4,483
|
|
|
$
|
5,209
|
|
|
$
|
5,028
|
|
Total Debt
(3)
|
$
|
6,859
|
|
|
$
|
7,114
|
|
|
$
|
7,976
|
|
Noble Energy Share of Equity
|
10,619
|
|
|
9,600
|
|
|
10,370
|
|
|||
Ratio of Debt-to-Book Capital
(4)
|
39
|
%
|
|
43
|
%
|
|
43
|
%
|
(1)
|
Total cash at December 31, 2017 includes
$18 million
cash of Noble Midstream Partners and $37.5 million restricted cash related to the Saddle Butte acquisition that closed in first quarter of 2018. Total cash at December 31, 2016 includes $57 million cash of Noble Midstream Partners, and restricted cash of $30 million related to the Delaware Basin property acquisition that closed in January 2017.
|
(2)
|
In 2017, amount available to be borrowed under the Revolving Credit Facility excludes
$265 million
and $625 million available to be borrowed under the Noble Midstream Services Revolving Credit Facility and Leviathan Term Loan Facility (defined below), respectively, which are not available to Noble Energy for general corporate purposes. In 2016, it excludes $350 million available to be borrowed under the Noble Midstream Services Revolving Credit Facility. See discussion 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.
Significant changes in our financial position impacting the ratio included
$255 million
net decrease in debt,
$1.9 billion
increase in shareholders' equity due to issuance of stock as part of consideration paid for Clayton Williams Energy Acquisition,
$312 million
increase due to issuance of Noble Midstream Partners Common Units and
$100 million
increase due to stock based compensation, offset by
$190 million
decrease in shareholders' equity from dividends paid and
$1.1 billion
decrease in shareholders' equity from current year net loss.
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
(millions)
|
|
|
|
|
|
|
||||||
Total Cash Provided By (Used in)
|
|
|
|
|
|
|
||||||
Operating Activities
|
|
$
|
1,951
|
|
|
$
|
1,351
|
|
|
$
|
2,062
|
|
Investing Activities
|
|
(1,606
|
)
|
|
(431
|
)
|
|
(2,871
|
)
|
|||
Financing Activities
|
|
(850
|
)
|
|
(768
|
)
|
|
654
|
|
|||
Increase (Decrease) in Cash and Cash Equivalents
|
|
$
|
(505
|
)
|
|
$
|
152
|
|
|
$
|
(155
|
)
|
•
|
$1.0 billion
from the Marcellus Shale upstream divestiture;
|
•
|
$568 million
on the sale of Greeley Crescent and Bronco acreage in the DJ Basin; and
|
•
|
$335 million
from the sale of mineral and royalty assets.
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
(millions)
|
|
|
|
|
|
|
||||||
Acquisition, Capital and Exploration Expenditures
|
|
|
|
|
|
|
|
|
||||
Unproved Property Acquisition
(1)
|
|
$
|
1,817
|
|
|
$
|
234
|
|
|
$
|
1,480
|
|
Proved Property Acquisition
(2)
|
|
839
|
|
|
—
|
|
|
1,613
|
|
|||
Exploration
|
|
42
|
|
|
222
|
|
|
322
|
|
|||
Development
|
|
2,310
|
|
|
1,017
|
|
|
2,055
|
|
|||
Midstream
(3)
|
|
480
|
|
|
42
|
|
|
356
|
|
|||
Corporate and Other
|
|
34
|
|
|
50
|
|
|
97
|
|
|||
Total
|
|
$
|
5,522
|
|
|
$
|
1,565
|
|
|
$
|
5,923
|
|
Other
|
|
|
|
|
|
|
|
|
||||
Investment in Equity Method Investee
(4)
|
|
$
|
68
|
|
|
$
|
8
|
|
|
$
|
104
|
|
Increase in Capital Lease Obligations
(5)
|
|
—
|
|
|
5
|
|
|
55
|
|
(1)
|
2017 costs include
$1.6
billion related to the Clayton Williams Energy Acquisition and $246 million related to the Delaware Basin asset acquisition.
|
(2)
|
2017 costs include
$722 million
of proved properties and
$63 million
of asset retirement obligations acquired in the Clayton Williams Energy Acquisition and $58 million related to the Delaware Basin asset acquisition.
|
(3)
|
2017 includes gathering and processing assets of
$48 million
related to the Clayton Williams Energy Acquisition.
|
(4)
|
2017 includes our contribution to the Advantage Joint Venture, in which Noble Midstream Partners owns a 50% interest.
|
(5)
|
Relates to US onshore assets.
|
Obligation
|
Note
Reference (1) |
Total
|
|
2018
|
|
2019 and 2020
|
|
2021 and 2022
|
|
2023 and beyond
|
||||||||||
(millions)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Long-Term Debt
(2)
|
$
|
6,586
|
|
|
$
|
—
|
|
|
$
|
230
|
|
|
$
|
1,464
|
|
|
$
|
4,892
|
|
|
Interest Payments
(3)
|
5,804
|
|
|
324
|
|
|
645
|
|
|
555
|
|
|
4,280
|
|
||||||
Capital Lease and Other Obligations
(4)
|
335
|
|
|
74
|
|
|
87
|
|
|
50
|
|
|
124
|
|
||||||
Drilling and Equipment Obligations
(5)
|
448
|
|
|
343
|
|
|
105
|
|
|
—
|
|
|
—
|
|
||||||
Purchase Obligations
(6)
|
448
|
|
|
293
|
|
|
101
|
|
|
22
|
|
|
32
|
|
||||||
Transportation and Gathering
(7)
|
2,474
|
|
|
215
|
|
|
499
|
|
|
405
|
|
|
1,355
|
|
||||||
Operating Lease Obligations
(8)
|
330
|
|
|
44
|
|
|
65
|
|
|
65
|
|
|
156
|
|
||||||
Other Liabilities
(9)
|
|
|
|
|
|
|
|
|
|
|||||||||||
Asset Retirement Obligations
(10)
|
875
|
|
|
51
|
|
|
267
|
|
|
99
|
|
|
458
|
|
||||||
Commodity Derivative Instruments
(11)
|
68
|
|
|
53
|
|
|
15
|
|
|
—
|
|
|
—
|
|
||||||
Total Contractual Obligations
|
|
$
|
17,368
|
|
|
$
|
1,397
|
|
|
$
|
2,014
|
|
|
$
|
2,660
|
|
|
$
|
11,297
|
|
(1)
|
References are to the Notes accompanying Item 8. Financial Statements and Supplementary Data.
|
(2)
|
Long-term debt excludes capital lease obligations and includes our fixed rate debt and revolving credit facilities balances based on the maturity dates of the facilities.
|
(3)
|
Interest payments are based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2017.
|
(4)
|
Annual capital lease payments, net to our interest, exclude regular maintenance and operational costs.
|
(5)
|
Drilling and equipment obligations represent our working interest share of contractual agreements with third-party service providers to procure drilling rigs and other related equipment for exploratory and development drilling activities. See Counterparty Credit Risk, above.
|
(6)
|
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.
|
(7)
|
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 and Firm Transportation Commitments
.
|
(8)
|
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.
|
(9)
|
The table excludes deferred compensation liabilities of
$197 million
as specific payment dates are unknown.
|
(10)
|
Asset retirement obligations are discounted.
|
(11)
|
Amount represents open commodity derivative instruments that were in a net payable position with the counterparty at December 31, 2017.
|
•
|
Acquisition costs - Costs associated with the purchase, lease or other costs to acquire mineral interests in crude oil and natural gas properties are initially capitalized as unproved property acquisition costs. These costs are commonly attributable to undeveloped leasehold costs or are derived from allocated fair values as a result of business combinations. Continued capitalization of these costs is dependent upon discovery of proved reserves. For example:
|
◦
|
If no proved reserves are discovered after exploration, drilling or lapse of the lease, then costs are impaired. As part of our periodic impairment review, we review undeveloped leasehold costs for potential impairment and if, based upon a change in exploration plans, timing and extent of development activities, availability of capital and suitable rig and drilling equipment, resource potential, comparative economics, changing regulations and/or other factors, an impairment is indicated, we will record impairment expense related to the respective lease.
|
◦
|
If proved reserves are discovered, the related acquisition costs are reclassified to proved properties. We assess proved crude oil and natural gas properties and other investments for possible impairment whenever events or circumstances indicate that the recorded carrying values of the assets may not be recoverable. We recognize an impairment loss as a result of an event that causes us to consider the possibility that impairment may have occurred and when the estimated undiscounted future net cash flows from a property or other investment are less than the carrying value.
|
•
|
Exploratory well costs - Costs associated with drilling an exploratory well may be capitalized temporarily, or “suspended,” pending a determination of whether crude oil or natural gas have been discovered and can be estimated with reasonable certainty to be economically producible. We carry the costs of an exploratory well as an asset if we have found a sufficient quantity of reserves to justify its completion as a producing well and as long as we are making sufficient progress assessing the reserves and the economic and operating viability of the project. For certain capital-intensive Gulf of Mexico or international projects, it may take several years to evaluate the future potential of the exploratory well and make a determination of its economic viability. Our ability to move forward on a project may be dependent on gaining access to transportation or processing facilities or obtaining permits and government or partner approval, the timing of which is beyond our control. In such cases, exploratory well costs remain suspended as long as
|
•
|
Development well costs - Costs associated with drilling a development well to obtain access to and to produce proved reserves are capitalized. Development well costs are included in our periodic proved property impairment test noted above.
|
•
|
Income Approach
Under the income approach, the fair value of the Texas reporting unit is estimated based on the present value of expected future cash flows. The income approach is dependent on a number of factors, including estimates of forecasted revenue and operating costs and proved reserves, as well as the success of future exploration for and development of unproved reserves, discount rates and other variables. Negative revisions of estimated reserves quantities, increases in future cost estimates, divestiture of a significant component of the reporting unit, or sustained decreases in crude oil or natural gas prices could lead to a reduction in expected future cash flows and possibly an impairment of all or a portion of goodwill in future periods. Key assumptions used in the discounted cash flow model described above include estimated quantities of crude oil, natural gas and NGL reserves, including both proved reserves and risk-adjusted unproved reserves; estimates of market prices considering forward commodity price curves as of the measurement date; and estimates of operating, administrative and capital costs adjusted for inflation. We discount the resulting future cash flows using a peer group based weighted average cost of capital.
|
•
|
Market Approach
Under the market approach, we estimate the fair value of the Texas reporting unit by comparison to similar businesses whose securities are actively traded in the public market The market approach requires management to make certain judgments about the selection of comparable companies and/or comparable recent company and asset transactions and transaction premiums, thereby creating a group of guideline public companies or transactions, or a peer group, that are engaged in similar operations with comparable risks and returns as our reporting unit.
|
•
|
the status of negotiations with counterparties regarding partial or permanent release of our contract commitments;
|
•
|
the status of FERC approval of prospective pipeline projects;
|
•
|
the timing of commercial availability of approved pipelines upon completion of construction; and
|
•
|
the likelihood of capacity utilization through purchase of third party gas, which would reduce unutilized volume commitments.
|
Consolidated Financial Statements of Noble Energy, Inc.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noble Energy, Inc.
|
|
|
|
/s/ KPMG LLP
|
|
|
|
|
|
|
|
We have served as the Company’s auditor since 2002.
|
||||
|
|
|
|
|
Houston, Texas
|
|
|
|
|
February 20, 2018
|
|
|
|
|
|
|
/s/ KPMG LLP
|
|
|
Houston, Texas
|
|
|
|
|
February 20, 2018
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
Revenues
|
|
|
|
|
|
||||||
Oil, Gas and NGL Sales
|
$
|
4,060
|
|
|
$
|
3,389
|
|
|
$
|
3,093
|
|
Income from Equity Method Investees and Other
|
196
|
|
|
102
|
|
|
90
|
|
|||
Total Revenues
|
4,256
|
|
|
3,491
|
|
|
3,183
|
|
|||
Costs and Expenses
|
|
|
|
|
|
||||||
Production Expense
|
1,141
|
|
|
1,100
|
|
|
996
|
|
|||
Exploration Expense
|
188
|
|
|
925
|
|
|
488
|
|
|||
Depreciation, Depletion and Amortization
|
2,053
|
|
|
2,454
|
|
|
2,131
|
|
|||
General and Administrative
|
415
|
|
|
399
|
|
|
396
|
|
|||
Loss on Marcellus Shale Upstream Divestiture
|
2,379
|
|
|
—
|
|
|
—
|
|
|||
Asset Impairments
|
70
|
|
|
92
|
|
|
533
|
|
|||
Goodwill Impairment
|
—
|
|
|
—
|
|
|
779
|
|
|||
Other Operating (Income) Expense, Net
|
(188
|
)
|
|
(103
|
)
|
|
332
|
|
|||
Total Operating Expenses
|
6,058
|
|
|
4,867
|
|
|
5,655
|
|
|||
Operating Loss
|
(1,802
|
)
|
|
(1,376
|
)
|
|
(2,472
|
)
|
|||
Other Expense (Income)
|
|
|
|
|
|
||||||
(Gain) Loss on Commodity Derivative Instruments
|
(63
|
)
|
|
139
|
|
|
(501
|
)
|
|||
Loss (Gain) on Extinguishment of Debt
|
98
|
|
|
(80
|
)
|
|
—
|
|
|||
Interest, Net of Amount Capitalized
|
354
|
|
|
328
|
|
|
263
|
|
|||
Other Non-Operating Expense (Income), Net
|
—
|
|
|
9
|
|
|
(15
|
)
|
|||
Total Other Expense (Income)
|
389
|
|
|
396
|
|
|
(253
|
)
|
|||
Loss Before Income Taxes
|
(2,191
|
)
|
|
(1,772
|
)
|
|
(2,219
|
)
|
|||
Income Tax (Benefit) Provision
|
(1,141
|
)
|
|
(787
|
)
|
|
222
|
|
|||
Net Loss Including Noncontrolling Interests
|
(1,050
|
)
|
|
(985
|
)
|
|
(2,441
|
)
|
|||
Less: Net Income Attributable to Noncontrolling Interests
|
68
|
|
|
13
|
|
|
—
|
|
|||
Net Loss Attributable to Noble Energy
|
$
|
(1,118
|
)
|
|
$
|
(998
|
)
|
|
$
|
(2,441
|
)
|
|
|
|
|
|
|
||||||
Net Loss Attributable to Noble Energy per Share of Common Stock
|
|
|
|
|
|
||||||
Basic and Diluted
|
$
|
(2.38
|
)
|
|
$
|
(2.32
|
)
|
|
$
|
(6.07
|
)
|
|
|
|
|
|
|
||||||
Weighted Average Number of Shares Outstanding
|
|
|
|
|
|
||||||
Basic and Diluted
|
469
|
|
|
430
|
|
|
402
|
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
Net Loss Including Noncontrolling Interests
|
$
|
(1,050
|
)
|
|
$
|
(985
|
)
|
|
$
|
(2,441
|
)
|
Other Items of Comprehensive Loss
|
|
|
|
|
|
||||||
Net Change in Mutual Fund Investment
|
—
|
|
|
—
|
|
|
(11
|
)
|
|||
Less Tax Expense
|
—
|
|
|
—
|
|
|
4
|
|
|||
Net Change in Pension and Other
|
3
|
|
|
3
|
|
|
99
|
|
|||
Less Tax Benefit
|
(1
|
)
|
|
(1
|
)
|
|
(35
|
)
|
|||
Other Comprehensive Income
|
2
|
|
|
2
|
|
|
57
|
|
|||
Comprehensive Loss Including Noncontrolling Interests
|
$
|
(1,048
|
)
|
|
$
|
(983
|
)
|
|
$
|
(2,384
|
)
|
Less: Comprehensive Income Attributable to Noncontrolling Interests
|
68
|
|
|
13
|
|
|
—
|
|
|||
Comprehensive Loss Attributable to Noble Energy
|
$
|
(1,116
|
)
|
|
$
|
(996
|
)
|
|
$
|
(2,384
|
)
|
|
December 31,
2017 |
|
December 31,
2016 |
||||
ASSETS
|
|
|
|
||||
Current Assets
|
|
|
|
||||
Cash and Cash Equivalents
|
$
|
675
|
|
|
$
|
1,180
|
|
Accounts Receivable, Net
|
748
|
|
|
615
|
|
||
Other Current Assets
|
780
|
|
|
160
|
|
||
Total Current Assets
|
2,203
|
|
|
1,955
|
|
||
Property, Plant and Equipment
|
|
|
|
||||
Oil and Gas Properties (Successful Efforts Method of Accounting)
|
29,678
|
|
|
30,355
|
|
||
Property, Plant and Equipment, Other
|
879
|
|
|
909
|
|
||
Total Property, Plant and Equipment, Gross
|
30,557
|
|
|
31,264
|
|
||
Accumulated Depreciation, Depletion and Amortization
|
(13,055
|
)
|
|
(12,716
|
)
|
||
Total Property, Plant and Equipment, Net
|
17,502
|
|
|
18,548
|
|
||
Goodwill
|
1,310
|
|
|
—
|
|
||
Other Noncurrent Assets
|
461
|
|
|
508
|
|
||
Total Assets
|
$
|
21,476
|
|
|
$
|
21,011
|
|
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
|
|
||||
Current Liabilities
|
|
|
|
||||
Accounts Payable - Trade
|
$
|
1,161
|
|
|
$
|
736
|
|
Other Current Liabilities
|
578
|
|
|
742
|
|
||
Total Current Liabilities
|
1,739
|
|
|
1,478
|
|
||
Long-Term Debt
|
6,746
|
|
|
7,011
|
|
||
Net Deferred Income Tax Liability
|
1,127
|
|
|
1,819
|
|
||
Other Noncurrent Liabilities
|
1,245
|
|
|
1,103
|
|
||
Total Liabilities
|
10,857
|
|
|
11,411
|
|
||
|
|
|
|
||||
Shareholders’ Equity
|
|
|
|
||||
Preferred Stock - Par Value $1.00 per share; 4 Million Shares Authorized, None Issued
|
—
|
|
|
—
|
|
||
Common Stock - Par Value $0.01; 1 Billion Shares Authorized; 529 Million and 471 Million Shares Issued, Respectively
|
5
|
|
|
5
|
|
||
Additional Paid in Capital
|
8,438
|
|
|
6,450
|
|
||
Accumulated Other Comprehensive Loss
|
(30
|
)
|
|
(31
|
)
|
||
Treasury Stock, at Cost; 39 Million and 38 Million Shares, Respectively
|
(725
|
)
|
|
(692
|
)
|
||
Retained Earnings
|
2,248
|
|
|
3,556
|
|
||
Noble Energy Share of Equity
|
9,936
|
|
|
9,288
|
|
||
Noncontrolling Interests
|
683
|
|
|
312
|
|
||
Total Equity
|
10,619
|
|
|
9,600
|
|
||
Total Liabilities and Equity
|
$
|
21,476
|
|
|
$
|
21,011
|
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
Cash Flows From Operating Activities
|
|
|
|
|
|
||||||
Net Loss Including Noncontrolling Interests
|
$
|
(1,050
|
)
|
|
$
|
(985
|
)
|
|
$
|
(2,441
|
)
|
Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities
|
|
|
|
|
|
|
|
||||
Depreciation, Depletion and Amortization
|
2,053
|
|
|
2,454
|
|
|
2,131
|
|
|||
Asset Impairments
|
70
|
|
|
92
|
|
|
533
|
|
|||
Loss on Marcellus Shale Upstream Divestiture
|
2,379
|
|
|
—
|
|
|
—
|
|
|||
Goodwill Impairment
|
—
|
|
|
—
|
|
|
779
|
|
|||
Dry Hole Cost
|
9
|
|
|
579
|
|
|
266
|
|
|||
Deferred Income Taxes
|
(1,227
|
)
|
|
(984
|
)
|
|
116
|
|
|||
(Gain) Loss on Commodity Derivative Instruments
|
(63
|
)
|
|
139
|
|
|
(501
|
)
|
|||
Net Cash Received in Settlement of Commodity Derivative Instruments
|
13
|
|
|
569
|
|
|
1,009
|
|
|||
Gain on Divestitures
|
(326
|
)
|
|
(238
|
)
|
|
—
|
|
|||
Stock Based Compensation
|
104
|
|
|
77
|
|
|
86
|
|
|||
Non-cash Pension Plan Termination Expense
|
—
|
|
|
—
|
|
|
82
|
|
|||
Loss (Gain) on Debt Extinguishment
|
98
|
|
|
(80
|
)
|
|
—
|
|
|||
Undeveloped Leasehold Impairment
|
62
|
|
|
93
|
|
|
21
|
|
|||
Expiration and Amortization of Undeveloped Leaseholds
|
—
|
|
|
55
|
|
|
92
|
|
|||
Other Adjustments for Noncash Items Included in Income
|
(21
|
)
|
|
40
|
|
|
18
|
|
|||
Changes in Operating Assets and Liabilities, Net of Assets Acquired and Liabilities Assumed
|
|
|
|
|
|
||||||
(Increase) Decrease in Accounts Receivable
|
(171
|
)
|
|
(164
|
)
|
|
453
|
|
|||
Increase (Decrease) in Accounts Payable
|
248
|
|
|
(111
|
)
|
|
(364
|
)
|
|||
(Decrease) Increase in Current Income Taxes Payable
|
(36
|
)
|
|
(32
|
)
|
|
(94
|
)
|
|||
(Decrease) Increase in Other Current Liabilities
|
(101
|
)
|
|
(63
|
)
|
|
(70
|
)
|
|||
Other Operating Assets and Liabilities, Net
|
(90
|
)
|
|
(90
|
)
|
|
(54
|
)
|
|||
Net Cash Provided by Operating Activities
|
1,951
|
|
|
1,351
|
|
|
2,062
|
|
|||
Cash Flows From Investing Activities
|
|
|
|
|
|
|
|
||||
Additions to Property, Plant and Equipment
|
(2,649
|
)
|
|
(1,541
|
)
|
|
(2,979
|
)
|
|||
Proceeds from Divestitures
|
2,073
|
|
|
1,241
|
|
|
151
|
|
|||
Clayton Williams Energy Acquisition, Net of Cash Received
|
(616
|
)
|
|
—
|
|
|
—
|
|
|||
Other Acquisitions
|
(327
|
)
|
|
—
|
|
|
—
|
|
|||
Marcellus Shale Acreage Exchange Consideration
|
—
|
|
|
(213
|
)
|
|
—
|
|
|||
Other
|
(87
|
)
|
|
82
|
|
|
(43
|
)
|
|||
Net Cash Used in Investing Activities
|
(1,606
|
)
|
|
(431
|
)
|
|
(2,871
|
)
|
|||
Cash Flows From Financing Activities
|
|
|
|
|
|
|
|
||||
Dividends Paid, Common Stock
|
(190
|
)
|
|
(172
|
)
|
|
(291
|
)
|
|||
Proceeds from Issuance of Noble Energy Common Stock, Net of Offering Costs
|
—
|
|
|
—
|
|
|
1,112
|
|
|||
Proceeds from Revolving Credit Facility
|
1,585
|
|
|
—
|
|
|
—
|
|
|||
Repayment of Revolving Credit Facility
|
(1,355
|
)
|
|
—
|
|
|
(70
|
)
|
|||
Repayment of Clayton Williams Energy Long-term Debt
|
(595
|
)
|
|
—
|
|
|
—
|
|
|||
Proceeds from Term Loan Facility
|
—
|
|
|
1,400
|
|
|
—
|
|
|||
Repayment of Term Loan Facility
|
(550
|
)
|
|
(850
|
)
|
|
—
|
|
|||
Proceeds from Issuance of Senior Notes, Net
|
1,086
|
|
|
—
|
|
|
—
|
|
|||
Repayment of Senior Notes
|
(1,114
|
)
|
|
(1,383
|
)
|
|
(12
|
)
|
|||
Proceeds from Noble Midstream Services Revolving Credit Facility
|
325
|
|
|
—
|
|
|
—
|
|
|||
Repayment of Noble Midstream Services Revolving Credit Facility
|
(240
|
)
|
|
—
|
|
|
—
|
|
|||
Proceeds from Issuance of Noble Midstream Partners Common Units, Net of Offering Costs
|
312
|
|
|
299
|
|
|
—
|
|
|||
Other
|
(114
|
)
|
|
(62
|
)
|
|
(85
|
)
|
|||
Net Cash (Used in) Provided By Financing Activities
|
(850
|
)
|
|
(768
|
)
|
|
654
|
|
|||
(Decrease) Increase in Cash and Cash Equivalents
|
(505
|
)
|
|
152
|
|
|
(155
|
)
|
|||
Cash and Cash Equivalents at Beginning of Period
|
1,180
|
|
|
1,028
|
|
|
1,183
|
|
|||
Cash and Cash Equivalents at End of Period
|
$
|
675
|
|
|
$
|
1,180
|
|
|
$
|
1,028
|
|
|
Attributable to Noble Energy
|
|
|
|
|
|||||||||||||||||||||
|
Common
Stock
|
|
Additional
Paid in
Capital
|
|
Accumulated Other
Comprehensive
Loss
|
|
Treasury
Stock at
Cost
|
|
Retained
Earnings
|
|
Non-controlling Interests
|
|
Total
Equity
|
|||||||||||||
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
|
|
||||||
Dividends (72 cents per share)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(291
|
)
|
|
—
|
|
|
(291
|
)
|
||||||
Issuance of Shares of Noble Energy Common Stock to Public, Net of Offering Costs
|
—
|
|
|
1,112
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,112
|
|
||||||
Net Change in Other
|
—
|
|
|
2
|
|
|
57
|
|
|
(17
|
)
|
|
—
|
|
|
—
|
|
|
42
|
|
||||||
December 31, 2015
|
$
|
5
|
|
|
$
|
6,360
|
|
|
$
|
(33
|
)
|
|
$
|
(688
|
)
|
|
$
|
4,726
|
|
|
—
|
|
|
$
|
10,370
|
|
Net (Loss) Income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(998
|
)
|
|
13
|
|
|
(985
|
)
|
||||||
Stock-based Compensation
|
—
|
|
|
68
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
68
|
|
||||||
Exercise of Stock Options
|
—
|
|
|
24
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
24
|
|
||||||
Dividends (40 cents per share)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(172
|
)
|
|
—
|
|
|
(172
|
)
|
||||||
Issuance of Noble Midstream Partners Common Units, Net of Offering Costs
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
299
|
|
|
299
|
|
||||||
Net Change in Other
|
—
|
|
|
(2
|
)
|
|
2
|
|
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
||||||
December 31, 2016
|
$
|
5
|
|
|
$
|
6,450
|
|
|
$
|
(31
|
)
|
|
$
|
(692
|
)
|
|
$
|
3,556
|
|
|
312
|
|
|
$
|
9,600
|
|
Net (Loss) Income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,118
|
)
|
|
68
|
|
|
(1,050
|
)
|
||||||
Clayton Williams Energy Acquisition
|
—
|
|
|
1,876
|
|
|
—
|
|
|
(25
|
)
|
|
—
|
|
|
—
|
|
|
1,851
|
|
||||||
Stock-based Compensation
|
—
|
|
|
100
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
100
|
|
||||||
Exercise of Stock Options
|
—
|
|
|
10
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10
|
|
||||||
Dividends (40 cents per share)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(190
|
)
|
|
—
|
|
|
(190
|
)
|
||||||
Issuance of Noble Midstream Partners Common Units, Net of Offering Costs
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
312
|
|
|
312
|
|
||||||
Distributions to Noncontrolling Interest Owners
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(28
|
)
|
|
(28
|
)
|
||||||
Net Change in Other
|
—
|
|
|
2
|
|
|
1
|
|
|
(8
|
)
|
|
—
|
|
|
19
|
|
|
14
|
|
||||||
December 31, 2017
|
$
|
5
|
|
|
$
|
8,438
|
|
|
$
|
(30
|
)
|
|
$
|
(725
|
)
|
|
$
|
2,248
|
|
|
683
|
|
|
$
|
10,619
|
|
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
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
|
2017
|
|
2016
|
|
2015
|
||||||
Production Expense
|
|
|
|
|
|
|
|
|
|
|||
Lease Operating Expense
|
|
$
|
571
|
|
|
$
|
542
|
|
|
$
|
563
|
|
Production and Ad Valorem Taxes
|
|
138
|
|
|
78
|
|
|
127
|
|
|||
Gathering, Transportation and Processing Expense
(1)
|
|
432
|
|
|
480
|
|
|
306
|
|
|||
Total
|
|
$
|
1,141
|
|
|
$
|
1,100
|
|
|
$
|
996
|
|
Exploration Expense
|
|
|
|
|
|
|
||||||
Leasehold Impairment and Amortization
(2)
|
|
$
|
62
|
|
|
$
|
148
|
|
|
$
|
113
|
|
Dry Hole Cost
|
|
9
|
|
|
579
|
|
|
266
|
|
|||
Seismic, Geological and Geophysical
|
|
27
|
|
|
76
|
|
|
34
|
|
|||
Staff Expense
|
|
55
|
|
|
77
|
|
|
43
|
|
|||
Other
|
|
35
|
|
|
45
|
|
|
32
|
|
|||
Total
|
|
$
|
188
|
|
|
$
|
925
|
|
|
$
|
488
|
|
Loss on Marcellus Shale Upstream Divestiture
|
|
|
|
|
|
|
||||||
Loss on Sale
|
|
$
|
2,270
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Firm Transportation Commitment
(2)
|
|
93
|
|
|
—
|
|
|
—
|
|
|||
Other
(3)
|
|
16
|
|
|
—
|
|
|
—
|
|
|||
Total
|
|
$
|
2,379
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Other Operating (Income) Expense, Net
|
|
|
|
|
|
|
|
|
|
|||
Marketing Expense
(4)
|
|
$
|
47
|
|
|
$
|
58
|
|
|
$
|
33
|
|
Clayton Williams Acquisition Expenses
(5)
|
|
100
|
|
|
—
|
|
|
—
|
|
|||
Corporate Restructuring Expense
(6)
|
|
—
|
|
|
8
|
|
|
51
|
|
|||
Pension Plan Expense
(7)
|
|
—
|
|
|
—
|
|
|
88
|
|
|||
Impact of Rosetta Merger
(8)
|
|
—
|
|
|
(25
|
)
|
|
81
|
|
|||
North Sea Remediation Project Revision
(9)
|
|
(42
|
)
|
|
—
|
|
|
—
|
|
|||
Loss on Asset Due to Terminated Contract
(10)
|
|
—
|
|
|
41
|
|
|
—
|
|
|||
Gain on Divestitures, Net
(11)
|
|
(326
|
)
|
|
(238
|
)
|
|
—
|
|
|||
Other, Net
|
|
33
|
|
|
53
|
|
|
79
|
|
|||
Total
|
|
$
|
(188
|
)
|
|
$
|
(103
|
)
|
|
$
|
332
|
|
(1)
|
Certain of our gathering and processing expenses were historically presented as components of other operating expense, net, in our consolidated statement of operations. Beginning in 2017, we changed our presentation to reflect these as components of production expense. These costs are now included within gathering, transportation and processing expense. For the years ended December 31, 2016 and 2015, these costs totaled
$17 million
and
$17 million
, respectively, and have been reclassified from other operating expense, net to conform to current presentation.
|
(2)
|
See
Note
6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs
.
|
(3)
|
Expense relates to unutilized commitments associated with Marcellus Shale firm transportation contracts. See
Note
17. Commitments and Contingencies
.
|
(4)
|
Amount includes costs for legal and advisory services and employee severance charges.
|
(5)
|
Expense relates to unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments.
|
(6)
|
See
Note
3. Clayton Williams Energy Acquisition
.
|
(7)
|
Expenses are associated with corporate organizational activities.
|
(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
4. Acquisitions, Divestitures and Merger
.
|
(10)
|
See
Note
9. Asset Retirement Obligations
.
|
(11)
|
Amount relates to the termination of a rig contract offshore Falkland Islands as a result of a supplier's non-performance.
|
(12)
|
See
Note
4. Acquisitions, Divestitures and Merger
.
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
December 31,
|
||||||
(millions)
|
|
2017
|
|
2016
|
||||
Accounts Receivable, Net
|
|
|
|
|
||||
Commodity Sales
|
|
$
|
455
|
|
|
$
|
403
|
|
Joint Interest Billings
|
|
207
|
|
|
106
|
|
||
Proceeds Receivable
(1)
|
|
—
|
|
|
40
|
|
||
Other
|
|
103
|
|
|
86
|
|
||
Allowance for Doubtful Accounts
|
|
(17
|
)
|
|
(20
|
)
|
||
Total
|
|
$
|
748
|
|
|
$
|
615
|
|
Other Current Assets
|
|
|
|
|
|
|
||
Inventories, Materials and Supplies
|
|
$
|
66
|
|
|
$
|
71
|
|
Inventories, Crude Oil
|
|
16
|
|
|
18
|
|
||
Assets Held for Sale
(2)
|
|
629
|
|
|
18
|
|
||
Restricted Cash
(3)
|
|
38
|
|
|
30
|
|
||
Prepaid Expenses and Other Assets, Current
|
|
31
|
|
|
23
|
|
||
Total
|
|
$
|
780
|
|
|
$
|
160
|
|
Other Noncurrent Assets
|
|
|
|
|
||||
Equity Method Investments
|
|
$
|
305
|
|
|
$
|
400
|
|
Mutual Fund Investments
|
|
57
|
|
|
71
|
|
||
Net Deferred Income Tax Asset
|
|
25
|
|
|
—
|
|
||
Other Assets, Noncurrent
|
|
74
|
|
|
37
|
|
||
Total
|
|
$
|
461
|
|
|
$
|
508
|
|
Other Current Liabilities
|
|
|
|
|
||||
Production and Ad Valorem Taxes
|
|
$
|
84
|
|
|
$
|
115
|
|
Commodity Derivative Liabilities, Current
|
|
58
|
|
|
102
|
|
||
Income Taxes Payable
|
|
18
|
|
|
53
|
|
||
Asset Retirement Obligations, Current
|
|
51
|
|
|
160
|
|
||
Interest Payable
|
|
67
|
|
|
76
|
|
||
Compensation and Benefits Payable
|
|
98
|
|
|
110
|
|
||
Current Portion of Capital Lease and Other Obligations
|
|
61
|
|
|
63
|
|
||
Other Liabilities, Current
|
|
141
|
|
|
63
|
|
||
Total
|
|
$
|
578
|
|
|
$
|
742
|
|
Other Noncurrent Liabilities
|
|
|
|
|
||||
Deferred Compensation Liabilities, Noncurrent
|
|
$
|
197
|
|
|
$
|
218
|
|
Asset Retirement Obligations, Noncurrent
|
|
824
|
|
|
775
|
|
||
Production and Ad Valorem Taxes
|
|
69
|
|
|
47
|
|
||
Marcellus Firm Transportation Commitment, Noncurrent
(4)
|
|
76
|
|
|
—
|
|
||
Other Liabilities, Noncurrent
|
|
79
|
|
|
63
|
|
||
Total
|
|
$
|
1,245
|
|
|
$
|
1,103
|
|
(1)
|
Proceeds relate to the farm-out of a
35%
interest in Block 12 offshore Cyprus and were received in January 2017. See
Note
4. Acquisitions, Divestitures and Merger
.
|
(4)
|
Relates to unutilized commitments associated with Marcellus Shale firm transportation contracts. See
Note
4. Acquisitions, Divestitures
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
|
2017
|
|
2016
|
|
2015
|
||||||
Cash Paid During the Year For
|
|
|
|
|
|
|
||||||
Interest, Net of Amount Capitalized
|
|
$
|
346
|
|
|
$
|
327
|
|
|
$
|
260
|
|
Income Taxes Paid, Net
|
|
121
|
|
|
236
|
|
|
202
|
|
|||
Non-Cash Financing and Investing Activities
|
|
|
|
|
|
|
||||||
Increase in Capital Lease and Other Obligations
|
|
—
|
|
|
5
|
|
|
55
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
Year Ended December 31,
|
||||||
(millions, except per share amounts)
|
2017
|
|
2016
|
||||
Revenues
|
$
|
4,304
|
|
|
$
|
3,651
|
|
Net Loss and Comprehensive Loss Attributable to Noble Energy
|
(678
|
)
|
|
(1,082
|
)
|
||
|
|
|
|
||||
Net Loss Attributable to Noble Energy per Common Share
|
|
|
|
||||
Basic and Diluted
|
$
|
(1.39
|
)
|
|
$
|
(2.23
|
)
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
•
|
US Onshore Divestitures
During 2017, we received total proceeds of
$671 million
resulting from the sale of certain US onshore properties, including
$568 million
related to divestment of non-core acreage in the DJ Basin. Proceeds were applied to reduce field basis with no recognition of gain or loss. A subsequent closing for certain non-core DJ Basin operated properties, in the amount of approximately
$40 million
, is expected to occur in mid-2018.
|
•
|
Sale of Mineral and Royalty Assets
We received
$335 million
and recognized a gain of
$334 million
on the sale of mineral and royalty assets covering approximately
140,000
net mineral acres concentrated primarily in Texas, Oklahoma and North Dakota.
|
•
|
Delaware Basin Acquisition
In January 2017, we completed the acquisition of Delaware Basin properties, including
seven
producing wells, thus increasing our contiguous acreage position in the Reeves County area. Consideration totaled
$301 million
, approximately
$246 million
of which was allocated to undeveloped leasehold cost. Initial consideration of
$30 million
was paid into an escrow account in fourth quarter 2016 and reflected as a restricted asset in our consolidated balance sheet as of December 31, 2016.
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
•
|
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
, with the remainder of the sale closing in 2017. Proceeds were applied to reduce field basis with no recognition of gain or loss;
|
•
|
sold additional DJ Basin non-producing properties, certain Eagle Ford properties, our Bowdoin property in northern Montana, and certain other smaller US onshore 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, which included the Karish and Tanin fields, offshore Israel, 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 and Dalit fields, offshore Israel, in compliance with the terms of the Framework, which requires us to reduce our ownership interest in the fields 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 fields basis and resulted in the recognition of a
$261 million
gain; and
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
•
|
received proceeds of
$131 million
related to the farm-out of a
35%
interest in Block 12, which includes the Aphrodite natural gas discovery, offshore Cyprus. 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)
|
2017
|
|
2016
|
|
2015
|
||||||
Gulf of Mexico
|
$
|
63
|
|
|
$
|
—
|
|
|
$
|
158
|
|
Israel
|
—
|
|
|
88
|
|
|
36
|
|
|||
Equatorial Guinea
|
—
|
|
|
—
|
|
|
339
|
|
|||
Other International
|
7
|
|
|
4
|
|
|
—
|
|
|||
Total
|
$
|
70
|
|
|
$
|
92
|
|
|
$
|
533
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
2017
|
|
2016
|
|
2015
|
||||||
Capitalized Exploratory Well Costs, Beginning of Period
|
$
|
768
|
|
|
$
|
1,353
|
|
|
$
|
1,337
|
|
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves
|
20
|
|
|
84
|
|
|
123
|
|
|||
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)
|
(203
|
)
|
|
(1
|
)
|
|
(19
|
)
|
|||
Capitalized Exploratory Well Costs Charged to Expense
(3)
|
(65
|
)
|
|
(525
|
)
|
|
(88
|
)
|
|||
Capitalized Exploratory Well Costs, End of Period
|
$
|
520
|
|
|
$
|
768
|
|
|
$
|
1,353
|
|
|
December 31,
|
||||||||||
(millions)
|
2017
|
|
2016
|
|
2015
|
||||||
Exploratory Well Costs Capitalized for a Period of One Year or Less
|
$
|
10
|
|
|
$
|
69
|
|
|
$
|
95
|
|
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling
|
510
|
|
|
699
|
|
|
1,258
|
|
|||
Balance at End of Period
|
$
|
520
|
|
|
$
|
768
|
|
|
$
|
1,353
|
|
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling
|
8
|
|
|
10
|
|
|
14
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
|
Suspended Since
|
|
|
||||||||||||
Country/Project
(millions)
|
Total
|
|
2015 - 2016
|
|
2013 - 2014
|
|
2012 & Prior
|
|
Progress
|
||||||||
Gulf of Mexico
|
|
|
|
|
|
|
|
|
|
||||||||
Katmai
|
$
|
147
|
|
|
$
|
56
|
|
|
$
|
91
|
|
|
$
|
—
|
|
|
Progressing a development scenario for this 2014 crude oil discovery. We are currently conducting feasibility and front-end engineering and design studies on host platform options.
|
Offshore Equatorial Guinea
|
|
|
|
|
|
|
|
|
|
||||||||
Felicita (Block O)
|
47
|
|
|
3
|
|
|
12
|
|
|
32
|
|
|
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)
|
23
|
|
|
1
|
|
|
6
|
|
|
16
|
|
|
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)
|
55
|
|
|
4
|
|
|
6
|
|
|
45
|
|
|
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 both governments to evaluate natural gas monetization options for both Yolanda (Equatorial Guinea) and YoYo discoveries. In June 2017, we converted our mining concession license for the YoYo block into a PSC.
|
||||
Offshore Israel
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Leviathan-1 Deep
|
91
|
|
|
8
|
|
|
10
|
|
|
73
|
|
|
The well did not reach the target interval in 2012. We continue to reprocess and review seismic information for this discovery, based on information obtained from other recent discoveries in the region, and develop future drilling plans to test this deep oil concept, which is held by the Leviathan Development and Production Leases.
|
||||
Dalit
|
32
|
|
|
3
|
|
|
5
|
|
|
24
|
|
|
Our future 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. See also Note 4. Acquisitions, Divestitures and Merger.
|
||||
Offshore Cyprus
|
|
|
|
|
|
|
|
|
|
||||||||
Cyprus
|
97
|
|
|
15
|
|
|
52
|
|
|
30
|
|
|
In 2016, we farmed-down a 35% interest in Block 12 and submitted an updated development plan. We 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. During 2017, we submitted an updated development plan, progressed capital project cost improvement and continued regional natural gas marketing efforts.
|
||||
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Projects less than $20 million
|
18
|
|
|
(9
|
)
|
|
21
|
|
|
6
|
|
|
Continuing to assess and evaluate wells.
|
||||
Total
|
$
|
510
|
|
|
$
|
81
|
|
|
$
|
203
|
|
|
$
|
226
|
|
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
•
|
50%
interest in Advantage Pipeline, which owns and operates a 70-mile crude oil pipeline in Texas (See
Note 4 – Acquisitions, Divestitures and Merger
);
|
•
|
50%
interest in CONE Gathering, which owns and operates natural gas gathering facilities servicing the Marcellus Shale (See
Note 4 – Acquisitions, Divestitures and Merger
);
|
•
|
34%
interest in CONE Midstream, a public master limited partnership, which constructs, owns and operates natural gas gathering and other midstream energy assets in the Marcellus Shale;
|
•
|
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 (LPG) processing plant in Equatorial Guinea.
|
|
|
December 31,
|
||||||
(millions)
|
|
2017
|
|
2016
|
||||
Equity Method Investments
|
|
|
|
|
||||
CONE Investments
(1)
|
|
$
|
—
|
|
|
$
|
172
|
|
AMPCO
|
|
129
|
|
|
120
|
|
||
Alba Plant
|
|
80
|
|
|
82
|
|
||
Advantage Pipeline
|
|
70
|
|
|
—
|
|
||
Other
|
|
26
|
|
|
26
|
|
||
Total Equity Method Investments
|
|
$
|
305
|
|
|
$
|
400
|
|
(1)
|
CONE Investments include CONE Midstream and CONE Gathering. The investments are included in assets held for sale at December 31, 2017.
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
December 31,
|
||||||
(millions)
|
|
2017
|
|
2016
|
||||
Balance Sheet Information
|
|
|
|
|
||||
Current Assets
|
|
$
|
390
|
|
|
$
|
313
|
|
Noncurrent Assets
|
|
588
|
|
|
1,390
|
|
||
Current Liabilities
|
|
171
|
|
|
149
|
|
||
Noncurrent Liabilities
|
|
90
|
|
|
256
|
|
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
|
2017
|
|
2016
|
|
2015
|
||||||
Statements of Operations Information
|
|
|
|
|
|
|
||||||
Operating Revenues
|
|
$
|
790
|
|
|
$
|
667
|
|
|
$
|
645
|
|
Operating Expenses
|
|
303
|
|
|
355
|
|
|
393
|
|
|||
Operating Income
|
|
487
|
|
|
312
|
|
|
252
|
|
|||
Other (Income) Net
|
|
(15
|
)
|
|
(7
|
)
|
|
(9
|
)
|
|||
Income Before Income Taxes
|
|
502
|
|
|
319
|
|
|
261
|
|
|||
Income Tax Provision
|
|
136
|
|
|
60
|
|
|
46
|
|
|||
Net Income
|
|
$
|
366
|
|
|
$
|
259
|
|
|
$
|
215
|
|
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
|
||||||||
2018
|
Three-Way Collars
|
NYMEX WTI
|
10,000
|
|
$
|
—
|
|
|
$
|
45.50
|
|
$
|
52.50
|
|
$
|
69.09
|
|
2018
|
Swaps
|
NYMEX WTI
|
24,000
|
|
57.09
|
|
|
—
|
|
—
|
|
—
|
|
||||
2018
|
Two-Way Collars
|
NYMEX WTI
|
18,000
|
|
—
|
|
|
—
|
|
50.42
|
|
58.82
|
|
||||
2018
|
Three-Way Collars
|
Dated Brent
|
3,000
|
|
—
|
|
|
40.00
|
|
50.00
|
|
70.41
|
|
||||
2018
|
Swaps
|
ICE Brent
|
2,000
|
|
59.00
|
|
|
—
|
|
—
|
|
—
|
|
||||
2018
|
Two-Way Collars
|
ICE Brent
|
2,000
|
|
—
|
|
|
—
|
|
50.00
|
|
55.25
|
|
||||
2018
|
Three-Way Collars
|
ICE Brent
|
5,000
|
|
—
|
|
|
43.00
|
|
50.00
|
|
59.50
|
|
||||
2018
|
Basis Swaps
|
(1)
|
12,000
|
|
(0.60
|
)
|
|
—
|
|
—
|
|
—
|
|
||||
2019
|
Swaps
|
NYMEX WTI
|
3,000
|
|
55.07
|
|
|
—
|
|
—
|
|
—
|
|
||||
2019
|
Swaps
|
ICE Brent
|
5,000
|
|
57.00
|
|
|
—
|
|
—
|
|
—
|
|
||||
2019
|
Three-Way Collars
|
ICE Brent
|
3,000
|
|
—
|
|
|
43.00
|
|
50.00
|
|
64.07
|
|
||||
2019
|
Basis Swaps
|
(1)
|
12,000
|
|
(1.01
|
)
|
|
—
|
|
—
|
|
—
|
|
(1)
|
We have entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma. The weighted average differential represents the amount of reduction to Cushing, Oklahoma, prices for the notional volumes covered by the basis swap contracts.
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
Fair Value of Derivative Instruments
(1)
|
|||||||||||||||||||||||
|
Asset Derivative Instruments
|
|
Liability Derivative Instruments
|
||||||||||||||||||||
|
December 31,
2017 |
|
December 31,
2016 |
|
December 31,
2017 |
|
December 31,
2016 |
||||||||||||||||
|
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
|
|
$
|
2
|
|
|
Current Assets
|
|
$
|
—
|
|
|
Current Liabilities
|
|
$
|
58
|
|
|
Current Liabilities
|
|
$
|
102
|
|
|
Noncurrent Assets
|
|
—
|
|
|
Noncurrent Assets
|
|
—
|
|
|
Noncurrent Liabilities
|
|
15
|
|
|
Noncurrent Liabilities
|
|
14
|
|
||||
Total
|
|
|
$
|
2
|
|
|
|
|
$
|
—
|
|
|
|
|
$
|
73
|
|
|
|
|
$
|
116
|
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
2017
|
|
2016
|
|
2015
|
||||||
Cash (Received) Paid in Settlement of Commodity Derivative Instruments
|
|
|
|
|
|
||||||
Crude Oil
|
$
|
(14
|
)
|
|
$
|
(499
|
)
|
|
$
|
(844
|
)
|
Natural Gas
|
1
|
|
|
(70
|
)
|
|
(147
|
)
|
|||
NGLs
(1)
|
—
|
|
|
—
|
|
|
(18
|
)
|
|||
Total Cash Received in Settlement of Commodity Derivative Instruments
|
(13
|
)
|
|
(569
|
)
|
|
(1,009
|
)
|
|||
Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments
|
|
|
|
|
|
||||||
Crude Oil
|
18
|
|
|
582
|
|
|
423
|
|
|||
Natural Gas
|
(68
|
)
|
|
126
|
|
|
65
|
|
|||
NGLs
(1)
|
—
|
|
|
—
|
|
|
20
|
|
|||
Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments
|
(50
|
)
|
|
708
|
|
|
508
|
|
|||
(Gain) Loss on Commodity Derivative Instruments
|
|
|
|
|
|
||||||
Crude Oil
|
4
|
|
|
83
|
|
|
(421
|
)
|
|||
Natural Gas
|
(67
|
)
|
|
56
|
|
|
(82
|
)
|
|||
NGLs
(1)
|
—
|
|
|
—
|
|
|
2
|
|
|||
Total (Gain) Loss on Commodity Derivative Instruments
|
$
|
(63
|
)
|
|
$
|
139
|
|
|
$
|
(501
|
)
|
(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)
|
2017
|
|
2016
|
||||
Asset Retirement Obligations, Beginning Balance
|
$
|
935
|
|
|
$
|
989
|
|
Liabilities Incurred
|
94
|
|
|
21
|
|
||
Liabilities Settled
|
(82
|
)
|
|
(120
|
)
|
||
Revision of Estimate
|
(65
|
)
|
|
(3
|
)
|
||
Reclassification to Liabilities Associated with Assets Held for Sale
|
(54
|
)
|
|
—
|
|
||
Accretion Expense
|
47
|
|
|
48
|
|
||
Asset Retirement Obligations, Ending Balance
|
$
|
875
|
|
|
$
|
935
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
December 31,
2017 |
|
December 31,
2016 |
||||||||||
(millions, except percentages)
|
Debt
|
|
Interest Rate
|
|
Debt
|
|
Interest Rate
|
||||||
Revolving Credit Facility, due August 27, 2020
|
$
|
230
|
|
|
2.27
|
%
|
|
$
|
—
|
|
|
—
|
%
|
Noble Midstream Services Revolving Credit Facility, due September 20, 2021
|
85
|
|
|
2.49
|
%
|
|
—
|
|
|
—
|
%
|
||
Term Loan Facility, due January 6, 2019
(1)
|
—
|
|
|
—
|
%
|
|
550
|
|
|
2.01
|
%
|
||
Leviathan Term Loan Facility, due February 23, 2025
|
—
|
|
|
—
|
%
|
|
—
|
|
|
—
|
|
||
Senior Notes, due March 1, 2019
(2)
|
—
|
|
|
—
|
%
|
|
1,000
|
|
|
8.25
|
%
|
||
Senior Notes, due May 1, 2021
|
379
|
|
|
5.63
|
%
|
|
379
|
|
|
5.63
|
%
|
||
Senior Notes, due December 15, 2021
|
1,000
|
|
|
4.15
|
%
|
|
1,000
|
|
|
4.15
|
%
|
||
Senior Notes, due June 1, 2022
(1)
|
—
|
|
|
—
|
%
|
|
18
|
|
|
5.88
|
%
|
||
Senior Notes, due October 15, 2023
|
100
|
|
|
7.25
|
%
|
|
100
|
|
|
7.25
|
%
|
||
Senior Notes, due November 15, 2024
|
650
|
|
|
3.90
|
%
|
|
650
|
|
|
3.90
|
%
|
||
Senior Notes, due April 1, 2027
|
250
|
|
|
8.00
|
%
|
|
250
|
|
|
8.00
|
%
|
||
Senior Notes, due January 15, 2028
(2)
|
600
|
|
|
3.85
|
%
|
|
—
|
|
|
—
|
%
|
||
Senior Notes, due March 1, 2041
|
850
|
|
|
6.00
|
%
|
|
850
|
|
|
6.00
|
%
|
||
Senior Notes, due November 15, 2043
|
1,000
|
|
|
5.25
|
%
|
|
1,000
|
|
|
5.25
|
%
|
||
Senior Notes, due November 15, 2044
|
850
|
|
|
5.05
|
%
|
|
850
|
|
|
5.05
|
%
|
||
Senior Notes, due August 15, 2047
(2)
|
500
|
|
|
4.95
|
%
|
|
—
|
|
|
—
|
%
|
||
Other Senior Notes and Debentures
(3)
|
92
|
|
|
7.13
|
%
|
|
92
|
|
|
7.13
|
%
|
||
Capital Lease and Other Obligations
(4)
|
273
|
|
|
—
|
%
|
|
375
|
|
|
—
|
%
|
||
Total
|
$
|
6,859
|
|
|
|
|
|
$
|
7,114
|
|
|
|
|
Unamortized Discount
|
(24
|
)
|
|
|
|
|
(23
|
)
|
|
|
|
||
Unamortized Premium
(2)
|
12
|
|
|
|
|
17
|
|
|
|
||||
Unamortized Debt Issuance Costs
|
(40
|
)
|
|
|
|
(34
|
)
|
|
|
||||
Total Debt, Net of Discount
|
$
|
6,807
|
|
|
|
|
|
$
|
7,074
|
|
|
|
|
Less Amounts Due Within One Year
|
|
|
|
|
|
|
|
|
|
|
|
||
Capital Lease and Other Obligations
|
(61
|
)
|
|
|
|
|
(63
|
)
|
|
|
|
||
Long-Term Debt Due After One Year
|
$
|
6,746
|
|
|
|
|
|
$
|
7,011
|
|
|
|
|
(1)
|
In fourth quarter 2017, we repaid
$550 million
of borrowings under the Term Loan Facility and
$18 million
of our outstanding Senior Notes due June 1, 2022.
|
(2)
|
In third quarter 2017, we redeemed all of our Senior Notes due March 1, 2019 and issued Senior Notes due January 15, 2028 and August 15, 2047.
|
(3)
|
Includes
$8 million
of Senior Notes due June 1, 2024 and
$84 million
of Senior Debentures due August 1, 2097. The weighted average interest rate for these instruments is
7.13%
.
|
(4)
|
The reduction from 2016 includes
$41 million
related to other obligations for drilling commitments assumed by the acquirer of the Marcellus Shale upstream assets and
$60 million
of capital lease principal payments.
|
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 London interbank offered rate (LIBOR) for an interest period of one month plus
1.00%
; or
|
•
|
in the case of LIBOR borrowings, the offered rate per annum for deposits of dollars for the applicable interest period.
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
(millions)
|
Debt
Principal
Payments
|
||
2018
|
$
|
—
|
|
2019
|
—
|
|
|
2020
|
230
|
|
|
2021
|
1,464
|
|
|
2022
|
—
|
|
|
Thereafter
|
4,892
|
|
|
Total
|
$
|
6,586
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
|
2017
|
|
2016
|
|
2015
|
||||||
Current Taxes
|
|
|
|
|
|
|
||||||
Federal
|
|
$
|
(11
|
)
|
|
$
|
(4
|
)
|
|
$
|
(1
|
)
|
State
|
|
1
|
|
|
5
|
|
|
—
|
|
|||
Foreign
|
|
96
|
|
|
196
|
|
|
107
|
|
|||
Total Current
|
|
$
|
86
|
|
|
$
|
197
|
|
|
$
|
106
|
|
Deferred Taxes
|
|
|
|
|
|
|
||||||
Federal
|
|
$
|
(1,258
|
)
|
|
$
|
(784
|
)
|
|
$
|
216
|
|
State
|
|
(8
|
)
|
|
(24
|
)
|
|
(5
|
)
|
|||
Foreign
|
|
39
|
|
|
(176
|
)
|
|
(95
|
)
|
|||
Total Deferred
|
|
$
|
(1,227
|
)
|
|
$
|
(984
|
)
|
|
$
|
116
|
|
Total Income Tax (Benefit) Provision Attributable to Noble Energy
|
|
$
|
(1,141
|
)
|
|
$
|
(787
|
)
|
|
$
|
222
|
|
Effective Tax Rate
|
|
52.1
|
%
|
|
44.4
|
%
|
|
(10.0
|
)%
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
December 31,
|
||||||
(millions)
|
|
2017
|
|
2016
|
||||
Deferred Tax Assets
|
|
|
|
|
||||
Loss Carryforwards
|
|
$
|
902
|
|
|
$
|
474
|
|
Employee Compensation and Benefits
|
|
97
|
|
|
150
|
|
||
Mark to Market of Commodity Derivative Instruments
|
|
7
|
|
|
44
|
|
||
Foreign Tax Credits
|
|
366
|
|
|
—
|
|
||
Other
|
|
104
|
|
|
49
|
|
||
Total Deferred Tax Assets
|
|
$
|
1,476
|
|
|
$
|
717
|
|
Valuation Allowance - Foreign Loss Carryforwards and Foreign Tax Credits
|
|
(549
|
)
|
|
(242
|
)
|
||
Net Deferred Tax Assets
|
|
$
|
927
|
|
|
$
|
475
|
|
Deferred Tax Liabilities
|
|
|
|
|
||||
Accumulated Undistributed Foreign Earnings
(1)
|
|
—
|
|
|
(240
|
)
|
||
Property, Plant and Equipment, Principally Due to Differences in Depreciation, Amortization, Lease Impairment and Abandonments
|
|
(2,029
|
)
|
|
(2,054
|
)
|
||
Total Deferred Tax Liability
|
|
$
|
(2,029
|
)
|
|
$
|
(2,294
|
)
|
Net Deferred Tax Liability
|
|
$
|
(1,102
|
)
|
|
$
|
(1,819
|
)
|
|
|
December 31,
|
||||||
(millions)
|
|
2017
|
|
2016
|
||||
Deferred Income Tax Asset - Noncurrent
|
|
$
|
25
|
|
|
$
|
—
|
|
Deferred Income Tax Liability - Noncurrent
|
|
(1,127
|
)
|
|
(1,819
|
)
|
||
Net Deferred Tax Liability
|
|
$
|
(1,102
|
)
|
|
$
|
(1,819
|
)
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
(millions)
|
|
Twelve Months Ended December 31, 2017
|
||
Unrecognized Tax Benefits, Beginning Balance
|
|
$
|
3
|
|
Reductions for Tax Positions of Prior Years
|
|
(3
|
)
|
|
Unrecognized Tax Benefits, Ending Balance
|
|
$
|
—
|
|
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
|
2017
|
|
2016
|
|
2015
|
||||||
Stock-Based Compensation Expense Included in:
|
|
|
|
|
|
|
||||||
General and Administrative Expense
|
|
$
|
56
|
|
|
$
|
62
|
|
|
$
|
50
|
|
Exploration Expense and Other
|
|
48
|
|
|
15
|
|
|
36
|
|
|||
Total Stock-Based Compensation Expense
|
|
$
|
104
|
|
|
$
|
77
|
|
|
$
|
86
|
|
Tax Benefit Recognized
|
|
$
|
(36
|
)
|
|
$
|
(27
|
)
|
|
$
|
(30
|
)
|
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)
|
|
2017
|
|
2016
|
|
2015
|
||||||
Expected Term (in Years)
|
|
6.4
|
|
|
6.3
|
|
|
6.0
|
|
|||
Expected Volatility
|
|
33.2
|
%
|
|
32.4
|
%
|
|
32.6
|
%
|
|||
Risk-Free Rate
|
|
2.2
|
%
|
|
1.6
|
%
|
|
1.4
|
%
|
|||
Expected Dividend Yield
|
|
0.9
|
%
|
|
0.7
|
%
|
|
1.2
|
%
|
|||
Weighted Average Grant-Date Fair Value
|
|
$
|
13.26
|
|
|
$
|
10.10
|
|
|
$
|
13.93
|
|
|
|
Options
|
|
Weighted
Average
Exercise
Price
|
|
Weighted
Average
Remaining
Contractual Term
|
|
Aggregate
Intrinsic Value
|
|||||
|
|
|
|
(per share)
|
|
(in years)
|
|
(in millions)
|
|||||
Outstanding at December 31, 2016
|
|
15,088,862
|
|
|
$
|
43.49
|
|
|
|
|
|
||
Granted
|
|
1,819,819
|
|
|
39.40
|
|
|
|
|
|
|||
Exercised
|
|
(382,882
|
)
|
|
37.57
|
|
|
|
|
|
|||
Forfeited
|
|
(976,577
|
)
|
|
43.93
|
|
|
|
|
|
|||
Outstanding at December 31, 2017
|
|
15,549,222
|
|
|
$
|
43.42
|
|
|
5.0
|
|
$
|
6
|
|
Exercisable at December 31, 2017
|
|
12,101,890
|
|
|
$
|
44.98
|
|
|
4.0
|
|
$
|
6
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
Year Ended December 31,
|
|||||||
|
2017
|
|
2016
|
|
2015
|
|||
Number of Simulations
|
500,000
|
|
|
500,000
|
|
|
500,000
|
|
Expected Volatility
|
35
|
%
|
|
38
|
%
|
|
30
|
%
|
Risk-Free Rate
|
1.5
|
%
|
|
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, 2016
|
|
1,371,780
|
|
|
$
|
36.37
|
|
|
1,502,992
|
|
|
$
|
27.43
|
|
Awarded
(1)
|
|
3,201,504
|
|
|
36.26
|
|
|
464,608
|
|
|
24.25
|
|
||
Vested
(1)
|
|
(2,515,383
|
)
|
|
34.93
|
|
|
(219,883
|
)
|
|
44.61
|
|
||
Forfeited
|
|
(218,164
|
)
|
|
37.66
|
|
|
(535,012
|
)
|
|
33.12
|
|
||
Outstanding at December 31, 2017
|
|
1,839,737
|
|
|
$
|
37.21
|
|
|
1,212,705
|
|
|
$
|
25.55
|
|
(1)
|
During 2017, we awarded approximately
1.9 million
shares of restricted stock for the conversion of Clayton Williams Energy shares into Noble Energy shares as part of the Clayton Williams Energy Acquisition. All awards subsequently vested during 2017. These awards are included in the above table. See
Note
3. Clayton Williams Energy Acquisition
.
|
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, 2016
|
|
712,089
|
|
|
$
|
31.65
|
|
|
209,504
|
|
|
$
|
6.82
|
|
Vested
|
|
(13,305
|
)
|
|
31.65
|
|
|
—
|
|
|
—
|
|
||
Forfeited
|
|
(88,625
|
)
|
|
31.65
|
|
|
(42,021
|
)
|
|
6.82
|
|
||
Outstanding at December 31, 2017
|
|
610,159
|
|
|
$
|
31.65
|
|
|
167,483
|
|
|
$
|
6.82
|
|
|
|
December 31,
|
||||||
(millions, except share amounts)
|
|
2017
|
|
2016
|
||||
Rabbi Trust Assets
|
|
|
|
|
||||
Mutual Fund Investments
|
|
$
|
57
|
|
|
$
|
62
|
|
Noble Energy Common Stock (at Fair Value)
|
|
14
|
|
|
26
|
|
||
Total Rabbi Trust Assets
|
|
$
|
71
|
|
|
$
|
88
|
|
Liability Under Related Deferred Compensation Plan
|
|
$
|
71
|
|
|
$
|
88
|
|
Number of Shares of Noble Energy Common Stock Held by Rabbi Trust
|
|
470,030
|
|
|
671,269
|
|
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, 2017
|
|
|
|
|
|
|
|
|
|
||||||||||
Financial Assets
|
|
|
|
|
|
|
|
|
|
||||||||||
Mutual Fund Investments
|
$
|
57
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
57
|
|
Commodity Derivative Instruments
|
—
|
|
|
7
|
|
|
—
|
|
|
(5
|
)
|
|
2
|
|
|||||
Financial Liabilities
|
|
|
|
|
|
|
|
|
|
||||||||||
Commodity Derivative Instruments
|
—
|
|
|
(78
|
)
|
|
—
|
|
|
5
|
|
|
(73
|
)
|
|||||
Portion of Deferred Compensation Liability Measured at Fair Value
|
(71
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(71
|
)
|
|||||
Stock Based Compensation Liability Measured at Fair Value
|
(10
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(10
|
)
|
|||||
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
|
)
|
(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, 2017
|
|
|
|
|
|
|
|
|
|||||||||||
Impaired Oil and Gas Properties
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
70
|
|
|
$
|
70
|
|
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
|
|
(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,
2017 |
|
December 31,
2016 |
||||||||||||
(millions)
|
Carrying Amount
|
|
Fair Value
|
|
Carrying Amount
|
|
Fair Value
|
||||||||
Long-Term Debt, Net
(1)
|
$
|
6,586
|
|
|
$
|
7,142
|
|
|
$
|
6,739
|
|
|
$
|
7,112
|
|
(1)
|
Excludes unamortized discount, premium, debt issuance costs and capital lease obligations.
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
|
Oil and Gas Exploration and Production
|
|
Midstream
|
|
|
||||||||||||||||||||||||
(In millions)
|
Consolidated
|
|
United
States |
|
Eastern
Mediter- ranean |
|
West
Africa |
|
Other Int'l
|
|
United States
|
|
Intersegment Eliminations and Other
(1)
|
|
Corporate
|
||||||||||||||||
Year Ended December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
Oil, NGL and Gas Sales from Third Parties
(2)
|
$
|
4,060
|
|
|
$
|
3,156
|
|
|
$
|
534
|
|
|
$
|
370
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Income from Equity Method Investees and Other
(3)
|
196
|
|
|
—
|
|
|
—
|
|
|
120
|
|
|
—
|
|
|
76
|
|
|
—
|
|
|
—
|
|
||||||||
Intersegment Revenues
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
277
|
|
|
(277
|
)
|
|
—
|
|
||||||||
Total Revenues
|
4,256
|
|
|
3,156
|
|
|
534
|
|
|
490
|
|
|
—
|
|
|
353
|
|
|
(277
|
)
|
|
—
|
|
||||||||
Lease Operating Expense
|
571
|
|
|
466
|
|
|
29
|
|
|
90
|
|
|
—
|
|
|
—
|
|
|
(14
|
)
|
|
—
|
|
||||||||
Production and Ad Valorem Taxes
|
138
|
|
|
135
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
—
|
|
|
—
|
|
||||||||
Gathering, Transportation and Processing Expense
|
432
|
|
|
550
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
70
|
|
|
(188
|
)
|
|
—
|
|
||||||||
Total Production Expense
|
1,141
|
|
|
1,151
|
|
|
29
|
|
|
90
|
|
|
—
|
|
|
73
|
|
|
(202
|
)
|
|
—
|
|
||||||||
DD&A
|
2,053
|
|
|
1,739
|
|
|
76
|
|
|
146
|
|
|
4
|
|
|
30
|
|
|
(5
|
)
|
|
63
|
|
||||||||
Clayton Williams Energy Acquisition Expenses
|
100
|
|
|
100
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Loss on Debt Extinguishment
|
98
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
98
|
|
||||||||
Loss on Marcellus Shale Upstream Divestiture
|
2,379
|
|
|
2,379
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Asset Impairments
|
70
|
|
|
63
|
|
|
—
|
|
|
—
|
|
|
7
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Gain on Commodity Derivative Instruments
|
(63
|
)
|
|
(92
|
)
|
|
—
|
|
|
29
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
(Loss) Income Before Income Taxes
|
(2,191
|
)
|
|
(2,365
|
)
|
|
413
|
|
|
203
|
|
|
(54
|
)
|
|
233
|
|
|
(62
|
)
|
|
(559
|
)
|
||||||||
Equity Method Investments
|
305
|
|
|
—
|
|
|
—
|
|
|
225
|
|
|
—
|
|
|
80
|
|
|
—
|
|
|
—
|
|
||||||||
Additions to Long Lived Assets
|
2,851
|
|
|
1,994
|
|
|
411
|
|
|
34
|
|
|
(34
|
)
|
|
423
|
|
|
(79
|
)
|
|
102
|
|
||||||||
Goodwill
(4)
|
1,310
|
|
|
1,310
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Total Assets at End of Year
(5)
|
21,476
|
|
|
15,767
|
|
|
2,846
|
|
|
1,308
|
|
|
114
|
|
|
1,357
|
|
|
(163
|
)
|
|
247
|
|
||||||||
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Oil, NGL and Gas Sales from Third Parties
(2)
|
$
|
3,389
|
|
|
$
|
2,416
|
|
|
$
|
540
|
|
|
$
|
433
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Income from Equity Method Investees and Other
|
102
|
|
|
—
|
|
|
—
|
|
|
50
|
|
|
—
|
|
|
52
|
|
|
—
|
|
|
—
|
|
||||||||
Intersegment Revenues
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
200
|
|
|
(200
|
)
|
|
—
|
|
||||||||
Total Revenues
|
3,491
|
|
|
2,416
|
|
|
540
|
|
|
483
|
|
|
—
|
|
|
252
|
|
|
(200
|
)
|
|
—
|
|
||||||||
Lease Operating Expense
|
542
|
|
|
418
|
|
|
37
|
|
|
105
|
|
|
—
|
|
|
—
|
|
|
(18
|
)
|
|
—
|
|
||||||||
Production and Ad Valorem Taxes
|
78
|
|
|
76
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
—
|
|
||||||||
Gathering, Transportation and Processing Expense
|
480
|
|
|
564
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
44
|
|
|
(128
|
)
|
|
—
|
|
||||||||
Total Production Expense
|
1,100
|
|
|
1,058
|
|
|
37
|
|
|
105
|
|
|
—
|
|
|
46
|
|
|
(146
|
)
|
|
—
|
|
||||||||
DD&A
|
2,454
|
|
|
2,103
|
|
|
81
|
|
|
205
|
|
|
6
|
|
|
19
|
|
|
—
|
|
|
40
|
|
||||||||
Asset Impairments
|
92
|
|
|
—
|
|
|
88
|
|
|
—
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Loss on Commodity Derivative Instruments
|
139
|
|
|
126
|
|
|
—
|
|
|
13
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
||||||||
(Loss) Income Before Income Taxes
|
(1,772
|
)
|
|
(1,277
|
)
|
|
543
|
|
|
(338
|
)
|
|
(199
|
)
|
|
176
|
|
|
(51
|
)
|
|
(626
|
)
|
||||||||
Equity Method Investments
|
400
|
|
|
—
|
|
|
—
|
|
|
217
|
|
|
—
|
|
|
183
|
|
|
—
|
|
|
—
|
|
||||||||
Additions to Long Lived Assets
|
1,526
|
|
|
1,353
|
|
|
88
|
|
|
54
|
|
|
(6
|
)
|
|
58
|
|
|
(53
|
)
|
|
32
|
|
||||||||
Total Assets at End of Year
(5)
|
21,011
|
|
|
16,153
|
|
|
2,233
|
|
|
1,479
|
|
|
89
|
|
|
851
|
|
|
(98
|
)
|
|
304
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
|
Oil and Gas Exploration and Production
|
|
Midstream
|
|
|
||||||||||||||||||||||||
(In millions)
|
Consolidated
|
|
United
States |
|
Eastern
Mediter- ranean |
|
West
Africa |
|
Other Int'l
|
|
United States
|
|
Intersegment Eliminations and Other
(1)
|
|
Corporate
|
||||||||||||||||
Year Ended December 31, 2015
|
|||||||||||||||||||||||||||||||
Oil, NGL and Gas Sales from Third Parties
(2)
|
$
|
3,093
|
|
|
$
|
2,011
|
|
|
$
|
497
|
|
|
$
|
580
|
|
|
$
|
5
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Income from Equity Method Investees and Other
|
90
|
|
|
—
|
|
|
—
|
|
|
39
|
|
|
—
|
|
|
51
|
|
|
—
|
|
|
—
|
|
||||||||
Intersegment Revenues
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
119
|
|
|
(119
|
)
|
|
—
|
|
||||||||
Total Revenues
|
3,183
|
|
|
2,011
|
|
|
497
|
|
|
619
|
|
|
5
|
|
|
170
|
|
|
(119
|
)
|
|
—
|
|
||||||||
Lease Operating Expense
|
563
|
|
|
398
|
|
|
42
|
|
|
131
|
|
|
4
|
|
|
—
|
|
|
(12
|
)
|
|
—
|
|
||||||||
Production and Ad Valorem Taxes
|
127
|
|
|
126
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
||||||||
Gathering, Transportation and Processing Expense
|
306
|
|
|
366
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
25
|
|
|
(85
|
)
|
|
—
|
|
||||||||
Total Production Expense
|
996
|
|
|
890
|
|
|
42
|
|
|
131
|
|
|
4
|
|
|
26
|
|
|
(97
|
)
|
|
—
|
|
||||||||
DD&A
|
2,131
|
|
|
1,677
|
|
|
70
|
|
|
326
|
|
|
—
|
|
|
14
|
|
|
—
|
|
|
44
|
|
||||||||
Asset Impairments
|
533
|
|
|
158
|
|
|
36
|
|
|
339
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Gain on Commodity Derivative Instruments
|
(501
|
)
|
|
(347
|
)
|
|
—
|
|
|
(154
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
(Loss) Income Before Income Taxes
|
(2,219
|
)
|
|
(1,693
|
)
|
|
313
|
|
|
(90
|
)
|
|
(229
|
)
|
|
123
|
|
|
(21
|
)
|
|
(622
|
)
|
||||||||
Equity Method Investments
|
453
|
|
|
—
|
|
|
—
|
|
|
227
|
|
|
—
|
|
|
226
|
|
|
—
|
|
|
—
|
|
||||||||
Additions to Long Lived Assets
|
3,062
|
|
|
2,409
|
|
|
147
|
|
|
124
|
|
|
177
|
|
|
146
|
|
|
(21
|
)
|
|
80
|
|
||||||||
Total Assets at End of Year
(5)
|
24,196
|
|
|
18,043
|
|
|
2,676
|
|
|
2,299
|
|
|
205
|
|
|
799
|
|
|
(46
|
)
|
|
220
|
|
(1)
|
Intersegment eliminations related to (loss) income before income taxes are the result of Midstream expenditures. These costs are presented as property, plant and equipment within the E&P business on an unconsolidated basis, in accordance with the successful efforts method of accounting, and are eliminated upon consolidation.
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
Percentage of Crude Oil Sales
|
|
Percentage of Total Oil, Gas & NGL Sales
|
||
Year Ended December 31, 2017
|
|
|
|
|
||
BP
(1)
|
|
15
|
%
|
|
10
|
%
|
Shell
(2)
|
|
22
|
%
|
|
13
|
%
|
Year Ended December 31, 2016
|
|
|
|
|
||
Glencore Energy UK Ltd
|
|
22
|
%
|
|
12
|
%
|
Shell
(2)
|
|
24
|
%
|
|
13
|
%
|
Year Ended December 31, 2015
|
|
|
|
|
||
Glencore Energy UK Ltd
|
|
30
|
%
|
|
18
|
%
|
Shell
(2)
|
|
18
|
%
|
|
11
|
%
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
Year Ended December 31,
|
||||
|
|
2017
|
|
2016
|
||
Common Stock Shares Issued
|
|
|
|
|
|
|
Shares, Beginning of Period
|
|
471,360,427
|
|
|
469,718,512
|
|
Exercise of Common Stock Options
|
|
382,882
|
|
|
954,898
|
|
Restricted Stock Awarded, Net of Forfeitures
(1)
|
|
2,912,936
|
|
|
687,017
|
|
Shares Exchanged in Clayton Williams Energy Acquisition
|
|
54,087,136
|
|
|
—
|
|
Shares, End of Period
|
|
528,743,381
|
|
|
471,360,427
|
|
Treasury Stock
|
|
|
|
|
|
|
Shares, Beginning of Period
|
|
37,961,316
|
|
|
37,925,625
|
|
Shares Received in Payment of Withholding Taxes Due on Vesting of Shares of Restricted Stock
(2)
|
|
1,026,891
|
|
|
236,700
|
|
Rabbi Trust Shares Distributed and/or Sold
|
|
(201,238
|
)
|
|
(201,009
|
)
|
Shares, End of Period
|
|
38,786,969
|
|
|
37,961,316
|
|
Additional Information
|
|
|
|
|
||
Incremental Shares From Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust
(2)
|
|
—
|
|
|
—
|
|
Number of Antidilutive Stock Options, Shares of Restricted Stock and Shares of Common Stock in Rabbi Trust excluded from Dilutive Loss per Share
|
|
15,619,276
|
|
|
14,218,319
|
|
(1)
|
The 2017 amount includes approximately
1.9 million
shares of restricted stock awarded to former holders of Clayton Williams Energy outstanding stock awards as part of the Clayton Williams Energy Acquisition. See
Note
3. Clayton Williams Energy Acquisition
.
|
(2)
|
The 2017 amount includes approximately
720,000
shares of common stock from Clayton Williams Energy shareholders for the payment of withholding taxes due on the vesting of Clayton Williams Energy restricted shares and options pursuant to the purchase and sale agreement.
|
(3)
|
For the years ended December 31, 2017 and 2016, 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.
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
Accumulated Other Comprehensive Loss
|
|||||||||||
(millions)
|
|
Interest Rate
Cash Flow
Hedges
|
|
Pension-
Related and
Other
|
|
Total
|
||||||
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
|
)
|
|||
Realized Amounts Reclassified Into Earnings
|
|
1
|
|
|
4
|
|
|
5
|
|
|||
Unrealized Change in Fair Value
|
|
—
|
|
|
(4
|
)
|
|
(4
|
)
|
|||
December 31, 2017
|
|
$
|
(20
|
)
|
|
$
|
(10
|
)
|
|
$
|
(30
|
)
|
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
|
||||||||||
2018
|
|
$
|
636
|
|
|
$
|
215
|
|
|
$
|
44
|
|
|
$
|
74
|
|
|
$
|
969
|
|
2019
|
|
167
|
|
|
252
|
|
|
33
|
|
|
45
|
|
|
497
|
|
|||||
2020
|
|
40
|
|
|
247
|
|
|
32
|
|
|
42
|
|
|
361
|
|
|||||
2021
|
|
13
|
|
|
223
|
|
|
32
|
|
|
29
|
|
|
297
|
|
|||||
2022
|
|
8
|
|
|
182
|
|
|
33
|
|
|
21
|
|
|
244
|
|
|||||
2023 and Thereafter
|
|
32
|
|
|
1,355
|
|
|
156
|
|
|
124
|
|
|
1,667
|
|
|||||
Total
|
|
$
|
896
|
|
|
$
|
2,474
|
|
|
$
|
330
|
|
|
$
|
335
|
|
|
$
|
4,035
|
|
(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
|
|
Israel
|
|
Total
|
||||
Proved Reserves as of:
|
|
|
|
|
|
|
|
|
||||
December 31, 2014
|
|
236
|
|
|
65
|
|
|
3
|
|
|
304
|
|
Revisions of Previous Estimates
(1)
|
|
(56
|
)
|
|
(5
|
)
|
|
—
|
|
|
(61
|
)
|
Extensions, Discoveries and Other Additions
(2)
|
|
42
|
|
|
—
|
|
|
—
|
|
|
42
|
|
Purchase of Minerals in Place
(3)
|
|
65
|
|
|
—
|
|
|
—
|
|
|
65
|
|
Sale of Minerals in Place
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
Production
(5)
|
|
(29
|
)
|
|
(12
|
)
|
|
—
|
|
|
(41
|
)
|
December 31, 2015
|
|
256
|
|
|
48
|
|
|
3
|
|
|
307
|
|
Revisions of Previous Estimates
(1)
|
|
14
|
|
|
(4
|
)
|
|
—
|
|
|
10
|
|
Extensions, Discoveries and Other Additions
(2)
|
|
66
|
|
|
—
|
|
|
—
|
|
|
66
|
|
Sale of Minerals in Place
|
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
Production
(5)
|
|
(36
|
)
|
|
(10
|
)
|
|
—
|
|
|
(46
|
)
|
December 31, 2016
|
|
296
|
|
|
34
|
|
|
3
|
|
|
333
|
|
Revisions of Previous Estimates
(1)
|
|
29
|
|
|
2
|
|
|
—
|
|
|
31
|
|
Extensions, Discoveries and Other Additions
(2)
|
|
104
|
|
|
—
|
|
|
6
|
|
|
110
|
|
Purchase of Minerals in Place
(3)
|
|
43
|
|
|
—
|
|
|
—
|
|
|
43
|
|
Sale of Minerals in Place
(4)
|
|
(12
|
)
|
|
—
|
|
|
—
|
|
|
(12
|
)
|
Production
(5)
|
|
(41
|
)
|
|
(7
|
)
|
|
—
|
|
|
(48
|
)
|
December 31, 2017
|
|
419
|
|
|
29
|
|
|
9
|
|
|
457
|
|
Proved Developed Reserves as of:
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2014
|
|
119
|
|
|
52
|
|
|
3
|
|
|
174
|
|
December 31, 2015
|
|
137
|
|
|
34
|
|
|
3
|
|
|
174
|
|
December 31, 2016
|
|
138
|
|
|
34
|
|
|
3
|
|
|
175
|
|
December 31, 2017
|
|
176
|
|
|
29
|
|
|
3
|
|
|
208
|
|
Proved Undeveloped Reserves as of:
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2014
|
|
117
|
|
|
13
|
|
|
—
|
|
|
130
|
|
December 31, 2015
|
|
119
|
|
|
14
|
|
|
—
|
|
|
133
|
|
December 31, 2016
|
|
158
|
|
|
—
|
|
|
—
|
|
|
158
|
|
December 31, 2017
|
|
243
|
|
|
—
|
|
|
6
|
|
|
249
|
|
(1)
|
The 2015 US revisions were primarily associated with negative price revisions of 70 MMBbls to our onshore programs due to a decline in the 12-month average price of crude oil; partially offset by positive revisions of 14 MMBbls due to producing well performance and optimized lateral lengths in the Delaware Basin and Eagle Ford Shale. Equatorial Guinea revisions were associated with negative price revisions.
|
(2)
|
The 2015 increase in US reserves was attributable to DJ Basin development.
|
(3)
|
The 2015 increase was attributable to reserves acquired in the Rosetta Merger.
|
Noble Energy, Inc.
|
|
|
Supplemental Oil and Gas Information
|
|
|
|
(Unaudited)
|
|
(4)
|
In 2017, we sold the Marcellus Shale upstream assets and other non-strategic US onshore assets.
|
(5)
|
Equatorial Guinea production included sales from Alba Plant of approximately
1
MMBbl in 2017 and
3
MMBbl in each of the years 2016 and 2015.
|
Noble Energy, Inc.
|
|
|
Supplemental Oil and Gas Information
|
|
|
|
(Unaudited)
|
|
|
|
NGLs (MMBbls)
|
|||||||
|
|
United
States
|
|
Equatorial
Guinea
|
|
Total
|
|||
Proved Reserves as of:
|
|
|
|
|
|
|
|||
December 31, 2014
|
|
113
|
|
|
15
|
|
|
128
|
|
Revisions of Previous Estimates
(1)
|
|
(37
|
)
|
|
—
|
|
|
(37
|
)
|
Extensions, Discoveries and Other Additions
(2)
|
|
15
|
|
|
—
|
|
|
15
|
|
Purchase of Minerals in Place
(3)
|
|
100
|
|
|
—
|
|
|
100
|
|
Sale of Minerals in Place
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
Production
(4)
|
|
(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
|
|
Sale of Minerals in Place
|
|
—
|
|
|
—
|
|
|
—
|
|
Production
(4)
|
|
(20
|
)
|
|
(2
|
)
|
|
(22
|
)
|
December 31, 2016
|
|
207
|
|
|
12
|
|
|
219
|
|
Revisions of Previous Estimates
(1)
|
|
31
|
|
|
1
|
|
|
32
|
|
Extensions, Discoveries and Other Additions
(2)
|
|
32
|
|
|
—
|
|
|
32
|
|
Purchase of Minerals in Place
(3)
|
|
7
|
|
|
—
|
|
|
7
|
|
Sale of Minerals in Place
(5)
|
|
(38
|
)
|
|
—
|
|
|
(38
|
)
|
Production
(4)
|
|
(21
|
)
|
|
(2
|
)
|
|
(23
|
)
|
December 31, 2017
|
|
218
|
|
|
11
|
|
|
229
|
|
Proved Developed Reserves as of:
|
|
|
|
|
|
|
|
|
|
December 31, 2014
|
|
64
|
|
|
8
|
|
|
72
|
|
December 31, 2015
|
|
101
|
|
|
5
|
|
|
106
|
|
December 31, 2016
|
|
113
|
|
|
12
|
|
|
125
|
|
December 31, 2017
|
|
119
|
|
|
11
|
|
|
130
|
|
Proved Undeveloped Reserves as of:
|
|
|
|
|
|
|
|||
December 31, 2014
|
|
49
|
|
|
7
|
|
|
56
|
|
December 31, 2015
|
|
75
|
|
|
8
|
|
|
83
|
|
December 31, 2016
|
|
94
|
|
|
—
|
|
|
94
|
|
December 31, 2017
|
|
99
|
|
|
—
|
|
|
99
|
|
(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; partially offset by a positive revision from our Marcellus Shale program due to positive well performance.
|
(2)
|
The 2015 additions included 14 MMBbls due to positive producing well performance and optimized lateral lengths in the DJ Basin.
|
Noble Energy, Inc.
|
|
|
Supplemental Oil and Gas Information
|
|
|
|
(Unaudited)
|
|
Noble Energy, Inc.
|
|
|
Supplemental Oil and Gas Information
|
|
|
|
(Unaudited)
|
|
|
|
Natural Gas and Casinghead Gas (Bcf)
|
||||||||||
|
|
United States
|
|
Israel
(1)
|
|
Equatorial Guinea
|
|
Total
|
||||
Proved Reserves as of:
|
|
|
|
|
|
|
|
|
||||
December 31, 2014
|
|
2,804
|
|
|
2,416
|
|
|
613
|
|
|
5,833
|
|
Revisions of Previous Estimates
(2)
|
|
(705
|
)
|
|
(20
|
)
|
|
4
|
|
|
(721
|
)
|
Extensions, Discoveries and Other Additions
(3)
|
|
257
|
|
|
—
|
|
|
—
|
|
|
257
|
|
Purchase of Minerals in Place
(4)
|
|
629
|
|
|
—
|
|
|
—
|
|
|
629
|
|
Sale of Minerals in Place
|
|
(16
|
)
|
|
—
|
|
|
—
|
|
|
(16
|
)
|
Production
|
|
(258
|
)
|
|
(92
|
)
|
|
(83
|
)
|
|
(433
|
)
|
December 31, 2015
|
|
2,711
|
|
|
2,304
|
|
|
534
|
|
|
5,549
|
|
Revisions of Previous Estimates
(2)
|
|
181
|
|
|
(3
|
)
|
|
38
|
|
|
216
|
|
Extensions, Discoveries and Other Additions
(3)
|
|
492
|
|
|
—
|
|
|
—
|
|
|
492
|
|
Purchase of Minerals in Place
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Sale of Minerals in Place
(5)
|
|
(224
|
)
|
|
(214
|
)
|
|
—
|
|
|
(438
|
)
|
Production
|
|
(322
|
)
|
|
(103
|
)
|
|
(86
|
)
|
|
(511
|
)
|
December 31, 2016
|
|
2,838
|
|
|
1,984
|
|
|
486
|
|
|
5,308
|
|
Revisions of Previous Estimates
(2)
|
|
124
|
|
|
292
|
|
|
13
|
|
|
429
|
|
Extensions, Discoveries and Other Additions
(3)
|
|
299
|
|
|
3,271
|
|
|
—
|
|
|
3,570
|
|
Purchase of Minerals in Place
(4)
|
|
46
|
|
|
—
|
|
|
—
|
|
|
46
|
|
Sale of Minerals in Place
(5)
|
|
(1,264
|
)
|
|
—
|
|
|
(1
|
)
|
|
(1,265
|
)
|
Production
|
|
(222
|
)
|
|
(99
|
)
|
|
(87
|
)
|
|
(408
|
)
|
December 31, 2017
|
|
1,821
|
|
|
5,448
|
|
|
411
|
|
|
7,680
|
|
Proved Developed Reserves as of:
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
December 31, 2017
|
|
983
|
|
|
1,793
|
|
|
411
|
|
|
3,187
|
|
Proved Undeveloped Reserves as of:
|
|
|
|
|
|
|
|
|
||||
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
|
|
December 31, 2017
|
|
838
|
|
|
3,655
|
|
|
—
|
|
|
4,493
|
|
(1)
|
In accordance with the terms of the Framework, we are required to reduce our ownership in the Tamar and Dalit fields from 36% to 25% by year-end 2021.
During 2016, we reduced our ownership to 32.5% through the sale of a 3.5% interest. At December 31, 2017, an additional 7.5% interest is included in assets held for sale. Proved reserves associated with the interest currently held for sale total approximately 502 Bcf, including 89 Bcf of PUDs, at December 31, 2017 and are included in the table above. In January 2018, we entered into an agreement to divest the 7.5% interest. See
Note 4. Acquisitions, Divestitures and Merger.
|
(2)
|
The 2015 US revisions were primarily associated with negative price revisions of 1.1 Tcf to our onshore programs due to a decline in the 12-month average price, offset by a positive revision primarily to our Marcellus Shale program due to positive well performance. Equatorial Guinea revisions were associated with positive performance revisions to the Alba field. Israel revisions were primarily associated with negative performance revisions in the Mari-B field.
|
Noble Energy, Inc.
|
|
|
Supplemental Oil and Gas Information
|
|
|
|
(Unaudited)
|
|
(3)
|
The 2015 increase in US reserves included an increase of 176 Bcf in the DJ Basin and 81 Bcf from Marcellus Shale development due to positive producing well performance and optimized lateral lengths.
|
(4)
|
The 2015 increase was attributable to reserves acquired in the Rosetta Merger.
|
(5)
|
In 2016, we sold US onshore assets in the DJ Basin and Eagle Ford Shale. We also executed an acreage exchange in the Marcellus Shale where we relinquished 185 Bcf, and we reduced our ownership in the Tamar field, offshore Israel.
|
Noble Energy, Inc.
|
|
|
Supplemental Oil and Gas Information
|
|
|
|
(Unaudited)
|
|
|
|
United
States
|
|
Israel
|
|
Equatorial
Guinea
|
|
Other
Int'l
|
|
Total
|
||||||||||
(millions)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Year Ended December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Revenues
|
|
$
|
3,156
|
|
|
$
|
534
|
|
|
$
|
370
|
|
|
$
|
—
|
|
|
$
|
4,060
|
|
Production Costs
(1)
|
|
1,199
|
|
|
49
|
|
|
103
|
|
|
2
|
|
|
1,353
|
|
|||||
Exploration Expense
|
|
102
|
|
|
—
|
|
|
1
|
|
|
85
|
|
|
188
|
|
|||||
DD&A
|
|
1,739
|
|
|
76
|
|
|
146
|
|
|
4
|
|
|
1,965
|
|
|||||
Loss on Marcellus Shale Upstream Divestiture
(2)
|
|
2,379
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,379
|
|
|||||
Asset Impairments
(3)
|
|
63
|
|
|
—
|
|
|
—
|
|
|
7
|
|
|
70
|
|
|||||
(Loss) Income before Income Taxes
|
|
(2,326
|
)
|
|
409
|
|
|
120
|
|
|
(98
|
)
|
|
(1,895
|
)
|
|||||
Income Tax Expense (Benefit)
(4)
|
|
(814
|
)
|
|
98
|
|
|
30
|
|
|
—
|
|
|
(686
|
)
|
|||||
Results of Operations
(5)
|
|
$
|
(1,512
|
)
|
|
$
|
311
|
|
|
$
|
90
|
|
|
$
|
(98
|
)
|
|
$
|
(1,209
|
)
|
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues
|
|
$
|
2,416
|
|
|
$
|
540
|
|
|
$
|
433
|
|
|
$
|
—
|
|
|
$
|
3,389
|
|
Production Costs
(1)
|
|
1,108
|
|
|
49
|
|
|
118
|
|
|
1
|
|
|
1,276
|
|
|||||
Exploration Expense
(6)
|
|
245
|
|
|
26
|
|
|
469
|
|
|
185
|
|
|
925
|
|
|||||
DD&A
|
|
2,103
|
|
|
81
|
|
|
205
|
|
|
6
|
|
|
2,395
|
|
|||||
Asset Impairments
(4)
|
|
—
|
|
|
88
|
|
|
—
|
|
|
4
|
|
|
92
|
|
|||||
(Loss) Income before Income Taxes
|
|
(1,040
|
)
|
|
296
|
|
|
(359
|
)
|
|
(196
|
)
|
|
(1,299
|
)
|
|||||
Income Tax Expense (Benefit)
(4)
|
|
(364
|
)
|
|
74
|
|
|
(90
|
)
|
|
—
|
|
|
(380
|
)
|
|||||
Results of Operations
(5)
|
|
$
|
(676
|
)
|
|
$
|
222
|
|
|
$
|
(269
|
)
|
|
$
|
(196
|
)
|
|
$
|
(919
|
)
|
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues
|
|
$
|
2,011
|
|
|
$
|
497
|
|
|
$
|
580
|
|
|
$
|
5
|
|
|
$
|
3,093
|
|
Production Costs
(1)
|
|
916
|
|
|
60
|
|
|
145
|
|
|
6
|
|
|
1,127
|
|
|||||
Exploration Expense
|
|
202
|
|
|
6
|
|
|
1
|
|
|
279
|
|
|
488
|
|
|||||
DD&A
|
|
1,677
|
|
|
70
|
|
|
326
|
|
|
—
|
|
|
2,073
|
|
|||||
Asset Impairments
(3)
|
|
158
|
|
|
36
|
|
|
339
|
|
|
—
|
|
|
533
|
|
|||||
Income (Loss) before Income Taxes
|
|
(942
|
)
|
|
325
|
|
|
(231
|
)
|
|
(280
|
)
|
|
(1,128
|
)
|
|||||
Income Tax Expense
(4)
|
|
(330
|
)
|
|
86
|
|
|
(58
|
)
|
|
(5
|
)
|
|
(307
|
)
|
|||||
Results of Operations
(5)
|
|
$
|
(612
|
)
|
|
$
|
239
|
|
|
$
|
(173
|
)
|
|
$
|
(275
|
)
|
|
$
|
(821
|
)
|
(1)
|
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.
|
(2)
|
(3)
|
2017 asset impairments relate primarily to the Gulf of Mexico Troubadour well.
|
(4)
|
Income tax expense is based upon respective corporate statutory tax rates. During 2017, 2016, and 2015, 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.
|
(5)
|
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
.
|
(6)
|
Equatorial Guinea exploration expense includes amounts related to the write off of costs associated with certain discoveries. See
Note
6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs
.
|
Noble Energy, Inc.
|
|
|
Supplemental Oil and Gas Information
|
|
|
|
(Unaudited)
|
|
|
|
United
States
|
|
Israel
|
|
Equatorial
Guinea
|
|
Other
Int'l
(1)
|
|
Total
|
||||||||||
(millions)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Property Acquisition Costs
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Proved
(2)
|
|
$
|
839
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
839
|
|
Unproved
(2)
|
|
1,817
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,817
|
|
|||||
Exploration Costs
(3)
|
|
59
|
|
|
6
|
|
|
4
|
|
|
90
|
|
|
159
|
|
|||||
Development Costs
(4)
|
|
1,870
|
|
|
483
|
|
|
33
|
|
|
(39
|
)
|
|
2,347
|
|
|||||
Total Consolidated Operations
|
|
$
|
4,585
|
|
|
$
|
489
|
|
|
$
|
37
|
|
|
$
|
51
|
|
|
$
|
5,162
|
|
December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Property Acquisition Costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Proved
(2)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Unproved
(2)
|
|
234
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
234
|
|
|||||
Exploration Costs
(4)
|
|
264
|
|
|
26
|
|
|
25
|
|
|
44
|
|
|
359
|
|
|||||
Development Costs
(4)
|
|
905
|
|
|
109
|
|
|
31
|
|
|
—
|
|
|
1,045
|
|
|||||
Total Consolidated Operations
|
|
$
|
1,403
|
|
|
$
|
135
|
|
|
$
|
56
|
|
|
$
|
44
|
|
|
$
|
1,638
|
|
December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Property Acquisition Costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Proved
(2)
|
|
$
|
1,613
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,613
|
|
Unproved
(2)
|
|
1,478
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
1,480
|
|
|||||
Exploration Costs
(3)
|
|
206
|
|
|
22
|
|
|
22
|
|
|
234
|
|
|
484
|
|
|||||
Development Costs
(4)
|
|
2,111
|
|
|
104
|
|
|
75
|
|
|
10
|
|
|
2,300
|
|
|||||
Total Consolidated Operations
|
|
$
|
5,408
|
|
|
$
|
126
|
|
|
$
|
97
|
|
|
$
|
246
|
|
|
$
|
5,877
|
|
(1)
|
Other International includes Newfoundland, Suriname, Falkland Islands, other new ventures and previous North Sea operations, which are in the process of being decommissioned.
|
(2)
|
2017 proved and unproved property acquisition costs include amounts allocated from the Clayton Williams Energy Acquisition (
See
Note
3. Clayton Williams Energy Acquisition
) and the Delaware Basin Acquisition (See
Note 4. Acquisitions, Divestitures and Merger
).
|
(3)
|
2017 exploration costs include primarily capitalized interest on Gulf of Mexico projects, and $7 million dry hole cost related to the Araku-1 exploration well, offshore Suriname. The remainder relates to seismic expense and drilling costs.
|
(4)
|
Worldwide development costs include amounts spent to develop PUDs of approximately
$1.2 billion
in 2017,
$656 million
in 2016, and
$1.5 billion
in 2015.
|
Noble Energy, Inc.
|
|
|
Supplemental Oil and Gas Information
|
|
|
|
(Unaudited)
|
|
|
|
December 31,
|
||||||
|
|
2017
|
|
2016
|
||||
(millions)
|
|
|
|
|
||||
Unproved Oil and Gas Properties
(1)
|
|
$
|
2,978
|
|
|
$
|
2,197
|
|
Proved Oil and Gas Properties
(2)
|
|
26,111
|
|
|
27,530
|
|
||
Total Oil and Gas Properties
|
|
29,089
|
|
|
29,727
|
|
||
Accumulated DD&A
|
|
(12,538
|
)
|
|
(12,265
|
)
|
||
Net Capitalized Costs
|
|
$
|
16,551
|
|
|
$
|
17,462
|
|
(1)
|
Unproved oil and gas property cost at December 31, 2017 include previous acquisition costs of
$1.6 billion
related to the Clayton Williams Energy Acquisition, and
$1.1 billion
and
$149 million
related to the Delaware Basin and Eagle Ford Shale properties.
|
(2)
|
Proved oil and gas properties at December 31, 2017 include asset retirement costs of $941 million and assets held for sale of
$448 million
.
|
Noble Energy, Inc.
|
|
|
Supplemental Oil and Gas Information
|
|
|
|
(Unaudited)
|
|
|
|
United
States
|
|
Israel
(1)
|
|
Equatorial
Guinea
|
|
Other
Int'l
(2)
|
|
Total
|
||||||||||
(millions)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Future Cash Inflows
(3)
|
|
$
|
30,061
|
|
|
$
|
29,998
|
|
|
$
|
2,028
|
|
|
$
|
—
|
|
|
$
|
62,087
|
|
Future Production Costs
(4)
|
|
(11,020
|
)
|
|
(2,517
|
)
|
|
(932
|
)
|
|
—
|
|
|
(14,469
|
)
|
|||||
Future Development Costs
(5)
|
|
(5,941
|
)
|
|
(1,706
|
)
|
|
(109
|
)
|
|
(51
|
)
|
|
(7,807
|
)
|
|||||
Future Income Tax Expense
(6)
|
|
(948
|
)
|
|
(13,088
|
)
|
|
(216
|
)
|
|
—
|
|
|
(14,252
|
)
|
|||||
Future Net Cash Flows
|
|
12,152
|
|
|
12,687
|
|
|
771
|
|
|
(51
|
)
|
|
25,559
|
|
|||||
10% Annual Discount for Estimated Timing of Cash Flows
|
|
(5,202
|
)
|
|
(8,993
|
)
|
|
(113
|
)
|
|
7
|
|
|
(14,301
|
)
|
|||||
Standardized Measure of Discounted Future Net Cash Flows
|
|
$
|
6,950
|
|
|
$
|
3,694
|
|
|
$
|
658
|
|
|
$
|
(44
|
)
|
|
$
|
11,258
|
|
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
|
|
(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
|
|
(1)
|
In accordance with the Framework, we are required to reduce our ownership in the Tamar and Dalit fields from 36% to 25% by year-end 2021.
During 2016, we reduced our ownership to 32.5% through the sale of a 3.5% interest. Therefore, amounts at December 31, 2017 and 2016 reflect a 32.5% working interest, while 2015 amounts reflect a 36% working interest. At December 31, 2017, 7.5% of our 32.5% interest is included in assets held for sale. The portion of the standardized measure of discounted future net cash flows included in the table above, and associated with the interest currently held for sale, totals approximately $650 million at December 31, 2017. See
Note 4. Acquisitions, Divestitures and Merger
. The 2017 increase in the standardized measure of discounted future net cash inflows relates primarily to the sanction of the first phase of development of the Leviathan field.
|
(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. As of December 31, 2017, US future income tax expense includes the expected impact of the recent Tax Reform Legislation. As of December 31, 2017, 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
|
|
Total
|
||||||||
December 31, 2017
|
|
|
|
|
|
|
|
|
||||||||
Average Crude Oil and Condensate Price per Bbl
|
|
$
|
47.81
|
|
|
$
|
46.82
|
|
|
$
|
53.12
|
|
|
$
|
48.13
|
|
Average Natural Gas Price per Mcf
|
|
2.83
|
|
|
5.43
|
|
|
0.27
|
|
|
4.54
|
|
||||
Average NGL Price per Bbl
|
|
22.32
|
|
|
—
|
|
|
37.23
|
|
|
23.02
|
|
||||
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
|
|
Noble Energy, Inc.
|
|
|
Supplemental Oil and Gas Information
|
|
|
|
(Unaudited)
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
(millions)
|
|
|
|
|
|
|
||||||
Standardized Measure of Discounted Future Net Cash Flows, Beginning of Year
|
|
$
|
5,686
|
|
|
$
|
6,628
|
|
|
$
|
13,979
|
|
Changes in Standardized Measure of Discounted Future Net Cash Flows
|
|
|
|
|
|
|
||||||
Sales of Oil and Gas Produced, Net of Production Costs
|
|
(2,674
|
)
|
|
(2,230
|
)
|
|
(2,026
|
)
|
|||
Net Changes in Prices and Production Costs
(1)
|
|
2,436
|
|
|
(593
|
)
|
|
(12,603
|
)
|
|||
Extensions, Discoveries and Improved Recovery, Less Related Costs
|
|
3,711
|
|
|
463
|
|
|
442
|
|
|||
Changes in Estimated Future Development Costs
|
|
(537
|
)
|
|
(373
|
)
|
|
1,135
|
|
|||
Development Costs Incurred During the Period
|
|
1,975
|
|
|
1,090
|
|
|
2,639
|
|
|||
Revisions of Previous Quantity Estimates
|
|
1,462
|
|
|
364
|
|
|
(1,051
|
)
|
|||
Purchases of Minerals in Place
(2)
|
|
423
|
|
|
161
|
|
|
2,747
|
|
|||
Sales of Minerals in Place
|
|
(643
|
)
|
|
(951
|
)
|
|
(46
|
)
|
|||
Accretion of Discount
|
|
778
|
|
|
919
|
|
|
1,789
|
|
|||
Net Change in Income Taxes
(3)
|
|
(1,669
|
)
|
|
414
|
|
|
2,075
|
|
|||
Change in Timing of Estimated Future Production and Other
(4)
|
|
310
|
|
|
(206
|
)
|
|
(2,452
|
)
|
|||
Aggregate Change in Standardized Measure of Discounted Future Net Cash Flows
|
|
$
|
5,572
|
|
|
$
|
(942
|
)
|
|
$
|
(7,351
|
)
|
Standardized Measure of Discounted Future Net Cash Flows, End of Year
|
|
$
|
11,258
|
|
|
$
|
5,686
|
|
|
$
|
6,628
|
|
(1)
|
The increase in 2017 and the decrease in 2015 were driven primarily by higher and lower, respectively, 12-month average commodity prices.
|
(2)
|
Purchase of minerals in 2017 relates to reserves acquired in the Clayton Williams Energy Acquisition.
|
(3)
|
The increase in 2017 future income tax expense relates primarily to the increase in profit and levy taxes in Israel, partially offset by the decrease in future corporate income tax rate in Israel. The increase in profits tax is driven by a significant increase in future cash flows related to the Leviathan project sanctioning in 2017. The increase in US tax expense due to the increase in future taxable income was offset by the decrease in tax expense associated with utilization of future net operating losses and decrease in applicable tax rate from 35% to 21% due to the changes in the US Tax Law effective January 1, 2018. 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.
|
Noble Energy, Inc.
|
|
|
Supplemental Quarterly Financial Information
|
|
|
|
(Unaudited)
|
|
|
|
Quarter Ended
|
||||||||||||||||||
|
|
March 31,
|
|
June 30,
|
|
Sep 30,
|
|
Dec 31,
|
|
Total
|
||||||||||
(millions except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
2017
(1) (3)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues
|
|
$
|
1,036
|
|
|
$
|
1,059
|
|
|
$
|
960
|
|
|
$
|
1,201
|
|
|
$
|
4,256
|
|
Income (Loss) Before Income Taxes
|
|
59
|
|
|
(2,334
|
)
|
|
(208
|
)
|
|
292
|
|
|
(2,191
|
)
|
|||||
Net Income (Loss)
|
|
47
|
|
|
(1,498
|
)
|
|
(115
|
)
|
|
516
|
|
|
(1,050
|
)
|
|||||
Less: Net Income Attributable to Noncontrolling Interests
|
|
11
|
|
|
14
|
|
|
21
|
|
|
22
|
|
|
68
|
|
|||||
Net Income (Loss) Attributable to Noble Energy
|
|
36
|
|
|
(1,512
|
)
|
|
(136
|
)
|
|
494
|
|
|
(1,118
|
)
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net Income (Loss) Per Share, Basic
|
|
0.08
|
|
|
(3.20
|
)
|
|
(0.28
|
)
|
|
1.01
|
|
|
(2.38
|
)
|
|||||
Net Income (Loss) Per Share, Diluted
|
|
0.08
|
|
|
(3.20
|
)
|
|
(0.28
|
)
|
|
1.01
|
|
|
(2.38
|
)
|
|||||
2016
(2) (3)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues
|
|
$
|
724
|
|
|
$
|
847
|
|
|
$
|
910
|
|
|
$
|
1,010
|
|
|
$
|
3,491
|
|
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
|
)
|
|||||
Net Loss Per Share, Basic and Diluted
|
|
(0.67
|
)
|
|
(0.73
|
)
|
|
(0.33
|
)
|
|
(0.59
|
)
|
|
(2.32
|
)
|
•
|
No unusual or infrequent activity.
|
•
|
$2.4 billion loss on Marcellus Shale upstream divestiture (See
Note
4. Acquisitions, Divestitures and Merger
).
|
•
|
$98 million loss on extinguishment of debt (See
Note 10. Long-Term Debt
).
|
•
|
$270 million deferred tax benefit, net, related to recent changes in federal income tax regulations; and
|
•
|
$334 million
gain on sale of mineral and royalty assets (See
Note
4. Acquisitions, Divestitures and Merger
).
|
•
|
$80 million gain on extinguishment of debt.
|
•
|
$25 million purchase price allocation adjustment related to Rosetta Merger (See
Note
4. Acquisitions, Divestitures and Merger
).
|
•
|
$81 million undeveloped leasehold impairment expense (See
Note
6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs
).
|
•
|
$579 million dry hole costs included in exploration expense (See
Note
6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs
); and
|
•
|
$92 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 (loss) as each quarterly computation is based on the earnings (loss) for the individual quarter as reported with rounding applied.
|
(a)
|
The following documents are filed as a part of this report:
|
(1)
|
Financial Statements: The consolidated financial statements and related notes, together with the reports of KPMG LLP, Independent Registered Public Accounting Firm, appear in Part II, Item 8, Financial Statements and Supplementary Data, of this Form 10-K.
|
(2)
|
Financial Statement Schedules: All schedules for which provision is made in the applicable accounting regulations of the SEC are not required under the related instruction or are inapplicable and, therefore, have been omitted.
|
(3)
|
Exhibits: The exhibits listed below on the Index to Exhibits are filed or incorporated by reference as part of this Form 10-K.
|
Exhibit Number
|
Exhibit **
|
|
2.1
|
—
|
|
2.2
|
—
|
|
2.3
|
—
|
|
2.4
|
—
|
|
2.5
|
—
|
|
2.6
|
—
|
|
3.1
|
—
|
|
3.2
|
—
|
|
3.3
|
—
|
|
3.4
|
—
|
|
4.1
|
—
|
|
4.2
|
—
|
|
4.3
|
—
|
|
4.4
|
—
|
|
4.5
|
—
|
|
4.6
|
—
|
|
4.7
|
—
|
|
4.8
|
—
|
Indenture dated as of October 14, 1993 between the Registrant and US Trust Company of Texas, N.A., as Trustee, relating to the Registrant’s 7¼% Notes Due 2023 (including the form of 2023 Notes) (filed in paper with the SEC as Exhibit 4.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1993 on November 12, 1993 and incorporated herein by reference).
|
4.9
|
—
|
|
4.10
|
—
|
|
4.11
|
—
|
|
10.1
|
—
|
|
10.2
|
—
|
|
10.3
|
—
|
|
10.4
|
—
|
|
10.5
|
—
|
|
10.6
|
—
|
|
10.7*
|
—
|
10.8*
|
—
|
|
10.9*
|
—
|
|
10.10*
|
—
|
Form of Indemnity Agreement entered into between the Registrant and each of the Registrant’s directors and bylaw officers (filed in paper with the SEC as Exhibit 10.18 to the Registrant’s Annual Report on Form 10-K405 for the year ended December 31, 1995 on March 25, 1996 (File No. 001-07964) and incorporated herein by reference).
|
10.11*
|
—
|
|
10.12*
|
—
|
|
10.13*
|
—
|
|
10.14*
|
—
|
|
10.15*
|
—
|
|
10.16*
|
—
|
|
10.17*
|
—
|
|
10.18*
|
—
|
|
10.19*
|
—
|
|
10.20*
|
—
|
|
10.21*
|
—
|
|
10.22*
|
—
|
|
10.23*
|
—
|
|
10.24*
|
—
|
|
10.25*
|
—
|
|
10.26*
|
—
|
10.27*
|
—
|
|
10.28*
|
—
|
|
10.29*
|
—
|
|
10.30*
|
—
|
|
10.31*
|
—
|
|
10.32*
|
—
|
|
10.33*
|
—
|
|
10.34*
|
—
|
|
10.35*
|
—
|
|
10.36*
|
—
|
|
10.37*
|
—
|
|
10.38*
|
—
|
|
10.39*
|
—
|
|
10.40*
|
—
|
|
10.41*
|
—
|
|
10.42*
|
—
|
|
10.43*
|
—
|
|
10.44*
|
—
|
|
10.45*
|
—
|
10.46*
|
—
|
|
10.47
|
—
|
|
10.48
|
—
|
|
10.49*
|
—
|
|
10.50
|
—
|
|
10.51
|
—
|
|
10.52
|
—
|
|
10.53†
|
—
|
|
12.1
|
—
|
|
21
|
—
|
|
23.1
|
—
|
|
23.2
|
—
|
|
31.1
|
—
|
|
31.2
|
—
|
|
32.1
|
—
|
|
32.2
|
—
|
|
99.1
|
—
|
|
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.
|
†
|
Confidential treatment granted under Rule 24b-2 as to certain portions of this exhibit, which are omitted and filed separately with the Commission.
|
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
|
GHG
|
|
Greenhouse gas emissions
|
GSPA
|
|
Gas Sales Purchase Agreement
|
HH
|
|
Henry Hub index
|
IDP
|
|
Integrated Development Plan
|
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
|
NGLs
|
|
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.
|
|
|
(Registrant)
|
|
|
|
Date:
|
February 20, 2018
|
By: /s/ David L. Stover
|
|
|
David L. Stover,
|
|
|
Chairman of the Board, President and Chief Executive Officer
|
|
|
|
Date:
|
February 20, 2018
|
By: /s/ Kenneth M. Fisher
|
|
|
Kenneth M. Fisher,
|
|
|
Executive Vice President, Chief Financial Officer
|
|
|
|
Date:
|
February 20, 2018
|
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 20, 2018
|
David L. Stover
|
|
(Principal Executive Officer)
|
|
|
|
|
|
|
|
/s/ Kenneth M. Fisher
|
|
Executive Vice President, Chief Financial Officer
|
|
February 20, 2018
|
Kenneth M. Fisher
|
|
(Principal Financial Officer)
|
|
|
|
|
|
|
|
/s/ Dustin A. Hatley
|
|
Vice President, Chief Accounting Officer and Controller
|
|
February 20, 2018
|
Dustin A. Hatley
|
|
(Principal Accounting Officer)
|
|
|
|
|
|
|
|
/s/ Jeffrey L. Berenson
|
|
Director
|
|
February 20, 2018
|
Jeffrey L. Berenson
|
|
|
|
|
|
|
|
|
|
/s/ Michael A. Cawley
|
|
Director
|
|
February 20, 2018
|
Michael A. Cawley
|
|
|
|
|
|
|
|
|
|
/s/ Edward F. Cox
|
|
Director
|
|
February 20, 2018
|
Edward F. Cox
|
|
|
|
|
|
|
|
|
|
/s/ James E. Craddock
|
|
Director
|
|
February 20, 2018
|
James E. Craddock
|
|
|
|
|
|
|
|
|
|
/s/ Thomas J. Edelman
|
|
Director
|
|
February 20, 2018
|
Thomas J. Edelman
|
|
|
|
|
|
|
|
|
|
/s/ Kirby L. Hedrick
|
|
Director
|
|
February 20, 2018
|
Kirby L. Hedrick
|
|
|
|
|
|
|
|
|
|
/s/ Holli C. Ladhani
|
|
Director
|
|
February 20, 2018
|
Holli C. Ladhani
|
|
|
|
|
|
|
|
|
|
/s/ Scott D. Urban
|
|
Director
|
|
February 20, 2018
|
Scott D. Urban
|
|
|
|
|
|
|
|
|
|
/s/ William T. Van Kleef
|
|
Director
|
|
February 20, 2018
|
William T. Van Kleef
|
|
|
|
|
|
|
|
|
|
/s/ Molly K. Williamson
|
|
Director
|
|
February 20, 2018
|
Molly K. Williamson
|
|
|
|
|
A.
|
Outside Date
. The Outside Date shall be 5:00 p.m., Houston time, on June 30, 2018 (the “
New Outside Date
”) and Section 7.1(b)(i) of the Purchase Agreement shall be deemed amended to reflect the New Outside Date.
|
B.
|
Deposit
.
|
1.
|
The amount of the Deposit as defined in Section 1.3(a) of the Purchase Agreement shall be $5,000,000 (the “
New Deposit Amount
”).
|
2.
|
In any event, the Deposit shall be returned to Buyer upon the earlier to occur of (i) the New Outside Date and (ii) termination of the Purchase Agreement for any reason, free and clear of any claims thereon by Seller.
|
3.
|
Upon execution of this letter agreement, and as a condition to the effectiveness of this letter agreement with respect to Buyer, Buyer and Noble Holdings shall execute and deliver Joint Instructions to the Bank, instructing the Bank to disburse (by wire transfer of immediately available funds in Dollars to an account designated by Buyer) all amounts in the Deposit Account other than the New Deposit Amount, which funds shall be disbursed free and clear of any claims thereon by Seller.
|
4.
|
Notwithstanding the foregoing, references in Section 7.3(c) of the Purchase Agreement to “the amount of the Deposit” shall be deemed to continue to refer to $38,250,000.
|
C.
|
Seller Discussions
.
|
1.
|
Section 5.14 of the Purchase Agreement shall be deleted in its entirety and replaced with the following: “[Reserved]”.
|
2.
|
Without limiting the other provisions of the Purchase Agreement, Seller, Seller’s Affiliates and its and their Representatives may discuss and negotiate with, and furnish information to, CNX Gas Company LLC and its Affiliates (collectively, the “
CONSOL Parties
”) and its and their Representatives, with respect to a settlement of the CONSOL Litigation and certain other disputes (which may include discussions and negotiations with respect to a potential sale of the CONE Interests and/or Subject Units) and a potential reorganization or other business restructuring of CONE Gathering, the General Partner and the Partnership Entities;
provided
, that Seller shall keep Buyer reasonably apprised of all such discussions and negotiations with the CONSOL Parties.
|
3.
|
At any time while the Purchase Agreement is in effect, if Seller desires to enter into a
bona fide
definitive written agreement with a CONSOL Party regarding terms of a settlement or other transaction with the CONSOL Parties, and such settlement or other transaction involves the direct or indirect sale, transfer or other disposition of the interests of Seller or its Affiliates with respect to the NBLM Interests, CONE Interests, General Partner Interest or Subject Units to the CONSOL Parties, Seller shall have the right to terminate the Purchase Agreement upon entry into such definitive agreement by written notice delivered to Buyer.
|
D.
|
Closing
. In addition to the obligations of Buyer to consummate the transactions contemplated by the Purchase Agreement being subject to the fulfillment, at or prior to the Closing, of the conditions set forth in Section 6.1 of the Purchase Agreement and each of the conditions in Section 6.2 of the Purchase Agreement being met or waived by Buyer, Buyer’s obligation is also subject to (and Section 6.2 of the Purchase Agreement will be deemed amended to include) the restructuring with respect to the governance, operational and economic structure of CONE Gathering, the General Partner and the Partnership Entities in a manner acceptable to Buyer in its sole discretion.
|
E.
|
Miscellaneous
. Article IX of the Purchase Agreement is hereby incorporated by reference herein
mutatis mutandis
. The provisions of this letter agreement shall be deemed agreements and covenants for all purposes under the Purchase Agreement. Further, this letter agreement shall be deemed an amendment of the Purchase Agreement; provided that, other than as expressly set forth in this letter agreement, this letter agreement shall not constitute an amendment or waiver of any provisions of the Transaction Documents and shall not abrogate or modify any Party’s rights or claims with respect to the Transaction Documents or transactions contemplated thereby (which such rights and claims are expressly reserved), and each Transaction Document, as specifically modified by this letter agreement, shall continue to be in full force and effect.
|
|
|
|
Sincerely,
|
|
|
|
|
|
|
|
|
|
Wheeling Creek Midstream, LLC
|
|
|
|
|
|
|
|
|
|
By:
/s/ Dheeraj Verma
|
|
|
|
|
Name: Dheeraj Verma
|
|
|
|
|
Title:
|
|
|
|
|
|
|
|
|
|
|
|
Noble Energy, Inc.
|
||||||||||||||||||||
Calculation of Ratio of Earnings to Fixed Charges
|
||||||||||||||||||||
|
|
Year Ended December 31,
|
||||||||||||||||||
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
||||||||||
(millions)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
(Loss) Income From Continuing Operations Before Income Tax, Non-controlling Interests and Income From Equity Investees
|
|
$
|
(2,436
|
)
|
|
$
|
(1,887
|
)
|
|
$
|
(2,309
|
)
|
|
$
|
1,540
|
|
|
$
|
1,138
|
|
Add (Deduct)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed Charges
|
|
426
|
|
|
440
|
|
|
435
|
|
|
349
|
|
|
296
|
|
|||||
Capitalized Interest
|
|
(49
|
)
|
|
(84
|
)
|
|
(144
|
)
|
|
(116
|
)
|
|
(121
|
)
|
|||||
Distributed Income From Equity Investees
|
|
139
|
|
|
83
|
|
|
77
|
|
|
226
|
|
|
204
|
|
|||||
Earnings as Defined
|
|
$
|
(1,920
|
)
|
|
$
|
(1,448
|
)
|
|
$
|
(1,941
|
)
|
|
$
|
1,999
|
|
|
$
|
1,517
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net Interest Expense
|
|
354
|
|
|
328
|
|
|
263
|
|
|
210
|
|
|
158
|
|
|||||
Capitalized Interest
|
|
49
|
|
|
84
|
|
|
144
|
|
|
116
|
|
|
121
|
|
|||||
Interest Portion of Rental Expense
|
|
23
|
|
|
28
|
|
|
28
|
|
|
23
|
|
|
17
|
|
|||||
Fixed Charges as Defined
|
|
$
|
426
|
|
|
$
|
440
|
|
|
$
|
435
|
|
|
$
|
349
|
|
|
$
|
296
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Ratio of Earnings to Fixed Charges
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5.7
|
|
|
5.1
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Amount by Which Earnings Were Insufficient to Cover Fixed Charges
|
|
$
|
2,346
|
|
|
$
|
1,888
|
|
|
$
|
2,376
|
|
|
$
|
—
|
|
|
$
|
—
|
|
NAME
|
|
JURISDICTION OF ORGANIZATION
|
Advantage Pipeline Holdings LLC*
|
|
Delaware
|
Advantage Pipeline Logistics LLC*
|
|
Texas
|
Advantage Pipeline Management, LLC*
|
|
Texas
|
Advantage Pipeline, L.L.C.*
|
|
Texas
|
Alba Associates LLC*
|
|
Cayman Islands
|
Alba Plant LLC*
|
|
Cayman Islands
|
AMPCO Marketing, L.L.C.*
|
|
Michigan
|
AMPCO Services, L.L.C.*
|
|
Michigan
|
Atlantic Methanol Associates LLC*
|
|
Cayman Islands
|
Atlantic Methanol Production Company LLC*
|
|
Cayman Islands
|
Atlantic Methanol Services B.V.*
|
|
Amsterdam
|
Black Diamond Gathering Holdings LLC
|
|
Delaware
|
Black Diamond Gathering LLC*
|
|
Delaware
|
Blanco River DevCo GP LLC
|
|
Delaware
|
Blanco River DevCo LP
|
|
Delaware
|
Clajon Industrial Gas, Inc. (fka Clayton Williams Company)
|
|
Texas
|
Clayton Williams Pipeline Corporation
|
|
Delaware
|
Colorado River DevCo GP LLC
|
|
Delaware
|
Colorado River DevCo LP
|
|
Delaware
|
CONE Midstream Partners LP*
|
|
Delaware
|
Desta Drilling GP, LLC (fka Larclay GP, LLC)
|
|
Texas
|
Desta Drilling, L.P. (fka Larclay L.P.)
|
|
Texas
|
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
|
Leviathan Transportation System Ltd.*
|
|
Tel Aviv
|
MachalaPower Cia. Ltda. (fka Samedan Power)
|
|
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 Jordan Marketing 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 NV 1 Holding LLC
|
|
Delaware
|
NBL NV 1 Limited
|
|
Cayman Islands
|
NBL NV 2 Holding LLC
|
|
Delaware
|
NBL NV 2 Limited
|
|
Cayman Islands
|
NBL Permian LLC
|
|
Delaware
|
NBL Permian Water LLC
|
|
Delaware
|
NBL Rhea Limited
|
|
Cayman Islands
|
NBL Suriname B.V.
|
|
Netherlands
|
NBL Texas, LLC
|
|
Delaware
|
NCWYO Assets LLC
|
|
Delaware
|
NEML Leviathan Finance Company Ltd.
|
|
Tel Aviv
|
Noble Energy (ISE) Limited
|
|
United Kingdom
|
Noble Energy (Oilex) Limited
|
|
United Kingdom
|
Noble Energy Cameroon Limited
|
|
Cayman Islands
|
Noble Energy Canada Inc. (fka Noble Energy Canada LLC)
|
|
Delaware
|
Noble Energy Canada ULC
|
|
British Columbia
|
Noble Energy Capital Limited
|
|
United Kingdom
|
Noble Energy Cyprus Midstream Holding LLC (fka NBL Cameroon Holding, 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.
|
|
Mexico
|
Noble Energy New Ventures, LLC (fka Noble Energy New Ventures, Inc.)
|
|
Delaware
|
Noble Energy Services, Inc.
|
|
Delaware
|
Noble Energy Sierra Leone Holdings, LLC
|
|
Delaware
|
Noble Energy SL Limited (fka Noble Energy Sierra Leone UK Limited)
|
|
United Kingdom
|
Noble Energy US Holdings, LLC
|
|
Delaware
|
Noble Energy WyCo, LLC
|
|
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
|
Romere Pass Acquisition L.L.C. (fka Romere Pass Acquisition Corp.)
|
|
Delaware
|
Rosetta Resources Holdings, LLC (fka Calpine Natural Gas Holdings, LLC)
|
|
Delaware
|
Rosetta Resources Michigan Limited Partnership (fka Rosetta Resources Gathering LP)
|
|
Delaware
|
Rosetta Resources Offshore, LLC
|
|
Delaware
|
Rosetta Resources Operating GP, LLC (fka Calpine Natural Gas GP, LLC)
|
|
Delaware
|
Rosetta Resources Operating LP (fka Calpine Natural Gas L.P.)
|
|
Delaware
|
Samedan Methanol
|
|
Cayman Islands
|
Samedan of North Africa, LLC (fka Samedan of North Africa, Inc.)
|
|
Delaware
|
Samedan Pipe Line Corporation
|
|
Delaware
|
San Juan River DevCo GP LLC
|
|
Delaware
|
San Juan River DevCo LP
|
|
Delaware
|
Seven Oaks Insurance Limited
|
|
Bermuda
|
Southwest Royalties, Inc.
|
|
Delaware
|
Tamar 10 Inch Pipeline Ltd.*
|
|
Tel Aviv
|
Tamar Mediterranean Gas Ltd.
|
|
Tel Aviv
|
Trinity River DevCo LLC
|
|
Delaware
|
Warrior Gas Co.
|
|
Texas
|
West Coast Energy Properties GP, LLC
|
|
Texas
|
White Star Insurance LLC
|
|
Texas
|
Yam Tethys Ltd*
|
|
Tel Aviv
|
|
|
|
|
|
NETHERLAND, SEWELL & ASSOCIATES, INC.
|
||
|
|
|
|
|
By:
|
/s/ Danny D. Simmons
|
|
|
|
Danny D. Simmons, P.E.
|
|
|
|
President and Chief Operating Officer
|
|
|
|
|
|
Houston, Texas
|
|
|
|
February 20, 2018
|
|
|
|
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 20, 2018
|
|
|
|
|
|
|
/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 20, 2018
|
|
|
|
|
|
|
/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 20, 2018
|
|
/s/ David L. Stover
|
|
|
|
David L. Stover
|
|
|
|
Chief Executive 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 20, 2018
|
|
/s/ Kenneth M. Fisher
|
|
|
|
Kenneth M. Fisher
|
|
|
|
Chief Financial Officer
|
|
|
Net Reserves
|
|||||||
|
|
Oil
|
|
NGL
|
|
Gas
|
|||
Category
|
|
(MBBL)
|
|
(MBBL)
|
|
(MMCF)
|
|||
|
|
|
|
|
|
|
|||
Proved Developed Producing
|
|
195,723.088
|
|
|
125,769.168
|
|
|
2,532,492.288
|
|
Proved Developed Non-Producing
|
|
11,218.954
|
|
|
3,989.500
|
|
|
654,366.768
|
|
Proved Undeveloped
|
|
249,766.624
|
|
|
98,829.936
|
|
|
4,493,593.600
|
|
|
|
|
|
|
|
|
|||
Total Proved
|
|
456,708.672
|
|
|
228,588.608
|
|
|
7,680,422.912
|
|