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
|
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 liquids (NGLs) and natural gas resources;
|
•
|
anticipated trends in our business;
|
•
|
market conditions in the oil and gas industry;
|
•
|
the impact of governmental regulation, including United States (US) federal, state, local, and foreign host government tax regulations, fiscal policies and terms, as well as that involving the protection of the environment or marketing of production and other regulations;
|
•
|
our ability to make and integrate acquisitions or execute divestitures; and
|
•
|
access to resources.
|
|
|
Crude Oil and
Condensate
|
|
NGLs
|
|
Natural Gas
|
|
Total
|
|||||||
Reserves Category
|
|
(MMBbls)
|
|
(MMBbls)
|
|
(Bcf)
|
|
(MMBoe)(1)
|
|
(Percent)
|
|||||
Proved Developed
|
|
|
|
|
|
|
|
|
|
|
|||||
United States
|
|
165
|
|
|
121
|
|
|
929
|
|
|
442
|
|
|
59
|
%
|
Israel
|
|
2
|
|
|
—
|
|
|
1,295
|
|
|
218
|
|
|
29
|
%
|
Equatorial Guinea
|
|
26
|
|
|
9
|
|
|
355
|
|
|
94
|
|
|
12
|
%
|
Total Proved Developed Reserves
|
|
193
|
|
|
130
|
|
|
2,579
|
|
|
754
|
|
|
100
|
%
|
Proved Undeveloped
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
United States
|
|
255
|
|
|
136
|
|
|
1,015
|
|
|
560
|
|
|
48
|
%
|
Israel
|
|
6
|
|
|
—
|
|
|
3,635
|
|
|
612
|
|
|
52
|
%
|
Equatorial Guinea
|
|
3
|
|
|
—
|
|
|
2
|
|
|
3
|
|
|
—
|
%
|
Total Proved Undeveloped Reserves
|
|
264
|
|
|
136
|
|
|
4,652
|
|
|
1,175
|
|
|
100
|
%
|
Total Proved Reserves
|
|
457
|
|
|
266
|
|
|
7,231
|
|
|
1,929
|
|
|
|
|
|
Year Ended December 31,
|
|||||||
(MMBoe)
|
|
2018
|
|
2017
|
|
2016
|
|||
Proved Reserves Beginning of Year
|
|
1,965
|
|
|
1,437
|
|
|
1,421
|
|
Revisions of Previous Estimates
|
|
(2
|
)
|
|
135
|
|
|
64
|
|
Extensions, Discoveries and Other Additions
|
|
223
|
|
|
736
|
|
|
179
|
|
Purchase of Minerals in Place
|
|
—
|
|
|
57
|
|
|
4
|
|
Sale of Minerals in Place
|
|
(128
|
)
|
|
(261
|
)
|
|
(77
|
)
|
Production
|
|
(129
|
)
|
|
(139
|
)
|
|
(154
|
)
|
Proved Reserves End of Year
|
|
1,929
|
|
|
1,965
|
|
|
1,437
|
|
(MMBoe)
|
|
United States
|
|
Israel
|
|
Equatorial Guinea
|
|
Total
|
||||
Proved Undeveloped Reserves, Beginning of Year
|
|
482
|
|
|
615
|
|
|
—
|
|
|
1,097
|
|
Revisions of Previous Estimates
|
|
(23
|
)
|
|
—
|
|
|
—
|
|
|
(23
|
)
|
Extensions, Discoveries and Other Additions
|
|
181
|
|
|
12
|
|
|
3
|
|
|
196
|
|
Sale of Minerals in Place
|
|
—
|
|
|
(15
|
)
|
|
—
|
|
|
(15
|
)
|
Conversion to Proved Developed
|
|
(80
|
)
|
|
—
|
|
|
—
|
|
|
(80
|
)
|
Proved Undeveloped Reserves, End of Year
|
|
560
|
|
|
612
|
|
|
3
|
|
|
1,175
|
|
•
|
Price Revisions US onshore positive price revisions (price impact to opening balance) of 3 MMBoe were due to changes in 12-month average commodity prices.
|
•
|
Non-Price Revisions Positive price revisions were offset by negative non-price revisions of 26 MMBoe, including the following:
|
•
|
the DJ Basin included a positive 8 MMBoe non-price revision, which included a positive revision of approximately 24 MMBoe associated with the adoption of Accounting Standards Codification (ASC) 606, Revenues from Contracts with Customers (ASC 606), partially offset by a negative revision of 16 MMBoe due to removal of PUDs locations due to changes in the previously adopted development plan;
|
•
|
the Delaware Basin included a negative 25 MMBoe non-price revision primarily due to changes in expected recoveries and higher operating and capital costs; and
|
•
|
the Eagle Ford Shale included a negative 9 MMBoe non-price revision primarily due to removal of PUDs locations due to changes in the previously adopted development plan.
|
•
|
the Audit Committee of our Board of Directors reviews significant reserves changes on an annual basis;
|
•
|
fields that meet a minimum reserve quantity threshold, 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.
|
|
|
Sales Volumes (1)
|
|
Average Sales Price (1)(2)
|
|
Production
Cost (3)
|
|||||||||||||||||||
|
|
Crude Oil &
Condensate
|
|
NGLs
|
|
Natural Gas
|
|
Crude Oil &
Condensate
|
|
NGLs
|
|
Natural Gas
|
|
Total
|
|||||||||||
|
|
(MBbl)
|
|
(MBbl)
|
|
(MMcf)
|
|
(Per Bbl)
|
|
(Per Bbl)
|
|
(Per Mcf)
|
|
(Per BOE)
|
|||||||||||
Year Ended December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
United States (4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
DJ Basin
|
|
23,165
|
|
|
8,880
|
|
|
83,766
|
|
|
$
|
63.06
|
|
|
$
|
25.32
|
|
|
$
|
2.13
|
|
|
$
|
4.53
|
|
Other US
|
|
18,506
|
|
|
13,761
|
|
|
88,370
|
|
|
58.69
|
|
|
26.24
|
|
|
2.90
|
|
|
6.16
|
|
||||
Total US
|
|
41,671
|
|
|
22,641
|
|
|
172,136
|
|
|
$
|
61.12
|
|
|
$
|
25.88
|
|
|
$
|
2.53
|
|
|
$
|
5.35
|
|
Israel (5)
|
|
113
|
|
|
—
|
|
|
86,461
|
|
|
$
|
63.25
|
|
|
$
|
—
|
|
|
$
|
5.47
|
|
|
$
|
2.30
|
|
Equatorial Guinea (6)
|
|
5,690
|
|
|
—
|
|
|
77,767
|
|
|
68.53
|
|
|
—
|
|
|
0.27
|
|
|
5.21
|
|
||||
Total Consolidated Operations
|
|
47,474
|
|
|
22,641
|
|
|
336,364
|
|
|
$
|
62.01
|
|
|
$
|
25.88
|
|
|
$
|
2.76
|
|
|
$
|
4.78
|
|
Equity Investee (7)
|
|
576
|
|
|
1,962
|
|
|
—
|
|
|
68.99
|
|
|
42.14
|
|
|
—
|
|
|
—
|
|
||||
Total
|
|
48,050
|
|
|
24,603
|
|
|
336,364
|
|
|
$
|
62.10
|
|
|
$
|
27.18
|
|
|
$
|
2.76
|
|
|
—
|
|
|
Year Ended December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
United States (4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
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
|
|
|
—
|
|
||||
Total Israel
|
|
130
|
|
|
—
|
|
|
99,240
|
|
|
$
|
46.95
|
|
|
$
|
—
|
|
|
$
|
5.32
|
|
|
$
|
2.01
|
|
Equatorial Guinea (6)
|
|
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 (7)
|
|
662
|
|
|
2,162
|
|
|
—
|
|
|
55.13
|
|
|
38.48
|
|
|
—
|
|
|
—
|
|
||||
Total
|
|
47,806
|
|
|
23,248
|
|
|
407,976
|
|
|
$
|
49.84
|
|
|
$
|
24.81
|
|
|
$
|
3.01
|
|
|
—
|
|
|
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
United States (4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
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
|
|
|
—
|
|
||||
Total Israel
|
|
140
|
|
|
—
|
|
|
102,808
|
|
|
$
|
36.67
|
|
|
$
|
—
|
|
|
$
|
5.21
|
|
|
$
|
2.60
|
|
Equatorial Guinea (6)
|
|
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 (7)
|
|
629
|
|
|
1,993
|
|
|
—
|
|
|
45.44
|
|
|
26.30
|
|
|
—
|
|
|
—
|
|
||||
Total
|
|
46,529
|
|
|
21,825
|
|
|
511,115
|
|
|
$
|
40.46
|
|
|
$
|
15.96
|
|
|
$
|
2.42
|
|
|
—
|
|
(1)
|
The adoption of ASC 606 on January 1, 2018 had a de minimis impact on revenues and production expense for 2018. See Item 8. Financial Statements and Supplementary Data – Note 4. Revenue from Contracts with Customers.
|
(2)
|
Average realized prices do not include gains or losses on commodity derivative instruments. See Item 1A. Risk Factors, Item 7A. Quantitative and Qualitative Disclosures About Market Risk and Item 8. Financial Statements and Supplementary Data – Note 13. Derivative Instruments and Hedging Activities.
|
(3)
|
Average production cost includes oil and gas exploration and production operating costs and workover and repair expense and excludes production and ad valorem taxes, gathering, transportation and processing expense, and other royalty expense.
|
(4)
|
Amounts include Gulf of Mexico assets prior to the sale in second quarter 2018 and Marcellus Shale assets prior to the sale in second quarter 2017. See Item 8. Financial Statements and Supplementary Data – Note 5. Acquisitions and Divestitures.
|
(5)
|
Sales volume reduction from 2017 is due to the sale of a 7.5% interest in the Tamar field.
|
(6)
|
(7)
|
Volumes represent sales of condensate and liquefied petroleum gas (LPG) from the LPG plant in Equatorial Guinea.
|
|
|
Crude Oil Wells
|
|
Natural Gas Wells
|
|
Total
|
||||||||||||
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
United States
|
|
5,289
|
|
|
4,781
|
|
|
909
|
|
|
842
|
|
|
6,198
|
|
|
5,623
|
|
Israel
|
|
—
|
|
|
—
|
|
|
7
|
|
|
2
|
|
|
7
|
|
|
2
|
|
Equatorial Guinea
|
|
5
|
|
|
2
|
|
|
23
|
|
|
8
|
|
|
28
|
|
|
10
|
|
Total
|
|
5,294
|
|
|
4,783
|
|
|
939
|
|
|
852
|
|
|
6,233
|
|
|
5,635
|
|
|
|
Developed Acreage
|
|
Undeveloped Acreage
|
||||||||
(thousands of acres)
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||
United States
|
|
|
|
|
|
|
|
|
||||
Onshore
|
|
549
|
|
|
449
|
|
|
527
|
|
|
384
|
|
Offshore
|
|
14
|
|
|
5
|
|
|
6
|
|
|
3
|
|
Total United States
|
|
563
|
|
|
454
|
|
|
533
|
|
|
387
|
|
International
|
|
|
|
|
|
|
|
|
|
|
|
|
Israel (1)
|
|
185
|
|
|
74
|
|
|
284
|
|
|
111
|
|
Equatorial Guinea
|
|
284
|
|
|
118
|
|
|
81
|
|
|
30
|
|
Newfoundland, Canada
|
|
—
|
|
|
—
|
|
|
2,332
|
|
|
681
|
|
Gabon
|
|
—
|
|
|
—
|
|
|
671
|
|
|
403
|
|
Cyprus
|
|
—
|
|
|
—
|
|
|
95
|
|
|
33
|
|
Cameroon
|
|
—
|
|
|
—
|
|
|
168
|
|
|
168
|
|
Total International
|
|
469
|
|
|
192
|
|
|
3,631
|
|
|
1,426
|
|
Total
|
|
1,032
|
|
|
646
|
|
|
4,164
|
|
|
1,813
|
|
|
|
Net Exploratory Wells
|
|
Net Development Wells
|
|
|
|||||||||||||||
|
|
Productive
|
|
Dry
|
|
Total
|
|
Productive
|
|
Dry
|
|
Total
|
|
Total
|
|||||||
Year Ended December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
United States
|
|
—
|
|
|
—
|
|
|
—
|
|
|
203.0
|
|
|
—
|
|
|
203.0
|
|
|
203.0
|
|
Total
|
|
—
|
|
|
—
|
|
|
—
|
|
|
203.0
|
|
|
—
|
|
|
203.0
|
|
|
203.0
|
|
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
|
|
|
|
Exploratory(1)
|
|
Development(1)
|
|
Total
|
||||||||||||
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
United States
|
|
—
|
|
|
—
|
|
|
114.0
|
|
|
107.1
|
|
|
114.0
|
|
|
107.1
|
|
Israel (2)
|
|
—
|
|
|
—
|
|
|
4.0
|
|
|
1.6
|
|
|
4.0
|
|
|
1.6
|
|
Total
|
|
—
|
|
|
—
|
|
|
118.0
|
|
|
108.7
|
|
|
118.0
|
|
|
108.7
|
|
(1)
|
Amounts exclude wells drilled and suspended awaiting a sanctioned development plan or being evaluated to assess the economic viability of the well.
|
(2)
|
Includes Leviathan 3, 4, 5 and 7 development wells not yet capable of production. Excludes Tamar Southwest well as it is not in the process of drilling or completing at December 31, 2018.
|
•
|
completed construction of the Collier, Billy Miner Train II and Coronado CGFs in the Delaware Basin;
|
•
|
completed construction of freshwater delivery infrastructure and commenced gathering services in the DJ Basin; and
|
•
|
signed a non-binding letter of intent with Salt Creek Midstream LLC (Salt Creek) for construction of a crude oil pipeline system in the Delaware Basin, for which definitive agreements with Salt Creek were executed in February 2019.
|
•
|
legislation has been proposed in Congress to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection,” to require federal permitting and regulatory control of hydraulic fracturing, and to require disclosure of the chemical constituents of the fluids used in the fracturing process;
|
•
|
the Bureau of Land Management (BLM), as a result of legal challenges, has published a final rule to rescind its 2015 rule governing hydraulic fracturing on federal and Indian lands. Further legal challenges are expected;
|
•
|
the Occupational Safety and Health Administration (OSHA) has lowered exposure limits for workers who use silica (sand) in hydraulic fracturing activities, and silica work practices have become stricter;
|
•
|
state and federal regulatory agencies have focused on a possible connection between the operation of injection wells used for oil and gas waste disposal and seismic activity, which some have termed “induced seismicity,” and some state regulatory agencies have modified their regulations to account for such induced seismicity; and
|
•
|
ongoing or proposed studies on the environmental impacts of hydraulic fracturing could spur initiatives to further regulate hydraulic fracturing.
|
•
|
reduction of our revenues, profit margins, operating income and cash flows;
|
•
|
reduction in the amount of crude oil, NGLs and natural gas that we can produce economically, leading to shut-in or early abandonment of producing wells, including low-margin US onshore 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;
|
•
|
use of cash flow to satisfy minimum obligations under throughput agreements if production is suspended;
|
•
|
reduction, or suspension, of our future capital investment programs, resulting in a reduced ability to develop or replace our reserves;
|
•
|
delay, postponement or cancellation of some of our exploration or development projects;
|
•
|
inability to meet exploration or continuous drilling commitments, leading to loss of leases or exploration rights;
|
•
|
loss of undeveloped acreage if we are unable to make scheduled delay rental payments or loss of developed acreage if our production is shut-in;
|
•
|
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, which 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 future 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 and our ability to access the commercial paper market;
|
•
|
changes in corporate structure that could lead to loss of key personnel and interrupt our business activities;
|
•
|
reduction or suspension of dividends or repurchases of 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, NGLs and natural gas, as impacted by economic factors that affect gross domestic product growth rates of countries around the world;
|
•
|
global supply for crude oil, NGLs and natural gas, as impacted by OPEC and non-OPEC countries (e.g. US, Russia, Canada);
|
•
|
technology advances that increase crude oil, NGL and natural gas production, thereby increasing supply;
|
•
|
new technologies that promote fuel efficiency or fuel efficiency regulations, such as the Corporate Average Fuel Economy (CAFE) standards, and impact demand for crude oil as a transportation fuel and reduce energy consumption;
|
•
|
the price and availability of alternative fuels and battery storage and 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;
|
•
|
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, the impact of trade embargoes or imposed tariffs, or instability/armed conflict in hydrocarbon-producing regions;
|
•
|
fluctuations in exchange rates of the US dollar, the currency in which the world's crude oil trade is generally denominated;
|
•
|
periods when production surpasses local pipeline/rail transportation and/or refining capacity, as is currently the case in the Delaware Basin, which in turn results in transportation constraints and significant discounts to our realized prices;
|
•
|
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, which 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 increase 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;
|
•
|
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;
|
•
|
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; and
|
•
|
other hazards arising out of foreign governmental sovereignty over areas in which we conduct operations.
|
•
|
increased volatility in global crude oil, NGL and natural gas 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, third-party providers or supplies to enter or exit the countries where we conduct 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 purchasers, leading to interruption of commodity deliveries, claims of force majeure, and/or termination of sales contracts, resulting in a reduction in our revenues;
|
•
|
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.
|
•
|
unauthorized access to seismic data, reserves information or other sensitive or proprietary information could have a negative impact on our ability to compete for oil and gas resources;
|
•
|
data corruption, communication interruption, or other operational disruption during drilling activities could result in failure to reach the intended target or a drilling incident;
|
•
|
data corruption or operational disruption of production infrastructure could result in loss of production, or accidental discharge;
|
•
|
a cyber attack on a supplier or service provider could result in supply chain disruptions which could delay or halt a development project, effectively delaying the start of cash flows from the project;
|
•
|
a cyber attack on a third-party gathering or pipeline service provider could prevent us from marketing our production, resulting in a loss of revenues;
|
•
|
a cyber attack involving commodities exchanges or financial institutions could slow or halt commodities trading, thus preventing us from marketing our production or engaging in hedging activities, resulting in a loss of revenues;
|
•
|
a cyber attack which halts activities at a power generation facility or refinery using natural gas as feed stock could have a significant impact on the natural gas market, resulting in reduced demand for our production, lower natural gas prices, and reduced revenues;
|
•
|
a cyber attack on a communications network or power grid could cause operational disruption resulting in loss of revenues;
|
•
|
a deliberate corruption of our financial or operational data, or data theft, could result in events of non-compliance which could lead to regulatory fines or penalties; and
|
•
|
business interruptions, including use of social engineering schemes and/or ransomware, could result in expensive remediation efforts, distraction of management, damage to our reputation, or a negative impact on the price of our common stock.
|
•
|
new municipal, 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; and
|
•
|
the presence of threatened or endangered species or of their habitat.
|
•
|
reduce our proved reserves;
|
•
|
reduce our ability to explore for new proved reserves;
|
•
|
increase exploratory and development well drilling costs, operating or other costs;
|
•
|
delay, or preclude, project development resulting in longer development cycle times;
|
•
|
disrupt or prohibit our ability to construct or operate midstream assets;
|
•
|
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.
|
•
|
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;
|
•
|
negatively impact our and/or our partners' ability 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.
|
•
|
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, NGL and natural gas 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 truck or rail car or train derailments;
|
•
|
leakage or loss of access to hydrocarbons resulting from formations with abnormal pressures and basin subsidence;
|
•
|
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, windstorms, or “superstorms,” which could affect our operations in areas such as Texas;
|
•
|
winter storms and snow, which could affect our operations in the DJ Basin;
|
•
|
extremely high temperatures, which could affect our midstream or third-party gathering and processing facilities in the DJ Basin and Texas;
|
•
|
severe droughts, which could result in new restrictions on water usage in the DJ Basin and Texas;
|
•
|
harsh weather and rough seas offshore international locations, which could limit exploration activities; and
|
•
|
other natural disasters.
|
•
|
a reduction in or slowing of customer drilling and development plans on our dedicated acreage, which would directly and adversely impact demand for our midstream services;
|
•
|
the volatility of crude oil, natural gas and NGL prices, which could have a negative effect on our customers’ drilling and development plans on our dedicated acreage or ability to finance their operations and drilling and completion costs on our dedicated acreage;
|
•
|
the availability of capital on an economic basis for our customers to fund their exploration and development activities;
|
•
|
drilling and operating risks associated with customer operations on our dedicated acreage;
|
•
|
downstream processing and transportation capacity constraints and interruptions, including the failure of our customers to have sufficient contracted processing or transportation capacity; and
|
•
|
adverse effects of increased or changed governmental and environmental regulation or enforcement of existing regulation.
|
•
|
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) may 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; and
|
•
|
we may be more vulnerable to general adverse economic and industry conditions.
|
•
|
acquiring desirable producing properties or new leases for future exploration;
|
•
|
acquiring or increasing access to gathering, transportation and processing services and capacity;
|
•
|
marketing our crude oil, NGL and natural gas production;
|
•
|
acquiring 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;
|
•
|
assumed effects of regulations by governmental agencies, including the SEC;
|
•
|
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.
|
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 (2)
|
|
Approximate Dollar
Value of Shares that
May Yet Be
Purchased Under the
Plans or Programs
|
||||||
|
|
|
|
|
|
|
|
(millions)
|
||||||
10/1/2018 - 10/31/2018
|
|
59,006
|
|
|
$
|
29.37
|
|
|
—
|
|
|
|
||
11/1/2018 - 11/30/2018
|
|
1,630,968
|
|
|
24.57
|
|
|
1,621,076
|
|
|
|
|||
12/1/2018 - 12/31/2018
|
|
964,927
|
|
|
23.53
|
|
|
964,609
|
|
|
|
|||
Total
|
|
2,654,901
|
|
|
$
|
24.29
|
|
|
2,585,685
|
|
|
$
|
455
|
|
Anadarko Petroleum Corp.
|
Devon Energy Corp.
|
Noble Energy, Inc.
|
Apache Corp.
|
EOG Resources, Inc.
|
Pioneer Natural Resources Co.
|
Cabot Oil & Gas Corp.
|
Hess Corp.
|
Range Resources Corp.
|
Chesapeake Energy Corp.
|
Marathon Oil Corp.
|
Southwestern Energy Co.
|
Continental Resources, Inc.
|
Murphy Oil Corp.
|
|
Year Ended December 31,
|
2014
|
2015
|
2016
|
2017
|
2018
|
||||||||||
Noble Energy, Inc.
|
$
|
70.38
|
|
$
|
49.73
|
|
$
|
58.15
|
|
$
|
45.11
|
|
$
|
29.47
|
|
S&P 500
|
113.69
|
|
115.26
|
|
129.05
|
|
157.22
|
|
150.33
|
|
|||||
Peer Group
|
86.06
|
|
53.24
|
|
76.93
|
|
68.75
|
|
51.93
|
|
|
|
Year Ended December 31,
|
||||||||||||||||||
(millions, except as noted)
|
|
2018
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
||||||||||
Revenues and Income
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total Revenues
|
|
$
|
4,986
|
|
|
$
|
4,256
|
|
|
$
|
3,491
|
|
|
$
|
3,183
|
|
|
$
|
5,115
|
|
Net Income (Loss) and Comprehensive Income (Loss) Including Noncontrolling Interests
|
|
14
|
|
|
(1,050
|
)
|
|
(985
|
)
|
|
(2,441
|
)
|
|
1,214
|
|
|||||
Net (Loss) Income and Comprehensive (Loss) Income Attributable to Noble Energy
|
|
(66
|
)
|
|
(1,118
|
)
|
|
(998
|
)
|
|
(2,441
|
)
|
|
1,214
|
|
|||||
Per Share Data, Attributable to Noble Energy
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
(Loss) Earnings Per Share - Basic
|
|
(0.14
|
)
|
|
(2.38
|
)
|
|
(2.32
|
)
|
|
(6.07
|
)
|
|
3.36
|
|
|||||
(Loss) Earnings Per Share - Diluted
|
|
(0.14
|
)
|
|
(2.38
|
)
|
|
(2.32
|
)
|
|
(6.07
|
)
|
|
3.27
|
|
|||||
Cash Dividends Per Share
|
|
0.43
|
|
|
0.40
|
|
|
0.40
|
|
|
0.72
|
|
|
0.68
|
|
|||||
Year-End Stock Price Per Share
|
|
18.76
|
|
|
29.14
|
|
|
38.06
|
|
|
32.93
|
|
|
47.43
|
|
|||||
Weighted Average Number of Shares Outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Basic
|
|
483
|
|
|
469
|
|
|
430
|
|
|
402
|
|
|
361
|
|
|||||
Diluted
|
|
483
|
|
|
469
|
|
|
430
|
|
|
402
|
|
|
367
|
|
|||||
Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Net Cash Provided by Operating Activities
|
|
$
|
2,336
|
|
|
$
|
1,951
|
|
|
$
|
1,351
|
|
|
$
|
2,062
|
|
|
$
|
3,506
|
|
Additions to Property, Plant and Equipment
|
|
3,279
|
|
|
2,649
|
|
|
1,541
|
|
|
2,979
|
|
|
4,871
|
|
|||||
Proceeds from Divestitures (1)
|
|
1,999
|
|
|
2,073
|
|
|
1,241
|
|
|
151
|
|
|
321
|
|
|||||
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
|
|
$
|
716
|
|
|
$
|
675
|
|
|
$
|
1,180
|
|
|
$
|
1,028
|
|
|
$
|
1,183
|
|
Property, Plant and Equipment, Net
|
|
18,419
|
|
|
17,502
|
|
|
18,548
|
|
|
21,300
|
|
|
18,143
|
|
|||||
Goodwill (2)
|
|
110
|
|
|
1,310
|
|
|
—
|
|
|
—
|
|
|
620
|
|
|||||
Total Assets
|
|
21,010
|
|
|
21,476
|
|
|
21,011
|
|
|
24,196
|
|
|
22,518
|
|
|||||
Long-term Obligations
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Long-Term Debt
|
|
6,574
|
|
|
6,746
|
|
|
7,011
|
|
|
7,976
|
|
|
6,068
|
|
|||||
Deferred Income Taxes
|
|
1,061
|
|
|
1,127
|
|
|
1,819
|
|
|
2,826
|
|
|
2,516
|
|
|||||
Asset Retirement Obligations, Noncurrent
|
|
762
|
|
|
824
|
|
|
775
|
|
|
861
|
|
|
670
|
|
|||||
Other
|
|
403
|
|
|
421
|
|
|
328
|
|
|
358
|
|
|
417
|
|
|||||
Total Equity
|
|
10,484
|
|
|
10,619
|
|
|
9,600
|
|
|
10,370
|
|
|
10,325
|
|
(1)
|
(2)
|
|
|
Year Ended December 31,
|
||||||||||||||||||
|
|
2018
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
||||||||||
Operations Information - Consolidated Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Consolidated Crude Oil Sales (MBbl/d)
|
|
130
|
|
|
129
|
|
|
125
|
|
|
112
|
|
|
103
|
|
|||||
Average Realized Price ($/Bbl)
|
|
$
|
62.01
|
|
|
$
|
49.73
|
|
|
$
|
40.39
|
|
|
$
|
45.00
|
|
|
$
|
91.58
|
|
Consolidated NGL Sales (MBbl/d)
|
|
62
|
|
|
58
|
|
|
54
|
|
|
39
|
|
|
23
|
|
|||||
Average Realized Price ($/Bbl)
|
|
$
|
25.88
|
|
|
$
|
23.40
|
|
|
$
|
14.92
|
|
|
$
|
13.91
|
|
|
$
|
33.75
|
|
Consolidated Natural Gas Sales (MMcf/d)
|
|
922
|
|
|
1,118
|
|
|
1,397
|
|
|
1,187
|
|
|
992
|
|
|||||
Average Realized Price ($/Mcf)
|
|
$
|
2.76
|
|
|
$
|
3.01
|
|
|
$
|
2.42
|
|
|
$
|
2.44
|
|
|
$
|
3.38
|
|
Proved Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Crude Oil and Condensate Reserves (MMBbls)
|
|
457
|
|
|
457
|
|
|
333
|
|
|
307
|
|
|
304
|
|
|||||
NGL Reserves (MMBbls)
|
|
266
|
|
|
229
|
|
|
219
|
|
|
189
|
|
|
128
|
|
|||||
Natural Gas Reserves (Bcf)
|
|
7,231
|
|
|
7,680
|
|
|
5,308
|
|
|
5,549
|
|
|
5,833
|
|
|||||
Total Reserves (MMBoe)
|
|
1,929
|
|
|
1,965
|
|
|
1,437
|
|
|
1,421
|
|
|
1,404
|
|
|||||
Number of Employees
|
|
2,330
|
|
|
2,277
|
|
|
2,274
|
|
|
2,395
|
|
|
2,735
|
|
•
|
•
|
•
|
•
|
•
|
•
|
•
|
•
|
|
||
|
||
|
|
|
||
|
•
|
sale of a 7.5% working interest in Tamar;
|
•
|
sale of our 50% interest in CONE Gathering LLC and our investment in CNX Midstream Partners common units;
|
•
|
sale of our Gulf of Mexico assets;
|
•
|
expansion of new venture portfolio in both US onshore and international offshore locations;
|
•
|
execution of numerous acreage exchanges and sales to secure more contiguous acreage positions within the DJ and Delaware Basins; and
|
•
|
completing the midstream Saddle Butte Acquisition, which expanded utilization of the Advantage Pipeline.
|
•
|
progressing Leviathan development to approximately 75% completion and remaining on budget and on schedule to flow first gas by the end of 2019;
|
•
|
achieved annual average record gross sales of over 1 Bcf/d in Israel;
|
•
|
advancing natural gas marketing and transportation optionality for the export of Tamar and Leviathan production to Egypt;
|
•
|
progressed the next phase of development offshore West Africa by entering a Heads of Agreement establishing the framework for monetization of natural gas from the Alen field;
|
•
|
increased total US onshore sales volumes by more than 18% from 2017, excluding the impact of the Marcellus Shale upstream divestiture, and continuing shift to an oilier production mix, with approximately 44% of our US onshore consolidated sales volumes attributable to crude oil;
|
•
|
securing near-term flow assurance and long-term out-of-basin takeaway capacity, including the EPIC firm transport agreement, from the Delaware Basin to the Texas Gulf Coast, with access to export markets;
|
•
|
expanded our midstream footprint capabilities through CGF constructions; and
|
•
|
received approval for the first large-scale CDP which will span our Mustang IDP area.
|
•
|
Board of Directors authorization to implement a $750 million share repurchase program and subsequent repurchase of 10 million shares of Noble Energy common stock, for $295 million, during the year;
|
•
|
increase in dividends to 11 cents per Noble Energy common share for second, third and fourth quarters and paid dividends of $208 million during 2018;
|
•
|
repayment of $609 million of outstanding debt;
|
•
|
enhancement of financial flexibility via revolving credit facility maturity date extensions, a capacity increase and entry into a new term loan credit facility;
|
•
|
repatriation of $791 million from foreign operations with no US tax impact;
|
•
|
positive mitigation efforts for retained Marcellus Shale firm transportation contracts;
|
•
|
strong liquidity position including cash on hand and unused borrowing capacity; and
|
•
|
investment grade credit ratings and received improved outlooks from two agencies.
|
•
|
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 by:
|
◦
|
utilizing our technical competencies and applying historical learnings from unconventional US shale plays to reduce US onshore finding and development costs.
|
•
|
Leveraging the benefits of our well-positioned and diversified portfolio, including:
|
◦
|
exercising investment optionality and flexibility afforded by our assets, certain of which are 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 Phase 1 field development and monetization of natural gas offshore West Africa.
|
•
|
Maintaining financial strength through:
|
◦
|
focusing operational activities on high-margin, high-return assets; and
|
◦
|
improving overall corporate returns.
|
•
|
commodity prices, including price realizations on specific crude oil, NGL and natural gas production;
|
•
|
operating and development costs;
|
•
|
production, drilling and delivery commitments, or other contractual obligations;
|
•
|
drilling results;
|
•
|
cash flows from operations and 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;
|
•
|
property acquisitions and divestitures;
|
•
|
exploration activity; and
|
•
|
potential changes in the fiscal regimes of the US and other countries in which we operate.
|
•
|
total average consolidated sales volumes of 346 MBoe/d, net;
|
•
|
average daily sales volumes for US onshore crude oil of 109 MBbl/d, net; and
|
•
|
average daily sales volumes of approximately 1.0 Bcfe/d, gross, offshore Israel, primarily from the Tamar field.
|
•
|
average realized crude oil price increase of 25% as compared with 2017;
|
•
|
average realized NGL price increase of 10% as compared with 2017;
|
•
|
average realized natural gas price decrease of 8% as compared with 2017;
|
•
|
goodwill impairment charge of $1.3 billion attributable to the Texas reporting unit (associated with the Clayton Williams Energy Acquisition);
|
•
|
pre-tax income of $119 million, as compared with pre-tax loss of $1.8 billion for 2017; and
|
•
|
capital expenditures, excluding acquisitions, of $2.8 billion, as compared with $2.4 billion for 2017.
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
2018
|
|
2017
|
|
2016
|
||||||
Oil, NGL and Gas Sales to Third Parties (1)
|
$
|
4,461
|
|
|
$
|
4,060
|
|
|
$
|
3,389
|
|
Income from Equity Method Investees
|
132
|
|
|
120
|
|
|
50
|
|
|||
Total Revenues
|
4,613
|
|
|
4,180
|
|
|
3,439
|
|
|||
Production Expense (1)
|
1,358
|
|
|
1,270
|
|
|
1,200
|
|
|||
Exploration Expense
|
129
|
|
|
188
|
|
|
925
|
|
|||
Depreciation, Depletion and Amortization
|
1,819
|
|
|
1,965
|
|
|
2,395
|
|
|||
Loss on Marcellus Shale Upstream Divestiture and Other
|
—
|
|
|
2,286
|
|
|
—
|
|
|||
Gain on Divestitures, Net (2)
|
(340
|
)
|
|
(326
|
)
|
|
(238
|
)
|
|||
Asset Impairments (2)
|
169
|
|
|
70
|
|
|
92
|
|
|||
Goodwill Impairment (3)
|
1,281
|
|
|
—
|
|
|
—
|
|
|||
(Gain) Loss on Commodity Derivative Instruments
|
(63
|
)
|
|
(63
|
)
|
|
139
|
|
|||
Clayton Williams Energy Acquisition Expenses
|
—
|
|
|
100
|
|
|
—
|
|
|||
Income (Loss) Before Income Taxes
|
119
|
|
|
(1,803
|
)
|
|
(1,271
|
)
|
(1)
|
The adoption of ASC 606 on January 1, 2018 had a de minimis impact on revenues and production expense for 2018. See Item 8. Financial Statements and Supplementary Data – Note 4. Revenue from Contracts with Customers.
|
(2)
|
(3)
|
|
Sales Volumes (1)
|
|
Average Realized Sales Prices (1)
|
||||||||||||||||||||
|
Crude Oil & Condensate
(MBbl/d)
|
|
NGLs
(MBbl/d) |
|
Natural Gas (MMcf/d)
|
|
Total
(MBoe/d)
|
|
Crude Oil & Condensate
(Per Bbl)
|
|
NGLs
(Per Bbl)
|
|
Natural
Gas (Per Mcf) |
||||||||||
Year Ended December 31, 2018
|
|||||||||||||||||||||||
United States (2)
|
114
|
|
|
62
|
|
|
472
|
|
|
255
|
|
|
$
|
61.12
|
|
|
$
|
25.88
|
|
|
$
|
2.53
|
|
Eastern Mediterranean
|
—
|
|
|
—
|
|
|
237
|
|
|
40
|
|
|
—
|
|
|
—
|
|
|
5.47
|
|
|||
West Africa (3)
|
16
|
|
|
—
|
|
|
213
|
|
|
51
|
|
|
68.53
|
|
|
—
|
|
|
0.27
|
|
|||
Total Consolidated Operations
|
130
|
|
|
62
|
|
|
922
|
|
|
346
|
|
|
62.01
|
|
|
25.88
|
|
|
2.76
|
|
|||
Equity Investees (4)
|
2
|
|
|
5
|
|
|
—
|
|
|
7
|
|
|
68.99
|
|
|
42.14
|
|
|
—
|
|
|||
Total
|
132
|
|
|
67
|
|
|
922
|
|
|
353
|
|
|
$
|
62.10
|
|
|
$
|
27.18
|
|
|
$
|
2.76
|
|
Year Ended December 31, 2017
|
|||||||||||||||||||||||
United States
|
111
|
|
|
58
|
|
|
607
|
|
|
270
|
|
|
$
|
49.11
|
|
|
$
|
23.40
|
|
|
$
|
3.02
|
|
Eastern Mediterranean
|
—
|
|
|
—
|
|
|
272
|
|
|
46
|
|
|
—
|
|
|
—
|
|
|
5.32
|
|
|||
West Africa (3)
|
18
|
|
|
—
|
|
|
239
|
|
|
57
|
|
|
53.68
|
|
|
—
|
|
|
0.27
|
|
|||
Total Consolidated Operations
|
129
|
|
|
58
|
|
|
1,118
|
|
|
373
|
|
|
49.73
|
|
|
23.40
|
|
|
3.01
|
|
|||
Equity Investees (4)
|
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
|
|
Eastern Mediterranean
|
—
|
|
|
—
|
|
|
281
|
|
|
47
|
|
|
—
|
|
|
—
|
|
|
5.21
|
|
|||
West Africa (3)
|
26
|
|
|
—
|
|
|
235
|
|
|
65
|
|
|
43.54
|
|
|
—
|
|
|
0.27
|
|
|||
Total Consolidated Operations
|
125
|
|
|
54
|
|
|
1,397
|
|
|
413
|
|
|
40.39
|
|
|
14.92
|
|
|
2.42
|
|
|||
Equity Investees (4)
|
2
|
|
|
5
|
|
|
—
|
|
|
7
|
|
|
45.44
|
|
|
26.30
|
|
|
—
|
|
|||
Total
|
127
|
|
|
59
|
|
|
1,397
|
|
|
420
|
|
|
$
|
40.46
|
|
|
$
|
15.96
|
|
|
$
|
2.42
|
|
(1)
|
The adoption of ASC 606 on January 1, 2018 had a de minimis impact on revenues and production expense for 2018. See Item 8. Financial Statements and Supplementary Data – Note 4. Revenue from Contracts with Customers. Specifically, this resulted in the following:
|
◦
|
increases in NGL revenues, and corresponding increase in production expense, of $7 million for 2018;
|
◦
|
decreases in natural gas revenues, and corresponding decreases in production expense, of $7 million for 2018;
|
◦
|
increases in NGL and natural gas sales volumes of 5 MBbl/d and 31MMcf/d, respectively, for 2018; and
|
◦
|
reductions in average realized NGL and natural gas sales prices of $1.76/Bbl and $0.12/Mcf, respectively, for 2018.
|
(2)
|
Includes 7 MBoe/d for 2018 related to Gulf of Mexico assets sold in April 2018. See Item 8. Financial Statements and Supplementary Data – Note 5. Acquisitions and Divestitures.
|
(3)
|
(4)
|
Volumes represent sales of condensate and LPG from the LPG plant in Equatorial Guinea. See Income from Equity Method Investees.
|
(millions)
|
|
Crude Oil &
Condensate
|
|
NGLs
|
|
Natural
Gas
|
|
Total
|
||||||||
Year Ended December 31, 2016
|
|
$
|
1,854
|
|
|
$
|
296
|
|
|
$
|
1,239
|
|
|
$
|
3,389
|
|
Changes due to
|
|
|
|
|
|
|
|
|
||||||||
Increase (Decrease) in Sales Volumes
|
|
55
|
|
|
17
|
|
|
(182
|
)
|
|
(110
|
)
|
||||
Increase in Sales Prices (1)
|
|
437
|
|
|
180
|
|
|
164
|
|
|
781
|
|
||||
Year Ended December 31, 2017
|
|
$
|
2,346
|
|
|
$
|
493
|
|
|
$
|
1,221
|
|
|
$
|
4,060
|
|
Changes due to
|
|
|
|
|
|
|
|
|
||||||||
Increase (Decrease) in Sales Volumes
|
|
14
|
|
|
—
|
|
|
(266
|
)
|
|
(252
|
)
|
||||
Increase (Decrease) in Sales Prices (1)
|
|
585
|
|
|
87
|
|
|
(19
|
)
|
|
653
|
|
||||
Impact of ASC 606 Adoption
|
|
—
|
|
|
7
|
|
|
(7
|
)
|
|
—
|
|
||||
Year Ended December 31, 2018
|
|
$
|
2,945
|
|
|
$
|
587
|
|
|
$
|
929
|
|
|
$
|
4,461
|
|
(1)
|
Changes exclude gains and losses related to commodity derivative instruments. See Item 8. Financial Statements and Supplementary Data – Note 13. Derivative Instruments and Hedging Activities.
|
•
|
25% increase in average realized prices (see factors impacting global pricing at Executive Overview - Industry Outlook); and
|
•
|
higher US onshore sales volumes of 19 MBbl/d primarily driven by an increase in development activity in the Delaware and DJ Basins;
|
•
|
lower Gulf of Mexico sales volumes of 16 MBbl/d resulting from the sale of the Gulf of Mexico assets in second quarter 2018; and
|
•
|
lower offshore West Africa sales volumes of 2 MBbl/d resulting from natural field decline.
|
•
|
23% increase in average realized prices (see factors impacting global pricing at Executive Overview – Industry Outlook);
|
•
|
higher US onshore sales volumes of 16 MBbl/d, including 5 MBbl/d contributed by 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 US onshore sales volumes of 6 MBbl/d (exclusive of 5 MBbl/d from adoption of ASC 606) primarily attributable to development activities in the Delaware and DJ Basins;
|
•
|
10% increase in average realized prices (see factors impacting global pricing at Executive Overview – Industry Outlook); and
|
•
|
$7 million increase associated with the adoption of ASC 606;
|
•
|
lower sales volumes of 5 MBbl/d due to the divestiture of the Marcellus Shale upstream assets in second quarter 2017.
|
•
|
56% increase in average realized prices (see factors impacting global pricing at Executive Overview – Industry Outlook); and
|
•
|
higher US onshore sales volumes of 7 MBbl/d, including 1 MBbl/d contributed by 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.
|
•
|
lower sales volumes of 174 MMcf/d due to the divestiture of the Marcellus Shale upstream assets in second quarter 2017;
|
•
|
lower Gulf of Mexico sales volumes of 14 MMcf/d resulting from the sale of the Gulf of Mexico assets in second quarter 2018;
|
•
|
lower Israel sales volumes of 35 MMcf/d due to the sale of a 7.5% interest in the Tamar field in second quarter 2018;
|
•
|
$7 million decrease associated with the adoption of ASC 606;
|
•
|
lower sales volumes of 26 MMcf/d from the Alba field, offshore Equatorial Guinea, resulting from natural field decline and timing of field maintenance; and
|
•
|
8% decrease in average realized prices primarily due to the impact of increased US onshore supply;
|
•
|
higher US onshore sales volumes of 30 MMcf/d (exclusive of 31 MMcf/d from adoption of ASC 606) primarily attributable to development activities in the Delaware and DJ Basins; and
|
•
|
higher sales volumes related to our remaining working interest in Israel due to increased demand for power as well as conversion of facilities from use of coal to natural gas.
|
•
|
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 in December 2016, partially offset by higher gross sales volumes from the field;
|
•
|
24% increase in average realized prices (see factors impacting global pricing at Executive Overview – Industry Outlook); and
|
•
|
higher US onshore sales volumes of 40 MMcf/d, including 6 MMcf/d contributed by Clayton Williams Energy assets.
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
Net Income (in millions)
|
|
|
|
|
|
|
||||||
AMPCO and Affiliates
|
|
$
|
64
|
|
|
$
|
58
|
|
|
$
|
16
|
|
Alba Plant
|
|
71
|
|
|
65
|
|
|
34
|
|
|||
Dividends (in millions)
|
|
|
|
|
|
|
||||||
AMPCO and Affiliates
|
|
$
|
63
|
|
|
$
|
47
|
|
|
$
|
16
|
|
Alba Plant
|
|
93
|
|
|
68
|
|
|
40
|
|
|||
Sales Volumes
|
|
|
|
|
|
|
||||||
Methanol (MMgal)
|
|
149
|
|
|
163
|
|
|
162
|
|
|||
Condensate (MBbl/d)
|
|
2
|
|
|
2
|
|
|
2
|
|
|||
LPG (MBbl/d)
|
|
5
|
|
|
6
|
|
|
5
|
|
|||
Average Realized Prices
|
|
|
|
|
|
|
||||||
Methanol (per gallon)
|
|
$
|
1.14
|
|
|
$
|
0.97
|
|
|
$
|
0.63
|
|
Condensate (per Bbl)
|
|
68.99
|
|
|
55.13
|
|
|
45.44
|
|
|||
LPG (per Bbl)
|
|
42.14
|
|
|
38.48
|
|
|
26.30
|
|
•
|
increase in net income from AMPCO and affiliates primarily due to higher realized methanol prices; and
|
•
|
increase in net income from Alba Plant primarily due to higher realized LPG prices.
|
•
|
increase in net income from AMPCO and affiliates primarily due to higher realized methanol prices; and
|
•
|
increase in net income from Alba Plant primarily due to higher LPG sales volumes and realized prices.
|
(millions, except unit rate)
|
Total per BOE (1)(2)
|
|
Total
|
|
United
States (2)
|
|
Eastern Mediterranean
|
|
West Africa
|
||||||||||
Year Ended December 31, 2018
|
|
|
|
|
|
|
|
|
|
||||||||||
Lease Operating Expense (3)
|
$
|
4.78
|
|
|
$
|
603
|
|
|
$
|
480
|
|
|
$
|
26
|
|
|
$
|
97
|
|
Production and Ad Valorem Taxes
|
1.46
|
|
|
184
|
|
|
184
|
|
|
—
|
|
|
—
|
|
|||||
Gathering, Transportation and Processing (4)
|
4.22
|
|
|
533
|
|
|
533
|
|
|
—
|
|
|
—
|
|
|||||
Other Royalty Expense
|
0.30
|
|
|
38
|
|
|
38
|
|
|
—
|
|
|
—
|
|
|||||
Total Production Expense
|
$
|
10.76
|
|
|
$
|
1,358
|
|
|
$
|
1,235
|
|
|
$
|
26
|
|
|
$
|
97
|
|
Total Production Expense per BOE
|
|
|
$
|
10.76
|
|
|
$
|
13.28
|
|
|
$
|
1.79
|
|
|
$
|
5.20
|
|
||
Year Ended December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Lease Operating Expense (3)
|
$
|
4.29
|
|
|
$
|
585
|
|
|
$
|
466
|
|
|
$
|
29
|
|
|
$
|
90
|
|
Production and Ad Valorem Taxes
|
0.84
|
|
|
115
|
|
|
115
|
|
|
—
|
|
|
—
|
|
|||||
Gathering, Transportation and Processing
|
4.04
|
|
|
550
|
|
|
550
|
|
|
—
|
|
|
—
|
|
|||||
Other Royalty Expense
|
0.15
|
|
|
20
|
|
|
20
|
|
|
—
|
|
|
—
|
|
|||||
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
|
0.36
|
|
|
55
|
|
|
55
|
|
|
—
|
|
|
—
|
|
|||||
Gathering, Transportation and Processing
|
3.73
|
|
|
564
|
|
|
564
|
|
|
—
|
|
|
—
|
|
|||||
Other Royalty Expense
|
0.14
|
|
|
21
|
|
|
21
|
|
|
—
|
|
|
—
|
|
|||||
Total Production Expense
|
$
|
7.95
|
|
|
$
|
1,200
|
|
|
$
|
1,058
|
|
|
$
|
37
|
|
|
$
|
105
|
|
Total Production Expense per BOE
|
|
|
$
|
7.95
|
|
|
$
|
9.63
|
|
|
$
|
2.14
|
|
|
$
|
4.42
|
|
(1)
|
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.
|
(2)
|
US production expense includes charges from our midstream operations that are eliminated on a consolidated basis. See Item 8. Financial Statements and Supplementary Data – Note 3. Segment Information.
|
(3)
|
Lease operating expense includes oil and gas operating costs (labor, fuel, repairs, replacements, saltwater disposal and other related lifting costs) and workover expense.
|
(4)
|
The adoption of ASC 606 on January 1, 2018 had a de minimis impact on revenues and production expense for 2018. See Item 8. Financial Statements and Supplementary Data – Note 4. Revenue from Contracts with Customers.
|
•
|
increase of $93 million primarily due to increased development activities resulting in added production in the DJ and Delaware Basins; and
|
•
|
increase in costs in the Delaware Basin due to higher activity and demand for supplies and services, particularly water disposal;
|
•
|
decrease of $84 million due to lower production in the Gulf of Mexico resulting from natural field decline and the subsequent sale of the assets in second quarter 2018; and
|
•
|
decrease of $13 million related to the divestiture of the Marcellus Shale upstream assets in second quarter 2017.
|
•
|
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 resulting from 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 following the partial divestiture in December 2016.
|
•
|
decrease of $17 million in the Gulf of Mexico due to lower production resulting from natural field decline and the subsequent sale of the assets in second quarter 2018; and
|
•
|
decrease of $88 million related to the divestiture of the Marcellus Shale upstream assets in second quarter 2017;
|
•
|
increase of $63 million related to increased activity in Delaware and DJ Basins.
|
•
|
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.
|
(millions)
|
Total
|
|
United States
|
|
Eastern Mediter-ranean
|
|
West
Africa
|
|
Other Int'l
|
||||||||||
Year Ended December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Leasehold Impairment and Amortization
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Dry Hole Cost (1)
|
1
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Seismic, Geological and Geophysical
|
22
|
|
|
8
|
|
|
3
|
|
|
—
|
|
|
11
|
|
|||||
Staff Expense
|
54
|
|
|
41
|
|
|
2
|
|
|
5
|
|
|
6
|
|
|||||
Other (2)
|
51
|
|
|
(3
|
)
|
|
2
|
|
|
1
|
|
|
51
|
|
|||||
Total Exploration Expense
|
$
|
129
|
|
|
$
|
48
|
|
|
$
|
7
|
|
|
$
|
6
|
|
|
$
|
68
|
|
Year Ended December 31, 2017
|
|
|
|
|
|
|
|
|
|
||||||||||
Leasehold Impairment and Amortization
|
$
|
62
|
|
|
$
|
60
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2
|
|
Dry Hole Cost (1)
|
9
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9
|
|
|||||
Seismic, Geological and Geophysical
|
27
|
|
|
8
|
|
|
—
|
|
|
—
|
|
|
19
|
|
|||||
Staff Expense
|
55
|
|
|
1
|
|
|
2
|
|
|
4
|
|
|
48
|
|
|||||
Other (2)
|
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 (1)
|
579
|
|
|
85
|
|
|
26
|
|
|
468
|
|
|
—
|
|
|||||
Seismic, Geological and Geophysical
|
76
|
|
|
—
|
|
|
—
|
|
|
10
|
|
|
66
|
|
|||||
Staff Expense
|
77
|
|
|
3
|
|
|
1
|
|
|
5
|
|
|
68
|
|
|||||
Other (2)
|
45
|
|
|
34
|
|
|
7
|
|
|
—
|
|
|
4
|
|
|||||
Total Exploration Expense
|
$
|
925
|
|
|
$
|
245
|
|
|
$
|
34
|
|
|
$
|
483
|
|
|
$
|
163
|
|
(1)
|
See Item 8. Financial Statements and Supplementary Data – Note 7. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
|
(2)
|
Includes lease rental and other exploration expense.
|
•
|
staff expense incurred across our US onshore assets.
|
•
|
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.
|
(millions, except unit rate)
|
Total
|
|
United
States |
|
Eastern
Mediter- ranean |
|
West
Africa |
|
Other Int'l
|
||||||||||
Year Ended December 31, 2018
|
|
|
|
|
|
|
|
|
|
||||||||||
DD&A Expense
|
$
|
1,819
|
|
|
$
|
1,642
|
|
|
$
|
60
|
|
|
$
|
115
|
|
|
$
|
2
|
|
Unit Rate per BOE (1)
|
$
|
14.42
|
|
|
$
|
17.66
|
|
|
$
|
4.13
|
|
|
$
|
6.17
|
|
|
$
|
—
|
|
Year 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
|
|
|
$
|
—
|
|
Year 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
|
|
|
$
|
—
|
|
•
|
decrease of $223 million due to both lower sales volumes in the Gulf of Mexico resulting from natural field decline and classification of the assets as held for sale in first quarter 2018, resulting in the cessation of DD&A expense;
|
•
|
decrease of $15 million due to reclassification of a 7.5% working interest in the Tamar field as assets held for sale at December 31, 2017, resulting in cessation of DD&A expense; and
|
•
|
decrease of $90 million due to the Marcellus Shale upstream divestiture in second quarter 2017;
|
•
|
higher sales volumes in the Delaware Basin, which almost doubled, due to increased development activities subsequent to the Clayton Williams Energy Acquisition in second quarter 2017.
|
•
|
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;
|
•
|
lower sales volumes in the DJ Basin and the impact of certain property divestitures since the second quarter 2016;
|
•
|
decrease of $291 million due to the Marcellus Shale upstream divestiture in second quarter 2017;
|
•
|
decrease of $7 million due to the sale of a 3.5% working interest in the Tamar field in December 2016;
|
•
|
decrease of $37 million due to a reduction in depletable costs of $153 million due to the reallocation of common asset costs from the Alen field, offshore Equatorial Guinea, to the West Africa natural gas monetization development project in second quarter 2017; and
|
•
|
lower sales volumes in the Gulf of Mexico resulting from natural field decline and reduction in the depletable costs due to downward revisions in estimates of ARO costs;
|
•
|
higher US onshore sales volumes of 29 MBoe/d, including 7 MBoe/d contributed by Clayton Williams Energy assets;
|
•
|
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 due to higher domestic demand.
|
•
|
net cash settlement payment of $161 million; and
|
•
|
net non-cash increase of $224 million in the fair value of our net commodity derivative asset, primarily driven by decreases in the forward commodity price curve for crude oil.
|
•
|
net cash settlement receipt of $13 million; and
|
•
|
net non-cash increase of $50 million in the fair value of our net commodity derivative liability, primarily driven by changes in the forward commodity price curves for both crude oil and natural gas.
|
•
|
net cash settlement receipt of $569 million; and
|
•
|
net non-cash decrease of $708 million in the fair value of our net commodity derivative liability, primarily driven by changes in the forward commodity price curves for both crude oil and natural gas.
|
•
|
completed the Saddle Butte Acquisition;
|
•
|
completed construction of the Coronado, Collier and Billy Miner Train II CGFs in the Delaware Basin;
|
•
|
completed construction of freshwater delivery infrastructure and commenced gathering services in the DJ Basin;
|
•
|
signed a non-binding letter of intent with Salt Creek for construction of a crude oil pipeline system in the Delaware Basin, for which definitive agreements with Salt Creek were executed in February 2019;
|
•
|
commenced natural gas compression in the Delaware Basin; and
|
•
|
in first quarter 2019, exercised options to acquire equity interests in the EPIC Y-Grade Pipeline and the EPIC Crude Oil Pipeline.
|
•
|
pre-tax income of $726 million, as compared with pre-tax income of $233 million for 2017;
|
•
|
net proceeds of approximately $696 million received, and gain of $503 million recognized, on the sale of our interest in CONE Gathering and sale of our investment in CNX Midstream Partners common units; and
|
•
|
capital expenditures, excluding acquisitions, of $521 million, as compared with $399 million for 2017.
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
2018
|
|
2017
|
|
2016
|
||||||
Midstream Services Revenues – Third Party
|
$
|
78
|
|
|
$
|
19
|
|
|
$
|
—
|
|
Sales of Purchased Oil
|
142
|
|
|
—
|
|
|
—
|
|
|||
Income from Equity Method Investees
|
40
|
|
|
57
|
|
|
52
|
|
|||
Intersegment Revenues
|
351
|
|
|
277
|
|
|
200
|
|
|||
Total Revenues
|
611
|
|
|
353
|
|
|
252
|
|
|||
Operating Costs and Expenses
|
128
|
|
|
90
|
|
|
57
|
|
|||
Depreciation, Depletion and Amortization
|
87
|
|
|
30
|
|
|
19
|
|
|||
Gain on Divestiture, Net
|
(503
|
)
|
|
—
|
|
|
—
|
|
|||
Asset Impairments
|
37
|
|
|
—
|
|
|
—
|
|
|||
Cost of Purchased Oil
|
136
|
|
|
—
|
|
|
—
|
|
|||
Total (Income) Expense
|
(115
|
)
|
|
120
|
|
|
76
|
|
|||
Income Before Income Taxes
|
726
|
|
|
233
|
|
|
176
|
|
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
|
2018
|
|
2017
|
|
2016
|
||||||
Net Income
|
|
|
|
|
|
|
||||||
CONE Gathering and CONE Midstream (1)
|
|
$
|
24
|
|
|
$
|
51
|
|
|
$
|
48
|
|
Advantage Pipeline
|
|
12
|
|
|
2
|
|
|
—
|
|
|||
Other
|
|
4
|
|
|
4
|
|
|
5
|
|
|||
Dividends
|
|
|
|
|
|
|
||||||
CONE Gathering and CONE Midstream (1)
|
|
19
|
|
|
25
|
|
|
27
|
|
|||
Advantage Pipeline
|
|
9
|
|
|
—
|
|
|
—
|
|
(1)
|
Investments were sold in separate transactions in 2018. See Item 8. Financial Statements and Supplementary Data – Note 5. Acquisitions and Divestitures.
|
•
|
increase of $21 million due to the addition of expenses associated with the Black Diamond gathering system acquired in the Saddle Butte Acquisition in first quarter 2018;
|
•
|
increase of $12 million in gathering, transportation and processing expense associated with the new CGFs in the Delaware Basin and commencement of gathering services in the Mustang IDP area of the DJ Basin.
|
•
|
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;
|
•
|
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; and
|
•
|
increase of $7 million in general and administrative and other expenses, primarily related to increased third-party legal and advisory fees resulting from transactions.
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
2018
|
|
2017
|
|
2016
|
||||||
Sales of Purchased Gas
|
$
|
113
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Loss on Marcellus Shale Upstream Divestiture and Other (1)
|
—
|
|
|
(93
|
)
|
|
—
|
|
|||
Cost of Purchased Gas
|
(140
|
)
|
|
—
|
|
|
—
|
|
(1)
|
Represents accrued non-cash exit costs related to certain retained Marcellus Shale firm transportation contracts.
|
|
Year Ended December 31,
|
||||||||||
(millions, except unit rate)
|
2018
|
|
2017
|
|
2016
|
||||||
G&A Expense
|
$
|
385
|
|
|
$
|
415
|
|
|
$
|
399
|
|
Unit Rate per BOE (1)
|
$
|
3.05
|
|
|
$
|
3.05
|
|
|
$
|
2.64
|
|
(1)
|
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.
|
|
Year Ended December 31,
|
||||||||||
(millions, except unit rate)
|
2018
|
|
2017
|
|
2016
|
||||||
Interest Expense
|
$
|
355
|
|
|
$
|
403
|
|
|
$
|
412
|
|
Capitalized Interest
|
(73
|
)
|
|
(49
|
)
|
|
(84
|
)
|
|||
Interest Expense, Net
|
$
|
282
|
|
|
$
|
354
|
|
|
$
|
328
|
|
Unit Rate per BOE (1)
|
$
|
2.23
|
|
|
$
|
2.60
|
|
|
$
|
2.17
|
|
(1)
|
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.
|
|
December 31,
|
||||||||||
(millions, except percentages)
|
2018
|
|
2017
|
|
2016
|
||||||
Total Cash (1)
|
$
|
719
|
|
|
$
|
713
|
|
|
$
|
1,210
|
|
Amount Available to be Borrowed under Revolving Credit Facility (2)
|
4,000
|
|
|
3,770
|
|
|
4,000
|
|
|||
Total Liquidity
|
$
|
4,719
|
|
|
$
|
4,483
|
|
|
$
|
5,210
|
|
Total Debt (3)
|
$
|
6,675
|
|
|
$
|
6,859
|
|
|
$
|
7,114
|
|
Noble Energy Share of Equity
|
10,484
|
|
|
10,619
|
|
|
9,600
|
|
|||
Ratio of Debt-to-Book Capital (4)
|
39
|
%
|
|
39
|
%
|
|
43
|
%
|
(1)
|
As of December 31, 2018, total cash includes cash and cash equivalents of $11 million related to Noble Midstream Partners and $3 million of restricted cash related to amounts held for the divestiture of certain non-core acreage in the Delaware Basin and Noble Midstream Partners collateral on letters of credit. As of December 31, 2017, total cash includes $18 million cash of Noble Midstream Partners and $38 million of restricted cash related to the Saddle Butte Acquisition that closed first quarter 2018. As of December 31, 2016, total cash 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)
|
Excludes amounts available to be borrowed under the Noble Midstream Services Revolving Credit Facility, which is not available to Noble Energy for general corporate purposes.
|
(3)
|
Total debt includes capital lease obligations and excludes unamortized debt discount/premium and debt issuance costs. Additionally, it includes $560 million of Noble Midstream Partners debt as of December 31, 2018.
|
(4)
|
We define our ratio of debt-to-book capital as total debt (which includes long-term debt excluding unamortized discount/premium and issuance costs, the current portion of long-term debt, and short-term borrowings) divided by the sum of total debt plus Noble Energy's share of equity.
|
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
|
2018
|
|
2017
|
|
2016
|
||||||
Total Cash Provided By (Used in)
|
|
|
|
|
|
|
||||||
Operating Activities
|
|
$
|
2,336
|
|
|
$
|
1,951
|
|
|
$
|
1,351
|
|
Investing Activities
|
|
(1,931
|
)
|
|
(1,617
|
)
|
|
(401
|
)
|
|||
Financing Activities
|
|
(399
|
)
|
|
(831
|
)
|
|
(768
|
)
|
|||
Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash
|
|
$
|
6
|
|
|
$
|
(497
|
)
|
|
$
|
182
|
|
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
|
2018
|
|
2017
|
|
2016
|
||||||
Acquisition, Capital and Exploration Expenditures
|
|
|
|
|
|
|
|
|
||||
Unproved Property Acquisition (1)
|
|
$
|
41
|
|
|
$
|
1,817
|
|
|
$
|
234
|
|
Proved Property Acquisition (2)
|
|
—
|
|
|
839
|
|
|
—
|
|
|||
Exploration and Development
|
|
2,683
|
|
|
2,352
|
|
|
1,239
|
|
|||
Midstream (3)
|
|
727
|
|
|
480
|
|
|
42
|
|
|||
Corporate
|
|
60
|
|
|
34
|
|
|
50
|
|
|||
Total
|
|
$
|
3,511
|
|
|
$
|
5,522
|
|
|
$
|
1,565
|
|
Other
|
|
|
|
|
|
|
|
|
||||
Investment in Equity Method Investee (4)
|
|
$
|
—
|
|
|
$
|
68
|
|
|
$
|
8
|
|
Increase in Capital Lease Obligations
|
|
14
|
|
|
—
|
|
|
5
|
|
(1)
|
2018 costs relate to US onshore undeveloped leasehold activity.
|
(2)
|
2017 costs include $722 million of proved properties and $63 million of ARO acquired in the Clayton Williams Energy Acquisition and $58 million of proved properties acquired in the Delaware Basin.
|
(3)
|
Midstream expenditures include those of Noble Midstream Partners.
|
(4)
|
2017 includes our contribution to the Advantage Pipeline joint venture, in which Noble Midstream Partners owns a 50% interest.
|
(millions)
|
Note
Reference (1) |
Total
|
|
2019
|
|
2020 and 2021
|
|
2022 and 2023
|
|
2024 and beyond
|
||||||||||
Long-Term Debt (2)
|
$
|
6,452
|
|
|
$
|
—
|
|
|
$
|
1,500
|
|
|
$
|
160
|
|
|
$
|
4,792
|
|
|
Interest Payments (3)
|
5,490
|
|
|
295
|
|
|
589
|
|
|
505
|
|
|
4,101
|
|
||||||
Capital Lease Obligations (4)
|
275
|
|
|
52
|
|
|
77
|
|
|
42
|
|
|
104
|
|
||||||
Purchase and Service Obligations (5)
|
271
|
|
|
197
|
|
|
42
|
|
|
27
|
|
|
5
|
|
||||||
Marcellus Shale Firm Transportation and Other Obligations (6)
|
1,531
|
|
|
123
|
|
|
243
|
|
|
231
|
|
|
934
|
|
||||||
Gathering, Transportation and Processing Obligations
|
801
|
|
|
151
|
|
|
232
|
|
|
133
|
|
|
285
|
|
||||||
Operating Lease Obligations (7)
|
512
|
|
|
91
|
|
|
133
|
|
|
112
|
|
|
176
|
|
||||||
Other Liabilities (8)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Asset Retirement Obligations (9)
|
880
|
|
|
118
|
|
|
147
|
|
|
67
|
|
|
548
|
|
||||||
Commodity Derivative Instruments (10)
|
27
|
|
|
1
|
|
|
26
|
|
|
—
|
|
|
—
|
|
||||||
Total Contractual Obligations
|
|
$
|
16,239
|
|
|
$
|
1,028
|
|
|
$
|
2,989
|
|
|
$
|
1,277
|
|
|
$
|
10,945
|
|
(1)
|
(2)
|
Long-term debt includes our revolving credit facilities and fixed-rate debt and excludes unamortized discounts, premiums, debt issuance costs and capital lease obligations.
|
(3)
|
Interest payments are based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2018.
|
(4)
|
Annual capital lease payments exclude regular maintenance and operational costs.
|
(5)
|
Purchase and service obligations represent 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.
|
(6)
|
Amount includes exit cost obligations resulting from a permanent capacity assignment. In addition, we entered into a permanent capacity assignment in January 2019 which reduced the undiscounted financial commitment by approximately $350 million.
|
(7)
|
Operating lease obligations represent non-cancelable leases for office buildings, facilities and equipment used in our daily operations, such as drilling rigs, vessels and compressors. Annual lease payments exclude regular maintenance and operational costs.
|
(8)
|
The table excludes deferred compensation liabilities of $147 million as specific payment dates are unknown. See Item 8. Financial Statements and Supplementary Data – Note 17. Stock-Based and Other Compensation Plans.
|
(9)
|
AROs are discounted.
|
(10)
|
Amount represents commodity derivative instruments that were in a net payable position with the counterparty at December 31, 2018.
|
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 19, 2019
|
|
|
|
|
|
|
/s/ KPMG LLP
|
|
|
Houston, Texas
|
|
|
|
|
February 19, 2019
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Revenues
|
|
|
|
|
|
||||||
Oil, NGL and Gas Sales
|
$
|
4,461
|
|
|
$
|
4,060
|
|
|
$
|
3,389
|
|
Sales of Purchased Oil and Gas and Other
|
525
|
|
|
196
|
|
|
102
|
|
|||
Total
|
4,986
|
|
|
4,256
|
|
|
3,491
|
|
|||
Costs and Expenses
|
|
|
|
|
|
||||||
Production Expense
|
1,197
|
|
|
1,141
|
|
|
1,100
|
|
|||
Exploration Expense
|
129
|
|
|
188
|
|
|
925
|
|
|||
Depreciation, Depletion and Amortization
|
1,934
|
|
|
2,053
|
|
|
2,454
|
|
|||
Loss on Marcellus Shale Upstream Divestiture and Other
|
—
|
|
|
2,379
|
|
|
—
|
|
|||
Gain on Divestitures, Net
|
(843
|
)
|
|
(326
|
)
|
|
(238
|
)
|
|||
Asset Impairments
|
206
|
|
|
70
|
|
|
92
|
|
|||
Goodwill Impairment
|
1,281
|
|
|
—
|
|
|
—
|
|
|||
General and Administrative
|
385
|
|
|
415
|
|
|
399
|
|
|||
Other Operating Expense, Net
|
346
|
|
|
138
|
|
|
135
|
|
|||
Total
|
4,635
|
|
|
6,058
|
|
|
4,867
|
|
|||
Operating Income (Loss)
|
351
|
|
|
(1,802
|
)
|
|
(1,376
|
)
|
|||
Other Expense
|
|
|
|
|
|
||||||
(Gain) Loss on Commodity Derivative Instruments
|
(63
|
)
|
|
(63
|
)
|
|
139
|
|
|||
Loss (Gain) on Extinguishment of Facility or Debt
|
8
|
|
|
98
|
|
|
(80
|
)
|
|||
Interest, Net of Amount Capitalized
|
282
|
|
|
354
|
|
|
328
|
|
|||
Other Non-Operating (Income) Expense, Net
|
(16
|
)
|
|
—
|
|
|
9
|
|
|||
Total
|
211
|
|
|
389
|
|
|
396
|
|
|||
Income (Loss) Before Income Taxes
|
140
|
|
|
(2,191
|
)
|
|
(1,772
|
)
|
|||
Income Tax Expense (Benefit)
|
126
|
|
|
(1,141
|
)
|
|
(787
|
)
|
|||
Net Income (Loss) and Comprehensive Income (Loss) Including Noncontrolling Interests
|
14
|
|
|
(1,050
|
)
|
|
(985
|
)
|
|||
Less: Net Income and Comprehensive Income Attributable to Noncontrolling Interests
|
80
|
|
|
68
|
|
|
13
|
|
|||
Net Loss and Comprehensive Loss Attributable to Noble Energy
|
$
|
(66
|
)
|
|
$
|
(1,118
|
)
|
|
$
|
(998
|
)
|
|
|
|
|
|
|
||||||
Loss Attributable to Noble Energy per Common Share
|
|
|
|
|
|
||||||
Basic and Diluted
|
$
|
(0.14
|
)
|
|
$
|
(2.38
|
)
|
|
$
|
(2.32
|
)
|
Weighted Average Number of Shares Outstanding
|
|
|
|
|
|
||||||
Basic and Diluted
|
483
|
|
|
469
|
|
|
430
|
|
|
December 31,
2018 |
|
December 31,
2017 |
||||
ASSETS
|
|
|
|
||||
Current Assets
|
|
|
|
||||
Cash and Cash Equivalents
|
$
|
716
|
|
|
$
|
675
|
|
Accounts Receivable, Net
|
616
|
|
|
748
|
|
||
Other Current Assets
|
418
|
|
|
780
|
|
||
Total Current Assets
|
1,750
|
|
|
2,203
|
|
||
Property, Plant and Equipment
|
|
|
|
||||
Oil and Gas Properties (Successful Efforts Method of Accounting)
|
29,002
|
|
|
29,678
|
|
||
Property, Plant and Equipment, Other
|
891
|
|
|
879
|
|
||
Total Property, Plant and Equipment, Gross
|
29,893
|
|
|
30,557
|
|
||
Accumulated Depreciation, Depletion and Amortization
|
(11,474
|
)
|
|
(13,055
|
)
|
||
Total Property, Plant and Equipment, Net
|
18,419
|
|
|
17,502
|
|
||
Other Noncurrent Assets
|
731
|
|
|
461
|
|
||
Goodwill
|
110
|
|
|
1,310
|
|
||
Total Assets
|
$
|
21,010
|
|
|
$
|
21,476
|
|
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
|
|
||||
Current Liabilities
|
|
|
|
||||
Accounts Payable - Trade
|
$
|
1,207
|
|
|
$
|
1,161
|
|
Other Current Liabilities
|
519
|
|
|
578
|
|
||
Total Current Liabilities
|
1,726
|
|
|
1,739
|
|
||
Long-Term Debt
|
6,574
|
|
|
6,746
|
|
||
Deferred Income Taxes
|
1,061
|
|
|
1,127
|
|
||
Other Noncurrent Liabilities
|
1,165
|
|
|
1,245
|
|
||
Total Liabilities
|
10,526
|
|
|
10,857
|
|
||
Commitments and Contingencies
|
|
|
|
||||
Shareholders’ Equity
|
|
|
|
||||
Preferred Stock - Par Value $1.00 per share; 4 Million Shares Authorized; None Issued
|
—
|
|
|
—
|
|
||
Common Stock - Par Value $0.01 per share; 1 Billion Shares Authorized; 520 Million and 529 Million Shares Issued, respectively
|
5
|
|
|
5
|
|
||
Additional Paid in Capital
|
8,203
|
|
|
8,438
|
|
||
Accumulated Other Comprehensive Loss
|
(32
|
)
|
|
(30
|
)
|
||
Treasury Stock, at Cost; 39 Million Shares
|
(730
|
)
|
|
(725
|
)
|
||
Retained Earnings
|
1,980
|
|
|
2,248
|
|
||
Noble Energy Share of Equity
|
9,426
|
|
|
9,936
|
|
||
Noncontrolling Interests
|
1,058
|
|
|
683
|
|
||
Total Equity
|
10,484
|
|
|
10,619
|
|
||
Total Liabilities and Equity
|
$
|
21,010
|
|
|
$
|
21,476
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Cash Flows From Operating Activities
|
|
|
|
|
|
||||||
Net Income (Loss) Including Noncontrolling Interests
|
$
|
14
|
|
|
$
|
(1,050
|
)
|
|
$
|
(985
|
)
|
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
|
|
|
|
|
|
|
|
||||
Depreciation, Depletion and Amortization
|
1,934
|
|
|
2,053
|
|
|
2,454
|
|
|||
Loss on Marcellus Shale Upstream Divestiture and Other
|
—
|
|
|
2,379
|
|
|
—
|
|
|||
Gain on Divestitures, Net
|
(843
|
)
|
|
(326
|
)
|
|
(238
|
)
|
|||
Asset Impairments
|
206
|
|
|
70
|
|
|
92
|
|
|||
Goodwill Impairment
|
1,281
|
|
|
—
|
|
|
—
|
|
|||
Deferred Income Tax Benefit
|
(70
|
)
|
|
(1,227
|
)
|
|
(984
|
)
|
|||
Loss (Gain) on Extinguishment of Facility or Debt, Net
|
4
|
|
|
98
|
|
|
(80
|
)
|
|||
(Gain) Loss on Commodity Derivative Instruments
|
(63
|
)
|
|
(63
|
)
|
|
139
|
|
|||
Net Cash (Paid) Received in Settlement of Commodity Derivative Instruments
|
(161
|
)
|
|
13
|
|
|
569
|
|
|||
Stock Based Compensation
|
62
|
|
|
104
|
|
|
77
|
|
|||
Undeveloped Leasehold Impairment
|
1
|
|
|
62
|
|
|
93
|
|
|||
Dry Hole Cost
|
1
|
|
|
9
|
|
|
579
|
|
|||
Other Adjustments for Noncash Items Included in Net Income (Loss)
|
17
|
|
|
(21
|
)
|
|
95
|
|
|||
Changes in Operating Assets and Liabilities
|
|
|
|
|
|
||||||
Decrease (Increase) in Accounts Receivable
|
156
|
|
|
(171
|
)
|
|
(151
|
)
|
|||
(Decrease) Increase in Accounts Payable
|
(63
|
)
|
|
248
|
|
|
(111
|
)
|
|||
Increase (Decrease) in Current Income Taxes Payable
|
22
|
|
|
(36
|
)
|
|
(32
|
)
|
|||
Other Current Assets and Liabilities, Net
|
(36
|
)
|
|
(71
|
)
|
|
(76
|
)
|
|||
Other Operating Assets and Liabilities, Net
|
(126
|
)
|
|
(120
|
)
|
|
(90
|
)
|
|||
Net Cash Provided by Operating Activities
|
2,336
|
|
|
1,951
|
|
|
1,351
|
|
|||
Cash Flows From Investing Activities
|
|
|
|
|
|
|
|
||||
Additions to Property, Plant and Equipment
|
(3,279
|
)
|
|
(2,649
|
)
|
|
(1,541
|
)
|
|||
Acquisitions, Net of Cash Received
|
(653
|
)
|
|
(954
|
)
|
|
30
|
|
|||
Proceeds from Divestitures
|
1,999
|
|
|
2,073
|
|
|
1,241
|
|
|||
Marcellus Shale Acreage Exchange Consideration
|
—
|
|
|
—
|
|
|
(213
|
)
|
|||
Other
|
2
|
|
|
(87
|
)
|
|
82
|
|
|||
Net Cash Used in Investing Activities
|
(1,931
|
)
|
|
(1,617
|
)
|
|
(401
|
)
|
|||
Cash Flows From Financing Activities
|
|
|
|
|
|
|
|
||||
Proceeds from Revolving Credit Facility
|
1,580
|
|
|
1,585
|
|
|
—
|
|
|||
Repayment of Revolving Credit Facility
|
(1,810
|
)
|
|
(1,355
|
)
|
|
—
|
|
|||
Proceeds from Term Loan Facility
|
—
|
|
|
—
|
|
|
1,400
|
|
|||
Repayment of Term Loan Facility
|
—
|
|
|
(550
|
)
|
|
(850
|
)
|
|||
Proceeds from Noble Midstream Services Revolving Credit Facility
|
777
|
|
|
325
|
|
|
—
|
|
|||
Repayment of Noble Midstream Services Revolving Credit Facility
|
(802
|
)
|
|
(240
|
)
|
|
—
|
|
|||
Proceeds from Noble Midstream Services Term Loan Credit Facility
|
500
|
|
|
—
|
|
|
—
|
|
|||
Repayment of Senior Notes
|
(384
|
)
|
|
(1,114
|
)
|
|
(1,383
|
)
|
|||
Repayment of Clayton Williams Energy Long-term Debt
|
—
|
|
|
(595
|
)
|
|
—
|
|
|||
Proceeds from Issuance of Senior Notes
|
—
|
|
|
1,086
|
|
|
—
|
|
|||
Dividends Paid, Common Stock
|
(208
|
)
|
|
(190
|
)
|
|
(172
|
)
|
|||
Purchase and Retirement of Common Stock
|
(295
|
)
|
|
—
|
|
|
—
|
|
|||
Issuance of Noble Midstream Partners Common Units, Net of Offering Costs
|
—
|
|
|
312
|
|
|
299
|
|
|||
Contributions from Noncontrolling Interest Owners
|
353
|
|
|
19
|
|
|
—
|
|
|||
Other
|
(110
|
)
|
|
(114
|
)
|
|
(62
|
)
|
|||
Net Cash Used in Financing Activities
|
(399
|
)
|
|
(831
|
)
|
|
(768
|
)
|
|||
Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash
|
6
|
|
|
(497
|
)
|
|
182
|
|
|||
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period
|
713
|
|
|
1,210
|
|
|
1,028
|
|
|||
Cash, Cash Equivalents, and Restricted Cash at End of Period
|
$
|
719
|
|
|
$
|
713
|
|
|
$
|
1,210
|
|
|
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, 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
|
|
|||||||
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
|
)
|
|||||||
Other
|
—
|
|
|
2
|
|
|
1
|
|
|
(8
|
)
|
|
—
|
|
|
19
|
|
|
14
|
|
|||||||
December 31, 2017
|
$
|
5
|
|
|
$
|
8,438
|
|
|
$
|
(30
|
)
|
|
$
|
(725
|
)
|
|
$
|
2,248
|
|
|
$
|
683
|
|
|
$
|
10,619
|
|
Net (Loss) Income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(66
|
)
|
|
80
|
|
|
14
|
|
|||||||
Stock-based Compensation
|
—
|
|
|
78
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
78
|
|
|||||||
Dividends (43 cents per share)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(208
|
)
|
|
—
|
|
|
(208
|
)
|
|||||||
Purchase and Retirement of Common Stock
|
—
|
|
|
(295
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(295
|
)
|
|||||||
Clayton Williams Energy Acquisition
|
—
|
|
|
(25
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(25
|
)
|
|||||||
Distributions to Noncontrolling Interest Owners
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(51
|
)
|
|
(51
|
)
|
|||||||
Contributions from Noncontrolling Interest Owners
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
353
|
|
|
353
|
|
|||||||
Other
|
—
|
|
|
7
|
|
|
(2
|
)
|
|
(5
|
)
|
|
6
|
|
|
(7
|
)
|
|
(1
|
)
|
|||||||
December 31, 2018
|
$
|
5
|
|
|
$
|
8,203
|
|
|
$
|
(32
|
)
|
|
$
|
(730
|
)
|
|
$
|
1,980
|
|
|
$
|
1,058
|
|
|
$
|
10,484
|
|
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
|
|
•
|
elect the package of 'practical expedients', which permits us not to reassess under the new standard our prior conclusions about lease identification, lease classification and initial direct costs;
|
•
|
elect the practical expedient pertaining to land easements and plan to account for existing land easements under our current accounting policy;
|
•
|
elect the short-term lease recognition exemption for all leases that qualify and, as such, no ROU asset or lease liability will be recorded on the balance sheet and no transition adjustment will be required for short-term leases; and
|
•
|
elect the practical expedient to not separate lease and non-lease components for all of our leases.
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
|
2018
|
|
2017
|
|
2016
|
||||||
Sales of Purchased Oil and Gas and Other
|
|
|
|
|
|
|
|
|
|
|||
Sales of Purchased Oil and Gas (1)
|
|
$
|
275
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Income from Equity Method Investees
|
|
172
|
|
|
177
|
|
|
102
|
|
|||
Midstream Services Revenues - Third Party
|
|
78
|
|
|
19
|
|
|
—
|
|
|||
Total
|
|
$
|
525
|
|
|
$
|
196
|
|
|
$
|
102
|
|
Production Expense
|
|
|
|
|
|
|
||||||
Lease Operating Expense
|
|
$
|
576
|
|
|
$
|
571
|
|
|
$
|
542
|
|
Production and Ad Valorem Taxes
|
|
190
|
|
|
118
|
|
|
57
|
|
|||
Gathering, Transportation and Processing Expense
|
|
393
|
|
|
432
|
|
|
480
|
|
|||
Other Royalty Expense
|
|
38
|
|
|
20
|
|
|
21
|
|
|||
Total
|
|
$
|
1,197
|
|
|
$
|
1,141
|
|
|
$
|
1,100
|
|
Exploration Expense
|
|
|
|
|
|
|
||||||
Leasehold Impairment and Amortization
|
|
$
|
1
|
|
|
$
|
62
|
|
|
$
|
148
|
|
Dry Hole Cost
|
|
1
|
|
|
9
|
|
|
579
|
|
|||
Seismic, Geological and Geophysical
|
|
22
|
|
|
27
|
|
|
76
|
|
|||
Staff Expense
|
|
54
|
|
|
55
|
|
|
77
|
|
|||
Other
|
|
51
|
|
|
35
|
|
|
45
|
|
|||
Total
|
|
$
|
129
|
|
|
$
|
188
|
|
|
$
|
925
|
|
Loss on Marcellus Shale Upstream Divestiture and Other
|
|
|
|
|
|
|
||||||
Loss on Sale
|
|
$
|
—
|
|
|
$
|
2,270
|
|
|
$
|
—
|
|
Exit Cost
|
|
—
|
|
|
93
|
|
|
—
|
|
|||
Other
|
|
—
|
|
|
16
|
|
|
—
|
|
|||
Total
|
|
$
|
—
|
|
|
$
|
2,379
|
|
|
$
|
—
|
|
Other Operating Expense, Net
|
|
|
|
|
|
|
|
|
|
|||
Marketing Expense (2)
|
|
$
|
40
|
|
|
$
|
47
|
|
|
$
|
58
|
|
Cost of Purchased Oil and Gas (1)
|
|
296
|
|
|
—
|
|
|
—
|
|
|||
Clayton Williams Energy Acquisition Expenses
|
|
—
|
|
|
100
|
|
|
—
|
|
|||
Gain on Asset Retirement Obligation Revisions (3)
|
|
(25
|
)
|
|
(42
|
)
|
|
—
|
|
|||
Other, Net
|
|
35
|
|
|
33
|
|
|
77
|
|
|||
Total
|
|
$
|
346
|
|
|
$
|
138
|
|
|
$
|
135
|
|
(1)
|
As part of the Saddle Butte Acquisition in first quarter 2018, we acquired certain contracts which include the purchase and sale of crude oil with third parties. In addition, we entered into certain transactions beginning in first quarter 2018 for the purchase of third-party natural gas and the subsequent sale of natural gas to other third parties. The natural gas is transported through firm transportation capacity we retained following the Marcellus Shale upstream divestiture in second quarter 2017 and is part of our mitigation efforts to utilize capacity and reduce our financial commitment. See Note 3. Segment Information and Note 10. Marcellus Shale Firm Transportation Commitments.
|
(2)
|
Amounts relate to shortfalls in transporting or processing minimum volumes under certain financial commitments primarily in the DJ Basin for 2018 and in the DJ Basin and Marcellus Shale for 2017 (prior to the Marcellus Shale upstream divestiture) and 2016.
|
(3)
|
Gains due to downward ARO revisions in locations where we have no remaining assets. See Note 8. Asset Retirement Obligations.
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
December 31,
|
||||||
(millions)
|
|
2018
|
|
2017
|
||||
Accounts Receivable, Net
|
|
|
|
|
||||
Commodity Sales
|
|
$
|
383
|
|
|
$
|
455
|
|
Joint Interest Billings (1)
|
|
137
|
|
|
207
|
|
||
Other
|
|
111
|
|
|
103
|
|
||
Allowance for Doubtful Accounts
|
|
(15
|
)
|
|
(17
|
)
|
||
Total
|
|
$
|
616
|
|
|
$
|
748
|
|
Other Current Assets
|
|
|
|
|
|
|
||
Commodity Derivative Assets
|
|
$
|
180
|
|
|
$
|
—
|
|
Inventories, Materials and Supplies
|
|
55
|
|
|
66
|
|
||
Inventories, Crude Oil
|
|
12
|
|
|
16
|
|
||
Assets Held for Sale (2)
|
|
133
|
|
|
629
|
|
||
Restricted Cash (3)
|
|
3
|
|
|
38
|
|
||
Prepaid Expenses and Other Assets, Current
|
|
35
|
|
|
31
|
|
||
Total
|
|
$
|
418
|
|
|
$
|
780
|
|
Other Noncurrent Assets
|
|
|
|
|
||||
Equity Method Investments
|
|
$
|
286
|
|
|
$
|
305
|
|
Customer-Related Intangible Assets, Net (4)
|
|
310
|
|
|
—
|
|
||
Mutual Fund Investments
|
|
38
|
|
|
57
|
|
||
Net Deferred Income Tax Asset
|
|
21
|
|
|
25
|
|
||
Other Assets, Noncurrent
|
|
76
|
|
|
74
|
|
||
Total
|
|
$
|
731
|
|
|
$
|
461
|
|
Other Current Liabilities
|
|
|
|
|
||||
Production and Ad Valorem Taxes
|
|
$
|
103
|
|
|
$
|
84
|
|
Commodity Derivative Liabilities
|
|
1
|
|
|
58
|
|
||
Income Taxes Payable
|
|
22
|
|
|
18
|
|
||
Asset Retirement Obligations
|
|
118
|
|
|
51
|
|
||
Interest Payable
|
|
66
|
|
|
67
|
|
||
Current Portion of Capital Lease Obligations
|
|
41
|
|
|
61
|
|
||
Liabilities Associated with Assets Held for Sale (2)
|
|
1
|
|
|
55
|
|
||
Compensation and Benefits Payable
|
|
83
|
|
|
98
|
|
||
Other Liabilities, Current
|
|
84
|
|
|
86
|
|
||
Total
|
|
$
|
519
|
|
|
$
|
578
|
|
Other Noncurrent Liabilities
|
|
|
|
|
||||
Deferred Compensation Liabilities
|
|
$
|
147
|
|
|
$
|
197
|
|
Asset Retirement Obligations
|
|
762
|
|
|
824
|
|
||
Marcellus Shale Exit Cost Accrual
|
|
67
|
|
|
76
|
|
||
Production and Ad Valorem Taxes
|
|
83
|
|
|
69
|
|
||
Commodity Derivative Liabilities
|
|
26
|
|
|
15
|
|
||
Other Liabilities, Noncurrent
|
|
80
|
|
|
64
|
|
||
Total
|
|
$
|
1,165
|
|
|
$
|
1,245
|
|
(1)
|
We bill partners for their share of expenses of joint venture projects for which we are the operator. These projects, especially those in deepwater or remote international locations, can be very capital cost intensive. Our receivables from joint interest billings decreased significantly in 2018 due to the second quarter 2018 sale of our Gulf of Mexico offshore assets.
|
(2)
|
Assets held for sale at December 31, 2018 include certain proved and unproved non-core acreage in Reeves County, Texas. Assets held for sale at December 31, 2017 include assets in the Greeley Crescent area of the DJ Basin, a 7.5% interest in the Tamar field, our investment in Southwest Royalties, Inc. acquired in the Clayton Williams Energy Acquisition, and the CONE investments, including
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
(3)
|
Balance at December 31, 2018 represents amounts held for the divestiture of certain non-core acreage in the Delaware Basin and Noble Midstream Partners collateral on letters of credit. Balance at December 31, 2017 represents amount held in escrow pending closing of the Saddle Butte Acquisition. See Note 5. Acquisitions and Divestitures.
|
(4)
|
Amount relates to intangible assets acquired in the Saddle Butte Acquisition. See Note 5. Acquisitions and Divestitures.
|
|
|
December 31,
|
||||||
(millions)
|
|
2018
|
|
2017
|
||||
Cash and Cash Equivalents at Beginning of Period
|
|
$
|
675
|
|
|
$
|
1,180
|
|
Restricted Cash at Beginning of Period
|
|
38
|
|
|
30
|
|
||
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period
|
|
$
|
713
|
|
|
$
|
1,210
|
|
Cash and Cash Equivalents at End of Period
|
|
$
|
716
|
|
|
$
|
675
|
|
Restricted Cash at End of Period
|
|
3
|
|
|
38
|
|
||
Cash, Cash Equivalents, and Restricted Cash at End of Period
|
|
$
|
719
|
|
|
$
|
713
|
|
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
|
2018
|
|
2017
|
|
2016
|
||||||
Cash Paid During the Year For
|
|
|
|
|
|
|
||||||
Interest, Net of Amount Capitalized
|
|
$
|
270
|
|
|
$
|
346
|
|
|
$
|
327
|
|
Income Taxes Paid, Net
|
|
172
|
|
|
121
|
|
|
236
|
|
|||
Non-Cash Financing and Investing Activities
|
|
|
|
|
|
|
||||||
Increase in Capital Lease Obligations
|
|
14
|
|
|
—
|
|
|
5
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
|
Oil and Gas Exploration and Production
|
|
Midstream
|
|
|
||||||||||||||||||||||||
(millions)
|
Consolidated
|
|
United
States |
|
Eastern
Mediter- ranean |
|
West
Africa |
|
Other Int'l
|
|
United States
|
|
Intersegment Eliminations and Other (1)
|
|
Corporate
|
||||||||||||||||
Year Ended December 31, 2018
|
|||||||||||||||||||||||||||||||
Crude Oil Sales
|
$
|
2,945
|
|
|
$
|
2,548
|
|
|
$
|
7
|
|
|
$
|
390
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
NGL Sales
|
587
|
|
|
587
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Natural Gas Sales
|
929
|
|
|
435
|
|
|
473
|
|
|
21
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Total Crude Oil, NGL and Natural Gas Sales
|
4,461
|
|
|
3,570
|
|
|
480
|
|
|
411
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Sales of Purchased Oil and Gas
|
275
|
|
|
20
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
142
|
|
|
—
|
|
|
113
|
|
||||||||
Income from Equity Method Investees
|
172
|
|
|
—
|
|
|
—
|
|
|
132
|
|
|
—
|
|
|
40
|
|
|
—
|
|
|
—
|
|
||||||||
Midstream Services Revenues - Third Party
|
78
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
78
|
|
|
—
|
|
|
—
|
|
||||||||
Intersegment Revenues
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
351
|
|
|
(351
|
)
|
|
|
|
||||||||
Total Revenues
|
4,986
|
|
|
3,590
|
|
|
480
|
|
|
543
|
|
|
—
|
|
|
611
|
|
|
(351
|
)
|
|
113
|
|
||||||||
Lease Operating Expense
|
576
|
|
|
480
|
|
|
26
|
|
|
97
|
|
|
—
|
|
|
—
|
|
|
(27
|
)
|
|
—
|
|
||||||||
Production and Ad Valorem Taxes
|
190
|
|
|
184
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6
|
|
|
—
|
|
|
—
|
|
||||||||
Gathering, Transportation and Processing Expense
|
393
|
|
|
533
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
95
|
|
|
(235
|
)
|
|
—
|
|
||||||||
Other Royalty Expense
|
38
|
|
|
38
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Total Production Expense
|
1,197
|
|
|
1,235
|
|
|
26
|
|
|
97
|
|
|
—
|
|
|
101
|
|
|
(262
|
)
|
|
—
|
|
||||||||
Exploration Expense
|
129
|
|
|
48
|
|
|
7
|
|
|
6
|
|
|
68
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
DD&A
|
1,934
|
|
|
1,642
|
|
|
60
|
|
|
115
|
|
|
2
|
|
|
87
|
|
|
(20
|
)
|
|
48
|
|
||||||||
(Gain) Loss on Divestitures, Net
|
(843
|
)
|
|
36
|
|
|
(376
|
)
|
|
—
|
|
|
—
|
|
|
(503
|
)
|
|
—
|
|
|
—
|
|
||||||||
Asset Impairments
|
206
|
|
|
169
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
37
|
|
|
—
|
|
|
—
|
|
||||||||
Goodwill Impairment
|
1,281
|
|
|
1,281
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Cost of Purchased Oil and Gas
|
296
|
|
|
20
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
136
|
|
|
—
|
|
|
140
|
|
||||||||
Gain on Asset Retirement Obligation Revisions
|
(25
|
)
|
|
—
|
|
|
(8
|
)
|
|
—
|
|
|
(17
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
(Gain) Loss on Commodity Derivative Instruments
|
(63
|
)
|
|
(70
|
)
|
|
—
|
|
|
7
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Income (Loss) Before Income Taxes
|
140
|
|
|
(875
|
)
|
|
742
|
|
|
305
|
|
|
(53
|
)
|
|
726
|
|
|
(60
|
)
|
|
(645
|
)
|
||||||||
Additions to Long Lived Assets
|
3,253
|
|
|
2,115
|
|
|
671
|
|
|
12
|
|
|
—
|
|
|
521
|
|
|
(91
|
)
|
|
25
|
|
||||||||
Property, Plant and Equipment, Net
|
18,419
|
|
|
13,044
|
|
|
2,630
|
|
|
805
|
|
|
37
|
|
|
1,742
|
|
|
(145
|
)
|
|
306
|
|
||||||||
Year Ended December 31, 2017
|
|||||||||||||||||||||||||||||||
Crude Oil Sales
|
$
|
2,346
|
|
|
$
|
1,993
|
|
|
$
|
6
|
|
|
$
|
347
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
NGL Sales
|
493
|
|
|
493
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Natural Gas Sales
|
1,221
|
|
|
670
|
|
|
528
|
|
|
23
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Total Crude Oil, NGL and Natural Gas Sales
|
4,060
|
|
|
3,156
|
|
|
534
|
|
|
370
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Income from Equity Method Investees
|
177
|
|
|
—
|
|
|
—
|
|
|
120
|
|
|
—
|
|
|
57
|
|
|
—
|
|
|
—
|
|
||||||||
Midstream Services Revenues - Third Party
|
19
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
19
|
|
|
—
|
|
|
—
|
|
||||||||
Intersegment Revenues
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
277
|
|
|
(277
|
)
|
|
—
|
|
||||||||
Total Revenues
|
4,256
|
|
|
3,156
|
|
|
534
|
|
|
490
|
|
|
—
|
|
|
353
|
|
|
(277
|
)
|
|
—
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
|
Oil and Gas Exploration and Production
|
|
Midstream
|
|
|
||||||||||||||||||||||||
(millions)
|
Consolidated
|
|
United
States |
|
Eastern
Mediter- ranean |
|
West
Africa |
|
Other Int'l
|
|
United States
|
|
Intersegment Eliminations and Other (1)
|
|
Corporate
|
||||||||||||||||
Lease Operating Expense
|
571
|
|
|
466
|
|
|
29
|
|
|
90
|
|
|
—
|
|
|
—
|
|
|
(14
|
)
|
|
—
|
|
||||||||
Production and Ad Valorem Taxes
|
118
|
|
|
115
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
—
|
|
|
—
|
|
||||||||
Gathering, Transportation and Processing Expense
|
432
|
|
|
550
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
70
|
|
|
(188
|
)
|
|
—
|
|
||||||||
Other Royalty Expense
|
20
|
|
|
20
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Total Production Expense
|
1,141
|
|
|
1,151
|
|
|
29
|
|
|
90
|
|
|
—
|
|
|
73
|
|
|
(202
|
)
|
|
—
|
|
||||||||
Exploration Expense
|
188
|
|
|
102
|
|
|
2
|
|
|
5
|
|
|
79
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
DD&A
|
2,053
|
|
|
1,739
|
|
|
76
|
|
|
146
|
|
|
4
|
|
|
30
|
|
|
(5
|
)
|
|
63
|
|
||||||||
Loss on Marcellus Shale Upstream Divestiture and Other
|
2,379
|
|
|
2,286
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
93
|
|
||||||||
Gain on Divestitures, Net
|
(326
|
)
|
|
(325
|
)
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Asset Impairments
|
70
|
|
|
63
|
|
|
—
|
|
|
—
|
|
|
7
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Clayton Williams Energy Acquisition Expenses
|
100
|
|
|
100
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Gain on Asset Retirement Obligation Revision
|
(42
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(42
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
(Gain) Loss on Commodity Derivative Instruments
|
(63
|
)
|
|
(92
|
)
|
|
—
|
|
|
29
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Loss on Debt Extinguishment
|
98
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
98
|
|
||||||||
(Loss) Income Before Income Taxes
|
(2,191
|
)
|
|
(2,365
|
)
|
|
413
|
|
|
203
|
|
|
(54
|
)
|
|
233
|
|
|
(62
|
)
|
|
(559
|
)
|
||||||||
Additions to Long Lived Assets
|
2,851
|
|
|
1,994
|
|
|
411
|
|
|
34
|
|
|
(34
|
)
|
|
423
|
|
|
(79
|
)
|
|
102
|
|
||||||||
Property, Plant and Equipment, Net
|
17,502
|
|
|
13,348
|
|
|
2,005
|
|
|
863
|
|
|
25
|
|
|
1,027
|
|
|
(74
|
)
|
|
308
|
|
||||||||
Year Ended December 31, 2016
|
|||||||||||||||||||||||||||||||
Crude Oil Sales
|
$
|
1,854
|
|
|
$
|
1,439
|
|
|
$
|
5
|
|
|
$
|
410
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
NGL Sales
|
296
|
|
|
296
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Natural Gas Sales
|
1,239
|
|
|
681
|
|
|
535
|
|
|
23
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Total Crude Oil, NGL and Natural Gas Sales
|
3,389
|
|
|
2,416
|
|
|
540
|
|
|
433
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Income from Equity Method Investees
|
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
|
57
|
|
|
55
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
—
|
|
||||||||
Gathering, Transportation and Processing Expense
|
480
|
|
|
564
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
44
|
|
|
(128
|
)
|
|
—
|
|
||||||||
Other Royalty Expense
|
21
|
|
|
21
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Total Production Expense
|
1,100
|
|
|
1,058
|
|
|
37
|
|
|
105
|
|
|
—
|
|
|
46
|
|
|
(146
|
)
|
|
—
|
|
||||||||
Exploration Expense
|
925
|
|
|
245
|
|
|
34
|
|
|
483
|
|
|
163
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
DD&A
|
2,454
|
|
|
2,103
|
|
|
81
|
|
|
205
|
|
|
6
|
|
|
19
|
|
|
—
|
|
|
40
|
|
||||||||
(Gain) Loss on Divestitures, Net
|
(238
|
)
|
|
23
|
|
|
(261
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Asset Impairments
|
92
|
|
|
—
|
|
|
88
|
|
|
—
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
|
Oil and Gas Exploration and Production
|
|
Midstream
|
|
|
||||||||||||||||||||||||
(millions)
|
Consolidated
|
|
United
States |
|
Eastern
Mediter- ranean |
|
West
Africa |
|
Other Int'l
|
|
United States
|
|
Intersegment Eliminations and Other (1)
|
|
Corporate
|
||||||||||||||||
Loss on Commodity Derivative Instruments
|
139
|
|
|
126
|
|
|
—
|
|
|
13
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
(Loss) Income Before Income Taxes
|
(1,772
|
)
|
|
(1,277
|
)
|
|
543
|
|
|
(338
|
)
|
|
(199
|
)
|
|
176
|
|
|
(51
|
)
|
|
(626
|
)
|
||||||||
Additions to Long Lived Assets
|
1,526
|
|
|
1,353
|
|
|
88
|
|
|
54
|
|
|
(6
|
)
|
|
58
|
|
|
(53
|
)
|
|
32
|
|
||||||||
Property, Plant and Equipment, Net
|
18,548
|
|
|
14,755
|
|
|
1,872
|
|
|
980
|
|
|
15
|
|
|
594
|
|
|
—
|
|
|
332
|
|
(1)
|
Intersegment eliminations related to income (loss) 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.
|
|
|
Percentage of Crude Oil Sales
|
|
Percentage of Total Oil, NGL & Gas Sales
|
||
Year Ended December 31, 2018
|
|
|
|
|
||
BP (1)
|
|
31
|
%
|
|
17
|
%
|
Shell (2)
|
|
22
|
%
|
|
14
|
%
|
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
|
%
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
(millions)
|
2019
|
2020
|
Total
|
||||||
Natural Gas Revenues (1)
|
$
|
137
|
|
$
|
169
|
|
$
|
306
|
|
(1)
|
The remaining performance obligations are estimated utilizing the contractual base or floor price provision in effect. Our future revenues from the sale of natural gas under these associated contracts will vary from the amounts presented above due to components of variable consideration above the contractual base or floor provision, such as index-based escalations and market price changes.
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
(millions, except per share amounts)
|
|
||
Fair Value of Common Stock Issued
|
$
|
1,851
|
|
Plus: Cash Consideration Paid to Clayton Williams Energy Stockholders
|
637
|
|
|
Total Purchase Price
|
$
|
2,488
|
|
Plus Liabilities Assumed by Noble Energy:
|
|
||
Accounts Payable
|
99
|
|
|
Other Current Liabilities
|
38
|
|
|
Long-Term Deferred Tax Liability
|
515
|
|
|
Long-Term Debt
|
595
|
|
|
Asset Retirement Obligations
|
63
|
|
|
Total Purchase Price Plus Liabilities Assumed
|
$
|
3,798
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
Year Ended December 31,
|
||||||||||
(millions, except per share amounts)
|
2018 (1)
|
|
2017
|
|
2016
|
||||||
Revenues
|
$
|
4,986
|
|
|
$
|
4,304
|
|
|
$
|
3,651
|
|
Net Income (Loss) and Comprehensive Income (Loss) Attributable to Noble Energy
|
(66
|
)
|
|
(678
|
)
|
|
(1,082
|
)
|
|||
|
|
|
|
|
|
||||||
Net Income (Loss) Attributable to Noble Energy per Common Share
|
|
|
|
|
|
||||||
Basic
|
$
|
(0.14
|
)
|
|
$
|
(1.39
|
)
|
|
$
|
(2.23
|
)
|
Diluted
|
$
|
(0.14
|
)
|
|
$
|
(1.39
|
)
|
|
$
|
(2.23
|
)
|
•
|
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.
|
•
|
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.
|
•
|
completed the acquisition of Delaware Basin properties, including seven producing wells, 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.
|
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
|
•
|
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.
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
2018
|
|
2017
|
|
2016
|
||||||
Capitalized Exploratory Well Costs, Beginning of Period
|
$
|
520
|
|
|
$
|
768
|
|
|
$
|
1,353
|
|
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves
|
7
|
|
|
20
|
|
|
84
|
|
|||
Divestitures and Other (1)
|
(168
|
)
|
|
—
|
|
|
(143
|
)
|
|||
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves or to Assets Held for Sale (2)
|
(1
|
)
|
|
(203
|
)
|
|
(1
|
)
|
|||
Capitalized Exploratory Well Costs Charged to Expense (3)
|
(4
|
)
|
|
(65
|
)
|
|
(525
|
)
|
|||
Capitalized Exploratory Well Costs, End of Period
|
$
|
354
|
|
|
$
|
520
|
|
|
$
|
768
|
|
|
December 31,
|
||||||||||
(millions)
|
2018
|
|
2017
|
|
2016
|
||||||
Exploratory Well Costs Capitalized for a Period of One Year or Less
|
$
|
6
|
|
|
$
|
10
|
|
|
$
|
69
|
|
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling
|
348
|
|
|
510
|
|
|
699
|
|
|||
Balance at End of Period
|
$
|
354
|
|
|
$
|
520
|
|
|
$
|
768
|
|
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling
|
7
|
|
|
8
|
|
|
10
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
|
Suspended Since
|
|
|
||||||||||||
Country/Project
(millions)
|
Total
|
|
2016 - 2017
|
|
2014 - 2015
|
|
2013 & Prior
|
|
Progress
|
||||||||
Offshore Equatorial Guinea
|
|
|
|
|
|
|
|
|
|
||||||||
Felicita (Block O)
|
$
|
48
|
|
|
$
|
3
|
|
|
$
|
7
|
|
|
$
|
38
|
|
|
We are in process of evaluating regional development scenarios for this 2008 natural gas discovery. In early 2016, we began analyzing, interpreting and evaluating the acquired seismic data. In 2018, we progressed definitive agreements to sell natural gas through the Punta Europa plants, which will expand the options for additional natural gas sales.
|
Yolanda (Block I)
|
24
|
|
|
2
|
|
|
3
|
|
|
19
|
|
|
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 development team is working with both governments to evaluate natural gas monetization options for both Yolanda and YoYo (Cameroon) discoveries. In 2018, we progressed the definitive agreements to sell natural gas through the Punta Europa plants, which will open the options for additional natural gas sales.
|
||||
Offshore Cameroon
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
YoYo (YoYo Block)
|
52
|
|
|
(1
|
)
|
|
6
|
|
|
47
|
|
|
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 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. In 2018, we progressed the definitive agreements to sell natural gas through the Punta Europa plants, which will open the options for additional natural gas sales.
|
||||
Offshore Israel
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Leviathan-1 Deep
|
94
|
|
|
6
|
|
|
8
|
|
|
80
|
|
|
The well did not reach the target interval in 2012. In 2018, we continued to reprocess and review seismic information for this prospect, incorporating information obtained from other recent discoveries in the region and developing future drilling plans to test this deep oil concept, which is held by the Leviathan Development and Production Leases.
|
||||
Dalit
|
24
|
|
|
2
|
|
|
3
|
|
|
19
|
|
|
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. Currently, we are analyzing 3D seismic data to evaluate additional potential of the area.
|
||||
Offshore Cyprus
|
|
|
|
|
|
|
|
|
|
||||||||
Cyprus
|
100
|
|
|
11
|
|
|
12
|
|
|
77
|
|
|
We continue to work with the Government of Cyprus to obtain approval of our development plan and the issuance of an Exploitation License. During 2017, we submitted an updated development plan. During 2018, we continued to progress capital project cost improvement and regional natural gas marketing efforts.
|
||||
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Projects less than $20 million
|
6
|
|
|
(7
|
)
|
|
10
|
|
|
3
|
|
|
Continuing to assess and evaluate wells.
|
||||
Total
|
$
|
348
|
|
|
$
|
16
|
|
|
$
|
49
|
|
|
$
|
283
|
|
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
December 31,
|
||||||
(millions)
|
2018
|
|
2017
|
||||
Undeveloped Leasehold Costs, Beginning of Period
|
$
|
2,922
|
|
|
$
|
2,197
|
|
Additions to Undeveloped Leasehold Costs (1)
|
47
|
|
|
1,859
|
|
||
Transfers to Proved Properties (2)
|
(453
|
)
|
|
(174
|
)
|
||
Assets Sold (3)
|
(142
|
)
|
|
(884
|
)
|
||
Impairment (4)
|
(1
|
)
|
|
(62
|
)
|
||
Other
|
—
|
|
|
(14
|
)
|
||
Undeveloped Leasehold Costs, Net of Impairment, End of Period
|
$
|
2,373
|
|
|
$
|
2,922
|
|
(1)
|
2017 additions relate to the Clayton Williams Energy Acquisition and Delaware Basin asset acquisition.
|
(2)
|
2018 transfers relate primarily to Delaware Basin assets.
|
(3)
|
2017 sales relate primarily to the Marcellus Shale upstream divestiture.
|
(4)
|
2017 impairment expense was primarily attributable to Gulf of Mexico leases.
|
|
Year Ended December 31,
|
||||||
(millions)
|
2018
|
|
2017
|
||||
Asset Retirement Obligations, Beginning Balance
|
$
|
875
|
|
|
$
|
935
|
|
Liabilities Incurred
|
25
|
|
|
94
|
|
||
Liabilities Settled
|
(345
|
)
|
|
(82
|
)
|
||
Revisions of Estimates
|
293
|
|
|
(65
|
)
|
||
Reclassification to Liabilities Associated with Assets Held for Sale
|
(1
|
)
|
|
(54
|
)
|
||
Accretion Expense
|
33
|
|
|
47
|
|
||
Asset Retirement Obligations, Ending Balance
|
$
|
880
|
|
|
$
|
875
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
December 31, 2018
|
|
December 31, 2017
|
||||||||||
(millions, except percentages)
|
Debt
|
|
Interest Rate
|
|
Debt
|
|
Interest Rate
|
||||||
Revolving Credit Facility, due March 9, 2023
|
$
|
—
|
|
|
—
|
%
|
|
$
|
230
|
|
|
2.27
|
%
|
Noble Midstream Services Revolving Credit Facility, due March 9, 2023
|
60
|
|
|
3.67
|
%
|
|
85
|
|
|
2.75
|
%
|
||
Noble Midstream Services Term Loan Credit Facility, due July 31, 2021
|
500
|
|
|
3.42
|
%
|
|
—
|
|
|
—
|
%
|
||
Senior Notes, due May 1, 2021 (1)
|
—
|
|
|
—
|
%
|
|
379
|
|
|
5.63
|
%
|
||
Senior Notes, due December 15, 2021
|
1,000
|
|
|
4.15
|
%
|
|
1,000
|
|
|
4.15
|
%
|
||
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
|
600
|
|
|
3.85
|
%
|
|
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
|
500
|
|
|
4.95
|
%
|
|
500
|
|
|
4.95
|
%
|
||
Other Senior Notes and Debentures (2)
|
92
|
|
|
7.13
|
%
|
|
92
|
|
|
7.13
|
%
|
||
Capital Lease Obligations
|
223
|
|
|
—
|
%
|
|
273
|
|
|
—
|
%
|
||
Total
|
$
|
6,675
|
|
|
|
|
|
$
|
6,859
|
|
|
|
|
Unamortized Discount
|
(22
|
)
|
|
|
|
|
(24
|
)
|
|
|
|
||
Unamortized Premium (1)
|
—
|
|
|
|
|
12
|
|
|
|
||||
Unamortized Debt Issuance Costs
|
(38
|
)
|
|
|
|
(40
|
)
|
|
|
||||
Total Debt, Net of Unamortized Discount, Premium and Debt Issuance Costs
|
$
|
6,615
|
|
|
|
|
|
$
|
6,807
|
|
|
|
|
Less Amounts Due Within One Year:
|
|
|
|
|
|
|
|
|
|
|
|
||
Capital Lease Obligations
|
(41
|
)
|
|
|
|
|
(61
|
)
|
|
|
|
||
Long-Term Debt Due After One Year
|
$
|
6,574
|
|
|
|
|
|
$
|
6,746
|
|
|
|
|
(1)
|
In second quarter 2018, we redeemed all of the Senior Notes due May 1, 2021, and expensed the associated premium. See Redemption of Notes, below.
|
(2)
|
Includes $8 million of 5.875% Senior Notes due June 1, 2024 and $84 million of 7.25% Senior Debentures due August 1, 2097.
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
(millions)
|
Debt Principal Payments
|
||
2019
|
$
|
—
|
|
2020
|
—
|
|
|
2021
|
1,500
|
|
|
2022
|
—
|
|
|
2023
|
160
|
|
|
Thereafter
|
4,792
|
|
|
Total
|
$
|
6,452
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
December 31,
|
||||||
(millions)
|
|
2018
|
|
2017
|
||||
Balance at Beginning of Period
|
|
$
|
90
|
|
|
$
|
—
|
|
Marcellus Exit Cost Accrual
|
|
—
|
|
|
93
|
|
||
Payments, Net of Accretion
|
|
(10
|
)
|
|
(3
|
)
|
||
Balance at End of Period
|
|
$
|
80
|
|
|
$
|
90
|
|
Less Current Portion Included in Other Current Liabilities
|
|
13
|
|
|
14
|
|
||
Long-term Portion Included in Other Noncurrent Liabilities
|
|
$
|
67
|
|
|
$
|
76
|
|
|
|
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
|
Statements of Operations Location
|
|
2018
|
|
2017
|
|
2016
|
||||||
Sales of Purchased Gas
|
|
Sales of Purchased Oil and Gas and Other
|
|
$
|
113
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
||||||
Cost of Purchased of Gas
|
|
Other Operating Expense, Net
|
|
108
|
|
|
—
|
|
|
—
|
|
|||
Utilized Firm Transportation Expense (1)
|
|
Other Operating Expense, Net
|
|
29
|
|
|
—
|
|
|
—
|
|
|||
Unutilized Firm Transportation Expense
|
|
Other Operating Expense, Net
|
|
3
|
|
|
—
|
|
|
—
|
|
|||
Cost of Purchased Gas, Total
|
|
Other Operating Expense, Net
|
|
$
|
140
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(1)
|
Includes the net impact of the difference in the firm transportation contract rates and the rates agreed to in the capacity releases. Additionally, amount includes transportation expense associated with our transport of purchased natural gas on Leach/Rayne Xpress.
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
(millions)
|
|
Purchase and Service Obligations
|
|
Marcellus Shale Firm Transportation and Other Obligations (1)
|
|
Gathering, Transportation & Processing Obligations
|
|
Operating
Lease
Obligations (2)
|
|
Capital
Lease Obligations (2)
|
|
Total
|
||||||||||||
2019
|
|
$
|
197
|
|
|
$
|
123
|
|
|
$
|
151
|
|
|
$
|
91
|
|
|
$
|
52
|
|
|
$
|
614
|
|
2020
|
|
29
|
|
|
122
|
|
|
129
|
|
|
74
|
|
|
46
|
|
|
400
|
|
||||||
2021
|
|
13
|
|
|
121
|
|
|
103
|
|
|
59
|
|
|
31
|
|
|
327
|
|
||||||
2022
|
|
6
|
|
|
118
|
|
|
67
|
|
|
62
|
|
|
22
|
|
|
275
|
|
||||||
2023
|
|
21
|
|
|
113
|
|
|
66
|
|
|
50
|
|
|
20
|
|
|
270
|
|
||||||
2024 and Thereafter
|
|
5
|
|
|
934
|
|
|
285
|
|
|
176
|
|
|
104
|
|
|
1,504
|
|
||||||
Total
|
|
$
|
271
|
|
|
$
|
1,531
|
|
|
$
|
801
|
|
|
$
|
512
|
|
|
$
|
275
|
|
|
$
|
3,390
|
|
(1)
|
Amount includes exit cost obligations resulting from a permanent capacity assignment. See Note 10. Marcellus Shale Firm Transportation Commitments.
|
(2)
|
Annual lease payments, net to our interest, exclude regular maintenance and operational costs. See Note 9. Long-Term Debt.
|
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
|
2018
|
|
2017
|
|
2016
|
||||||
Domestic
|
|
$
|
(953
|
)
|
|
$
|
(2,831
|
)
|
|
$
|
(1,859
|
)
|
Foreign
|
|
1,093
|
|
|
640
|
|
|
87
|
|
|||
Total
|
|
$
|
140
|
|
|
$
|
(2,191
|
)
|
|
$
|
(1,772
|
)
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
Year Ended December 31,
|
||||||||||
(millions, except percentages)
|
|
2018
|
|
2017
|
|
2016
|
||||||
Current Taxes
|
|
|
|
|
|
|
||||||
Federal
|
|
$
|
22
|
|
|
$
|
(11
|
)
|
|
$
|
(4
|
)
|
State
|
|
2
|
|
|
1
|
|
|
5
|
|
|||
Foreign
|
|
172
|
|
|
96
|
|
|
196
|
|
|||
Total Current
|
|
$
|
196
|
|
|
$
|
86
|
|
|
$
|
197
|
|
Deferred Taxes
|
|
|
|
|
|
|
||||||
Federal
|
|
$
|
(123
|
)
|
|
$
|
(1,258
|
)
|
|
$
|
(784
|
)
|
State
|
|
(7
|
)
|
|
(8
|
)
|
|
(24
|
)
|
|||
Foreign
|
|
60
|
|
|
39
|
|
|
(176
|
)
|
|||
Total Deferred
|
|
$
|
(70
|
)
|
|
$
|
(1,227
|
)
|
|
$
|
(984
|
)
|
Total Income Tax Provision (Benefit) Attributable to Noble Energy
|
|
$
|
126
|
|
|
$
|
(1,141
|
)
|
|
$
|
(787
|
)
|
Effective Tax Rate
|
|
90.0
|
%
|
|
52.1
|
%
|
|
44.4
|
%
|
|
|
Year Ended December 31,
|
|||||||
(percentages)
|
|
2018
|
|
2017
|
|
2016
|
|||
Federal Statutory Rate (1)
|
|
21.0
|
%
|
|
35.0
|
%
|
|
35.0
|
%
|
Effect of
|
|
|
|
|
|
|
|||
Goodwill Impairment
|
|
192.5
|
|
|
—
|
|
|
—
|
|
Change in Valuation Allowance (1)
|
|
(170.2
|
)
|
|
(17.4
|
)
|
|
(2.0
|
)
|
US and Foreign Statutory Rate Change (1)
|
|
80.7
|
|
|
23.5
|
|
|
1.6
|
|
Accumulated Undistributed Foreign Earnings (1)
|
|
—
|
|
|
11.0
|
|
|
7.2
|
|
Transition Tax (1)
|
|
—
|
|
|
(4.8
|
)
|
|
—
|
|
Difference Between US and Foreign Rates
|
|
17.9
|
|
|
1.8
|
|
|
(0.1
|
)
|
Earnings of Equity Method Investees
|
|
(20.1
|
)
|
|
1.9
|
|
|
1.0
|
|
Noncontrolling Interests
|
|
(12.1
|
)
|
|
1.1
|
|
|
0.4
|
|
State Taxes, Net of Federal Benefit
|
|
0.9
|
|
|
0.3
|
|
|
1.3
|
|
Foreign Exploration Loss
|
|
(35.6
|
)
|
|
—
|
|
|
—
|
|
Global Intangible Low-Taxed Income (GILTI) (1)
|
|
24.2
|
|
|
—
|
|
|
—
|
|
Return to Provision
|
|
(17.1
|
)
|
|
(0.1
|
)
|
|
(0.2
|
)
|
Audit Settlement
|
|
5.1
|
|
|
0.1
|
|
|
(0.2
|
)
|
Oil Profits Tax - Israel
|
|
3.3
|
|
|
(0.1
|
)
|
|
—
|
|
Other, Net
|
|
(0.5
|
)
|
|
(0.2
|
)
|
|
0.4
|
|
Effective Rate
|
|
90.0
|
%
|
|
52.1
|
%
|
|
44.4
|
%
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
December 31,
|
||||||
(millions)
|
|
2018
|
|
2017
|
||||
Deferred Tax Assets
|
|
|
|
|
||||
Loss Carryforwards
|
|
$
|
589
|
|
|
$
|
902
|
|
Employee Compensation and Benefits
|
|
92
|
|
|
97
|
|
||
Mark to Market of Commodity Derivative Instruments
|
|
(27
|
)
|
|
7
|
|
||
Foreign Tax Credits
|
|
138
|
|
|
366
|
|
||
Other
|
|
157
|
|
|
104
|
|
||
Total Deferred Tax Assets
|
|
$
|
949
|
|
|
$
|
1,476
|
|
Valuation Allowance - Foreign Loss Carryforwards and Foreign Tax Credits
|
|
(320
|
)
|
|
(549
|
)
|
||
Net Deferred Tax Assets
|
|
$
|
629
|
|
|
$
|
927
|
|
Deferred Tax Liabilities
|
|
|
|
|
||||
Property, Plant and Equipment, Principally Due to Differences in Depreciation, Amortization, Lease Impairment and Abandonments
|
|
(1,669
|
)
|
|
(2,029
|
)
|
||
Total Deferred Tax Liability
|
|
$
|
(1,669
|
)
|
|
$
|
(2,029
|
)
|
Net Deferred Tax Liability
|
|
$
|
(1,040
|
)
|
|
$
|
(1,102
|
)
|
|
|
December 31,
|
||||||
(millions)
|
|
2018
|
|
2017
|
||||
Deferred Income Tax Asset - Noncurrent
|
|
$
|
21
|
|
|
$
|
25
|
|
Deferred Income Tax Liability - Noncurrent
|
|
(1,061
|
)
|
|
(1,127
|
)
|
||
Net Deferred Tax Liability
|
|
$
|
(1,040
|
)
|
|
$
|
(1,102
|
)
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
|
|
|
Swaps
|
|
Collars
|
|||||||||||||
Settlement
Period
|
Type of Contract
|
Index
|
Bbls per
Day
|
|
Weighted Average Differential
|
Weighted
Average
Fixed
Price
|
|
Weighted
Average
Short Put
Price
|
Weighted
Average
Floor
Price
|
Weighted
Average
Ceiling
Price
|
||||||||||
2019
|
Swaps
|
NYMEX WTI
|
22,000
|
|
$
|
—
|
|
$
|
56.96
|
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
2019
|
Three-Way Collars
|
NYMEX WTI
|
33,000
|
|
—
|
|
—
|
|
|
49.35
|
|
59.35
|
|
72.25
|
|
|||||
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)
|
27,000
|
|
(3.23
|
)
|
—
|
|
|
—
|
|
—
|
|
—
|
|
|||||
2020
|
Swaption
|
NYMEX WTI
|
5,000
|
|
—
|
|
61.79
|
|
|
—
|
|
—
|
|
—
|
|
|||||
2020
|
Basis Swap
|
(1)
|
15,000
|
|
(5.01
|
)
|
—
|
|
|
—
|
|
—
|
|
—
|
|
(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.
|
|
|
|
|
|
Swaps
|
|
Collars
|
||||||||||||||
Settlement
Period
|
Type of Contract
|
Index
|
MMBtu per Day
|
|
Weighted Average Differential
|
Weighted Average Fixed Price
|
|
Weighted
Average
Short Put
Price
|
Weighted
Average
Floor
Price
|
Weighted
Average
Ceiling
Price
|
|||||||||||
1Q19(1)
|
Swaps
|
NYMEX HH
|
86,500
|
|
|
$
|
—
|
|
$
|
4.36
|
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
1Q19(1)
|
Three-Way Collars
|
NYMEX HH
|
21,500
|
|
|
—
|
|
—
|
|
|
3.00
|
|
3.25
|
|
4.08
|
|
|||||
2019
|
Three-Way Collars
|
NYMEX HH
|
104,000
|
|
|
—
|
|
—
|
|
|
2.25
|
|
2.65
|
|
2.95
|
|
|||||
2019
|
Basis Swaps
|
(2)
|
52,000
|
|
|
(0.74
|
)
|
—
|
|
|
—
|
|
—
|
|
—
|
|
|
Asset Derivative Instruments
|
|
Liability Derivative Instruments
|
||||||||||||||||||||
|
December 31, 2018
|
|
December 31, 2017
|
|
December 31, 2018
|
|
December 31, 2017
|
||||||||||||||||
(millions)
|
Balance
Sheet
Location
|
|
Fair
Value
|
|
Balance Sheet Location
|
|
Fair
Value
|
|
Balance Sheet Location
|
|
Fair
Value
|
|
Balance Sheet Location
|
|
Fair
Value
|
||||||||
Commodity Derivative Instruments
|
Current Assets
|
|
$
|
180
|
|
|
Current Assets
|
|
$
|
2
|
|
|
Current Liabilities
|
|
$
|
1
|
|
|
Current Liabilities
|
|
$
|
58
|
|
|
Noncurrent Assets
|
|
—
|
|
|
Noncurrent Assets
|
|
—
|
|
|
Noncurrent Liabilities
|
|
26
|
|
|
Noncurrent Liabilities
|
|
15
|
|
||||
Total
|
|
|
$
|
180
|
|
|
|
|
$
|
2
|
|
|
|
|
$
|
27
|
|
|
|
|
$
|
73
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
2018
|
|
2017
|
|
2016
|
||||||
Cash Paid (Received) in Settlement of Commodity Derivative Instruments
|
|
|
|
|
|
||||||
Crude Oil
|
$
|
162
|
|
|
$
|
(14
|
)
|
|
$
|
(499
|
)
|
Natural Gas
|
(1
|
)
|
|
1
|
|
|
(70
|
)
|
|||
Total Cash Paid (Received) in Settlement of Commodity Derivative Instruments
|
161
|
|
|
(13
|
)
|
|
(569
|
)
|
|||
Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments
|
|
|
|
|
|
||||||
Crude Oil
|
(225
|
)
|
|
18
|
|
|
582
|
|
|||
Natural Gas
|
1
|
|
|
(68
|
)
|
|
126
|
|
|||
Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments
|
(224
|
)
|
|
(50
|
)
|
|
708
|
|
|||
(Gain) Loss on Commodity Derivative Instruments
|
|
|
|
|
|
||||||
Crude Oil
|
(63
|
)
|
|
4
|
|
|
83
|
|
|||
Natural Gas
|
—
|
|
|
(67
|
)
|
|
56
|
|
|||
Total (Gain) Loss on Commodity Derivative Instruments
|
$
|
(63
|
)
|
|
$
|
(63
|
)
|
|
$
|
139
|
|
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, 2018
|
|
|
|
|
|
|
|
|
|
||||||||||
Financial Assets
|
|
|
|
|
|
|
|
|
|
||||||||||
Mutual Fund Investments
|
$
|
38
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
38
|
|
Commodity Derivative Instruments
|
—
|
|
|
187
|
|
|
—
|
|
|
(7
|
)
|
|
180
|
|
|||||
Financial Liabilities
|
|
|
|
|
|
|
|
|
|
||||||||||
Commodity Derivative Instruments
|
—
|
|
|
(34
|
)
|
|
—
|
|
|
7
|
|
|
(27
|
)
|
|||||
Portion of Deferred Compensation Liability Measured at Fair Value
|
(43
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(43
|
)
|
|||||
Stock Based Compensation Liability Measured at Fair Value
|
(8
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(8
|
)
|
|||||
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
|
)
|
(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
|
|
|
December 31, 2018
|
|
December 31, 2017
|
||||||||||||
(millions)
|
Carrying Amount
|
|
Fair Value
|
|
Carrying Amount
|
|
Fair Value
|
||||||||
Long-Term Debt, Net (1)
|
$
|
6,452
|
|
|
$
|
6,121
|
|
|
$
|
6,586
|
|
|
$
|
7,142
|
|
•
|
50% interest in Advantage Pipeline, which owns and operates a 70-mile crude oil pipeline in Texas (See Note 5. Acquisitions and Divestitures);
|
•
|
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 , which owns and operates a LPG processing plant in Equatorial Guinea.
|
|
|
December 31,
|
||||||
(millions)
|
|
2018
|
|
2017
|
||||
Advantage Pipeline
|
|
$
|
73
|
|
|
$
|
70
|
|
AMPCO
|
|
131
|
|
|
129
|
|
||
Alba Plant
|
|
58
|
|
|
80
|
|
||
Other
|
|
24
|
|
|
26
|
|
||
Total Equity Method Investments
|
|
$
|
286
|
|
|
$
|
305
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
|
December 31,
|
||||||
(millions)
|
|
2018
|
|
2017
|
||||
Balance Sheet Information
|
|
|
|
|
||||
Current Assets
|
|
$
|
387
|
|
|
$
|
390
|
|
Noncurrent Assets
|
|
575
|
|
|
588
|
|
||
Current Liabilities
|
|
198
|
|
|
171
|
|
||
Noncurrent Liabilities
|
|
81
|
|
|
90
|
|
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
|
2018
|
|
2017
|
|
2016
|
||||||
Statements of Operations Information
|
|
|
|
|
|
|
||||||
Operating Revenues
|
|
$
|
855
|
|
|
$
|
790
|
|
|
$
|
667
|
|
Operating Expenses
|
|
284
|
|
|
303
|
|
|
355
|
|
|||
Operating Income
|
|
571
|
|
|
487
|
|
|
312
|
|
|||
Other Income, net
|
|
3
|
|
|
15
|
|
|
7
|
|
|||
Income Before Income Taxes
|
|
574
|
|
|
502
|
|
|
319
|
|
|||
Income Tax Provision
|
|
152
|
|
|
136
|
|
|
60
|
|
|||
Net Income
|
|
$
|
422
|
|
|
$
|
366
|
|
|
$
|
259
|
|
|
|
Year Ended December 31,
|
||||
|
|
2018
|
|
2017
|
||
Shares of Common Stock Issued
|
|
|
|
|
|
|
Shares, Beginning of Period
|
|
528,743,381
|
|
|
471,360,427
|
|
Exercise of Common Stock Options
|
|
576,617
|
|
|
382,882
|
|
Restricted Stock Awarded, Net of Forfeitures (1)
|
|
2,488,363
|
|
|
2,912,936
|
|
Purchase and Retirement of Common Stock (2)
|
|
(10,008,128
|
)
|
|
—
|
|
Shares Exchanged in Clayton Williams Energy Acquisition
|
|
(745,232
|
)
|
|
54,087,136
|
|
Shares, End of Period
|
|
521,055,001
|
|
|
528,743,381
|
|
Treasury Stock
|
|
|
|
|
||
Shares, Beginning of Period
|
|
38,786,969
|
|
|
37,961,316
|
|
Shares Received in Payment of Withholding Taxes Due on Vesting of Shares of Restricted Stock (3)
|
|
267,258
|
|
|
1,026,891
|
|
Rabbi Trust Shares Distributed and/or Sold
|
|
(202,239
|
)
|
|
(201,238
|
)
|
Shares, End of Period
|
|
38,851,988
|
|
|
38,786,969
|
|
Additional Information
|
|
|
|
|
||
Incremental Shares From Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust
|
|
—
|
|
|
—
|
|
Number of Antidilutive Stock Options, Shares of Restricted Stock and Shares of Common Stock in Rabbi Trust excluded from Dilutive Earnings (Loss) per Share (4)
|
|
15,004,591
|
|
|
15,619,276
|
|
(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.
|
(2)
|
On February 15, 2018, we announced that the Company's Board of Directors had authorized a share repurchase program of $750 million which expires December 31, 2020. These shares were repurchased and retired at an average price of $29.49 per share.
|
(3)
|
The 2017 amount includes approximately 720,000 shares of common stock received 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.
|
(4)
|
For the years ended December 31, 2018 and 2017, 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
|
|
(millions)
|
|
Interest Rate
Cash Flow
Hedge
|
|
Other Postretirement Benefit Plans
|
|
Total
|
||||||
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
|
)
|
|||
Realized Amounts Reclassified Into Earnings
|
|
(3
|
)
|
|
1
|
|
|
(2
|
)
|
|||
Unrealized Change in Fair Value
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
December 31, 2018
|
|
$
|
(23
|
)
|
|
$
|
(9
|
)
|
|
$
|
(32
|
)
|
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
|
2018
|
|
2017
|
|
2016
|
||||||
Stock-Based Compensation Expense Included in:
|
|
|
|
|
|
|
||||||
General and Administrative Expense
|
|
$
|
54
|
|
|
$
|
56
|
|
|
$
|
62
|
|
Exploration Expense and Other
|
|
8
|
|
|
48
|
|
|
15
|
|
|||
Total Stock-Based Compensation Expense
|
|
$
|
62
|
|
|
$
|
104
|
|
|
$
|
77
|
|
Tax Benefit Recognized
|
|
$
|
(13
|
)
|
|
$
|
(36
|
)
|
|
$
|
(27
|
)
|
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)
|
|
2018
|
|
2017
|
|
2016
|
||||||
Expected Term (in Years)
|
|
6.7
|
|
|
6.4
|
|
|
6.3
|
|
|||
Expected Volatility
|
|
33.4
|
%
|
|
33.2
|
%
|
|
32.4
|
%
|
|||
Risk-Free Rate
|
|
2.6
|
%
|
|
2.2
|
%
|
|
1.6
|
%
|
|||
Expected Dividend Yield
|
|
1.2
|
%
|
|
0.9
|
%
|
|
0.7
|
%
|
|||
Weighted Average Grant-Date Fair Value
|
|
$
|
10.47
|
|
|
$
|
13.26
|
|
|
$
|
10.10
|
|
|
|
Options
|
|
Weighted
Average
Exercise
Price
|
|
Weighted
Average
Remaining
Contractual Term
|
|
Aggregate
Intrinsic Value
|
|||||
|
|
|
|
(per share)
|
|
(in years)
|
|
(in millions)
|
|||||
Outstanding at December 31, 2017
|
|
15,549,222
|
|
|
$
|
43.42
|
|
|
|
|
|
||
Granted
|
|
551,888
|
|
|
30.20
|
|
|
|
|
|
|||
Exercised
|
|
(576,617
|
)
|
|
34.55
|
|
|
|
|
|
|||
Forfeited
|
|
(1,672,473
|
)
|
|
40.04
|
|
|
|
|
|
|||
Outstanding at December 31, 2018
|
|
13,852,020
|
|
|
$
|
44.04
|
|
|
5.0
|
|
$
|
—
|
|
Exercisable at December 31, 2018
|
|
11,866,188
|
|
|
$
|
45.58
|
|
|
4.0
|
|
$
|
—
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
|
Year Ended December 31,
|
|||||||
|
2018
|
|
2017
|
|
2016
|
|||
Number of Simulations
|
10,000,000
|
|
|
500,000
|
|
|
500,000
|
|
Expected Volatility
|
35
|
%
|
|
35
|
%
|
|
38
|
%
|
Risk-Free Rate
|
2.3
|
%
|
|
1.5
|
%
|
|
1.0
|
%
|
|
|
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, 2017
|
|
1,839,737
|
|
|
$
|
37.21
|
|
|
1,212,705
|
|
|
$
|
25.55
|
|
Awarded
|
|
2,702,426
|
|
|
30.68
|
|
|
874,960
|
|
|
19.56
|
|
||
Vested
|
|
(982,280
|
)
|
|
35.28
|
|
|
—
|
|
|
—
|
|
||
Forfeited
|
|
(386,992
|
)
|
|
32.65
|
|
|
(702,031
|
)
|
|
25.52
|
|
||
Outstanding at December 31, 2018
|
|
3,172,891
|
|
|
$
|
32.72
|
|
|
1,385,634
|
|
|
$
|
21.74
|
|
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, 2017
|
|
610,159
|
|
|
$
|
31.65
|
|
|
167,483
|
|
|
$
|
6.82
|
|
Vested
|
|
(83,276
|
)
|
|
31.65
|
|
|
—
|
|
|
—
|
|
||
Forfeited
|
|
(59,518
|
)
|
|
31.65
|
|
|
(17,187
|
)
|
|
6.82
|
|
||
Outstanding at December 31, 2018
|
|
467,365
|
|
|
$
|
31.65
|
|
|
150,296
|
|
|
$
|
6.82
|
|
|
|
December 31,
|
||||||
(millions, except share amounts)
|
|
2018
|
|
2017
|
||||
Mutual Fund Investments
|
|
$
|
38
|
|
|
$
|
57
|
|
Noble Energy Common Stock (at Fair Value)
|
|
5
|
|
|
14
|
|
||
Total Rabbi Trust Assets
|
|
$
|
43
|
|
|
$
|
71
|
|
Liability Under Related Deferred Compensation Plan
|
|
$
|
43
|
|
|
$
|
71
|
|
Number of Shares of Noble Energy Common Stock Held by Rabbi Trust
|
|
267,792
|
|
|
470,030
|
|
Noble Energy, Inc.
|
|
|
Notes to Consolidated Financial Statements
|
|
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, 2015
|
|
256
|
|
|
48
|
|
|
3
|
|
|
307
|
|
Revisions of Previous Estimates
|
|
14
|
|
|
(4
|
)
|
|
—
|
|
|
10
|
|
Extensions, Discoveries and Other Additions
|
|
66
|
|
|
—
|
|
|
—
|
|
|
66
|
|
Sale of Minerals in Place
|
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
Production
|
|
(36
|
)
|
|
(10
|
)
|
|
—
|
|
|
(46
|
)
|
December 31, 2016
|
|
296
|
|
|
34
|
|
|
3
|
|
|
333
|
|
Revisions of Previous Estimates
|
|
29
|
|
|
2
|
|
|
—
|
|
|
31
|
|
Extensions, Discoveries and Other Additions
|
|
104
|
|
|
—
|
|
|
6
|
|
|
110
|
|
Purchase of Minerals in Place
|
|
43
|
|
|
—
|
|
|
—
|
|
|
43
|
|
Sale of Minerals in Place
|
|
(12
|
)
|
|
—
|
|
|
—
|
|
|
(12
|
)
|
Production
|
|
(41
|
)
|
|
(7
|
)
|
|
—
|
|
|
(48
|
)
|
December 31, 2017
|
|
419
|
|
|
29
|
|
|
9
|
|
|
457
|
|
Revisions of Previous Estimates
|
|
(31
|
)
|
|
3
|
|
|
—
|
|
|
(28
|
)
|
Extensions, Discoveries and Other Additions
|
|
98
|
|
|
3
|
|
|
—
|
|
|
101
|
|
Sale of Minerals in Place
|
|
(24
|
)
|
|
—
|
|
|
(1
|
)
|
|
(25
|
)
|
Production
|
|
(42
|
)
|
|
(6
|
)
|
|
—
|
|
|
(48
|
)
|
December 31, 2018
|
|
420
|
|
|
29
|
|
|
8
|
|
|
457
|
|
Proved Developed Reserves as of:
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2015
|
|
137
|
|
|
34
|
|
|
3
|
|
|
174
|
|
December 31, 2016
|
|
138
|
|
|
34
|
|
|
3
|
|
|
175
|
|
December 31, 2017
|
|
176
|
|
|
29
|
|
|
3
|
|
|
208
|
|
December 31, 2018
|
|
165
|
|
|
26
|
|
|
2
|
|
|
193
|
|
Proved Undeveloped Reserves as of:
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2015
|
|
119
|
|
|
14
|
|
|
—
|
|
|
133
|
|
December 31, 2016
|
|
158
|
|
|
—
|
|
|
—
|
|
|
158
|
|
December 31, 2017
|
|
243
|
|
|
—
|
|
|
6
|
|
|
249
|
|
December 31, 2018
|
|
255
|
|
|
3
|
|
|
6
|
|
|
264
|
|
•
|
Price Revisions
|
◦
|
2016 positive price revisions included 19 MMBbls in the US and 4 MMBbls in Equatorial Guinea.
|
◦
|
2017 positive price revisions included 12 MMBbls in the US.
|
◦
|
2018 positive price revisions of 14 MMBbls included 10 MMBbls in the US and 4 MMBbls in Equatorial Guinea.
|
•
|
Non-Price Revisions
|
◦
|
2016 US revisions associated with positive performance and/or decreases in development or operating costs included revisions of 33 MMBbls in the DJ Basin, Marcellus Shale, Delaware Basin and Gulf of Mexico.
|
◦
|
2017 US revisions associated with positive performance totaled 17 MMBbls, of which 14 were primarily attributable to the Delaware Basin due to continued optimization of well development and improved producing well performance.
|
◦
|
2018 includes negative non-price revisions of 42 MMBbls, which primarily includes 30 MMBbls for changes in expected recoveries and increased operating and capital costs in the Delaware Basin, and 11 MMBbls for changes in the previously adopted development plan in the Eagle Ford Shale and DJ Basin.
|
Noble Energy, Inc.
|
|
|
Supplemental Oil and Gas Information
|
|
|
|
(Unaudited)
|
|
•
|
2016 extensions in US reserves included 38 MMBbls in the DJ Basin and 28 MMBbls in the Delaware Basin and Eagle Ford Shale, and was associated with increased performance from our horizontal drilling programs.
|
•
|
2017 extensions in US reserves included additions of 59 MMBbls in the Delaware Basin, 42 MMBbls in the DJ Basin and 3 MMBbls in the Eagle Ford Shale primarily due to the addition of planned new locations and activity.
|
•
|
2018 extensions relate to drilling plans for new wells and include 55 MMBbls, 38 MMBbls, 5 MMBbls and 3 MMBbls in the Delaware Basin, DJ Basin, Eagle Ford Shale and Equatorial Guinea, respectively.
|
•
|
2017 includes the sale of Marcellus Shale upstream assets and other non-strategic US onshore assets.
|
•
|
2018 sales included 16 MMBbls related to our Gulf of Mexico assets and 8 MMBbls related to other non-strategic US onshore assets.
|
Noble Energy, Inc.
|
|
|
Supplemental Oil and Gas Information
|
|
|
|
(Unaudited)
|
|
|
|
NGLs (MMBbls)
|
|||||||
|
|
United
States
|
|
Equatorial
Guinea
|
|
Total
|
|||
Proved Reserves as of:
|
|
|
|
|
|
|
|||
December 31, 2015
|
|
176
|
|
|
13
|
|
|
189
|
|
Revisions of Previous Estimates
|
|
16
|
|
|
1
|
|
|
17
|
|
Extensions, Discoveries and Other Additions
|
|
31
|
|
|
—
|
|
|
31
|
|
Purchase of Minerals in Place
|
|
4
|
|
|
—
|
|
|
4
|
|
Production
|
|
(20
|
)
|
|
(2
|
)
|
|
(22
|
)
|
December 31, 2016
|
|
207
|
|
|
12
|
|
|
219
|
|
Revisions of Previous Estimates
|
|
31
|
|
|
1
|
|
|
32
|
|
Extensions, Discoveries and Other Additions
|
|
32
|
|
|
—
|
|
|
32
|
|
Purchase of Minerals in Place
|
|
7
|
|
|
—
|
|
|
7
|
|
Sale of Minerals in Place
|
|
(38
|
)
|
|
—
|
|
|
(38
|
)
|
Production
|
|
(21
|
)
|
|
(2
|
)
|
|
(23
|
)
|
December 31, 2017
|
|
218
|
|
|
11
|
|
|
229
|
|
Revisions of Previous Estimates
|
|
21
|
|
|
—
|
|
|
21
|
|
Extensions, Discoveries and Other Additions
|
|
48
|
|
|
—
|
|
|
48
|
|
Sale of Minerals in Place
|
|
(7
|
)
|
|
—
|
|
|
(7
|
)
|
Production
|
|
(23
|
)
|
|
(2
|
)
|
|
(25
|
)
|
December 31, 2018
|
|
257
|
|
|
9
|
|
|
266
|
|
Proved Developed Reserves as of:
|
|
|
|
|
|
|
|
|
|
December 31, 2015
|
|
101
|
|
|
5
|
|
|
106
|
|
December 31, 2016
|
|
113
|
|
|
12
|
|
|
125
|
|
December 31, 2017
|
|
119
|
|
|
11
|
|
|
130
|
|
December 31, 2018
|
|
121
|
|
|
9
|
|
|
130
|
|
Proved Undeveloped Reserves as of:
|
|
|
|
|
|
|
|||
December 31, 2015
|
|
75
|
|
|
8
|
|
|
83
|
|
December 31, 2016
|
|
94
|
|
|
—
|
|
|
94
|
|
December 31, 2017
|
|
99
|
|
|
—
|
|
|
99
|
|
December 31, 2018
|
|
136
|
|
|
—
|
|
|
136
|
|
•
|
Price Revisions
|
◦
|
2016 included negative price revisions of 4 MMBbls.
|
◦
|
2017 included positive price revisions of 6 MMBbls.
|
◦
|
2018 included include positive price revisions of 5 MMBbls in the US.
|
•
|
Non-Price Revisions
|
◦
|
2016 US revisions were primarily associated with positive performance revisions of 11 MMBbls in the Marcellus Shale and 9 MMBbls in the DJ Basin.
|
◦
|
2017 US revisions associated with positive performance revisions totaled 25 MMBbls, including 11 MMBbls in the Delaware Basin, 8 MMBbls in the Eagle Ford Shale and 6 MMBbls in the DJ Basin, due to continued optimization of well development and improved producing well performance.
|
◦
|
2018 net positive non-price revisions of 16 MMBbls include positive revisions of 35 MMBbls in the DJ Basin primarily due to ASC 606 adoption, offset by negative revisions of 15 MMBbls in the Eagle Ford Shale due to changes in the previously adopted development plan and 4 MMBbls in the Delaware Basin for changes in expected recoveries and increased operating and capital costs.
|
Noble Energy, Inc.
|
|
|
Supplemental Oil and Gas Information
|
|
|
|
(Unaudited)
|
|
•
|
2016 extensions in US reserves primarily included an increase of 15 MMBbls in the DJ Basin and 14 MMBbls in the Delaware Basin and Eagle Ford shale due to improved well performance and/or decreases in development or operating costs.
|
•
|
2017 extensions in US reserves included 19 MMBbls in the DJ Basin, 9 MMBbls in the Delaware Basin and 4 MMBbls in the Eagle Ford Shale primarily due to the addition of planned new locations and activity.
|
•
|
2018 extensions relate to the addition of planned new locations and activity, of which 25 MMBbls, 15 MMBbls and 8 MMBbls relate to the DJ Basin, Delaware Basin and Eagle Ford Shale, respectively.
|
•
|
2017 sales included the Marcellus Shale upstream assets and other non-strategic US onshore assets.
|
•
|
2018 sales included 1 MMBbl from Gulf of Mexico assets and 6 MMBbls for certain non-core US onshore assets.
|
Noble Energy, Inc.
|
|
|
Supplemental Oil and Gas Information
|
|
|
|
(Unaudited)
|
|
|
|
Natural Gas and Casinghead Gas (Bcf)
|
||||||||||
|
|
United States
|
|
Israel
|
|
Equatorial Guinea
|
|
Total
|
||||
Proved Reserves as of:
|
|
|
|
|
|
|
|
|
||||
December 31, 2015
|
|
2,711
|
|
|
2,304
|
|
|
534
|
|
|
5,549
|
|
Revisions of Previous Estimates
|
|
181
|
|
|
(3
|
)
|
|
38
|
|
|
216
|
|
Extensions, Discoveries and Other Additions
|
|
492
|
|
|
—
|
|
|
—
|
|
|
492
|
|
Sale of Minerals in Place
|
|
(224
|
)
|
|
(214
|
)
|
|
—
|
|
|
(438
|
)
|
Production
|
|
(322
|
)
|
|
(103
|
)
|
|
(86
|
)
|
|
(511
|
)
|
December 31, 2016
|
|
2,838
|
|
|
1,984
|
|
|
486
|
|
|
5,308
|
|
Revisions of Previous Estimates
|
|
124
|
|
|
292
|
|
|
13
|
|
|
429
|
|
Extensions, Discoveries and Other Additions
|
|
299
|
|
|
3,271
|
|
|
—
|
|
|
3,570
|
|
Purchase of Minerals in Place
|
|
46
|
|
|
—
|
|
|
—
|
|
|
46
|
|
Sale of Minerals in Place
|
|
(1,264
|
)
|
|
—
|
|
|
(1
|
)
|
|
(1,265
|
)
|
Production
|
|
(222
|
)
|
|
(99
|
)
|
|
(87
|
)
|
|
(408
|
)
|
December 31, 2017
|
|
1,821
|
|
|
5,448
|
|
|
411
|
|
|
7,680
|
|
Revisions of Previous Estimates
|
|
1
|
|
|
2
|
|
|
22
|
|
|
25
|
|
Extensions, Discoveries and Other Additions
|
|
373
|
|
|
68
|
|
|
2
|
|
|
443
|
|
Sale of Minerals in Place
|
|
(79
|
)
|
|
(502
|
)
|
|
—
|
|
|
(581
|
)
|
Production
|
|
(172
|
)
|
|
(86
|
)
|
|
(78
|
)
|
|
(336
|
)
|
December 31, 2018
|
|
1,944
|
|
|
4,930
|
|
|
357
|
|
|
7,231
|
|
Proved Developed Reserves as of:
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
December 31, 2018
|
|
929
|
|
|
1,295
|
|
|
355
|
|
|
2,579
|
|
Proved Undeveloped Reserves as of:
|
|
|
|
|
|
|
|
|
||||
December 31, 2015
|
|
898
|
|
|
425
|
|
|
287
|
|
|
1,610
|
|
December 31, 2016
|
|
1,021
|
|
|
384
|
|
|
—
|
|
|
1,405
|
|
December 31, 2017
|
|
838
|
|
|
3,655
|
|
|
—
|
|
|
4,493
|
|
December 31, 2018
|
|
1,015
|
|
|
3,635
|
|
|
2
|
|
|
4,652
|
|
•
|
Price Revisions
|
◦
|
2016 included negative commodity price revisions of 81 Bcf in the US and 20 Bcf in Equatorial Guinea.
|
◦
|
2017 included positive commodity price revisions of 53 Bcf in the US and 13 Bcf in Equatorial Guinea.
|
◦
|
2018 included positive price revisions of 44 Bcf in the US and 5 Bcf in Equatorial Guinea.
|
•
|
Non-Price Revisions
|
◦
|
2016 US revisions were primarily associated with positive performance and/or decreases in development or operating costs and included 167 Bcf in the Marcellus Shale and 95 Bcf in the DJ Basin. Equatorial Guinea revisions were associated with positive performance revisions of 58 Bcf at the Alba field.
|
◦
|
2017 performance revisions of 66 Bcf primarily included 81 Bcf in the Eagle Ford Shale and 31 Bcf in the Delaware Basin, partially offset by negative performance revisions of 49 Bcf in the DJ Basin primarily associated vertical well locations.
|
Noble Energy, Inc.
|
|
|
Supplemental Oil and Gas Information
|
|
|
|
(Unaudited)
|
|
◦
|
2018 net negative revisions of 24 Bcf include negative performance revisions of 43 Bcf in the US, partially offset by positive revisions of 19 Bcf in Equatorial Guinea and Israel. US includes positive revisions of 70 Bcf in the DJ Basin primarily due to ASC 606 adoption, offset by negative revisions of 71 Bcf in the Eagle Ford Shale due to changes in the previously adopted development plan and 42 Bcf primarily in the Delaware Basin due to changes in expected recoveries and increased operating and capital costs. Additional reserves of 17 Bcf in Equatorial Guinea and 2 Bcf in Israel relate to improved recoveries on existing wells.
|
•
|
2016 extensions in US reserves included positive performance revisions associated with our horizontal drilling programs including 230 Bcf in the Marcellus Shale, 185 Bcf in the DJ Basin, and 77 Bcf in the Delaware Basin and Eagle Ford Shale.
|
•
|
2017 extensions in US reserves included additions of 224 Bcf in the DJ Basin, 53 Bcf in the Delaware Basin and 22 Bcf in the Eagle Ford Shale primarily due to the addition of planned new locations and activity. The 2017 increase in Israel reserves represented sanction of the first phase of development of the Leviathan natural gas project.
|
•
|
2018 extensions in reserves relate to drilling plans for new wells. Increases in the US include 254 Bcf, 77 Bcf and 42 Bcf in the DJ Basin, Delaware Basin and Eagle Ford Shale, respectively, and the increase in Israel of 68 Bcf relates to the Tamar field.
|
•
|
2016 included the sale of non-strategic US onshore assets, an acreage exchange in the Marcellus Shale where we relinquished 185 Bcf, and we sold a 3.5% ownership interest in the Tamar field, offshore Israel.
|
•
|
2017 included the sale of our Marcellus Shale upstream assets and other non-strategic US onshore assets.
|
•
|
2018 sales included 20 Bcf for our Gulf of Mexico assets, 59 Bcf for other non-strategic US onshore assets and 502 Bcf for a 7.5% working interest in the Tamar field, offshore Israel.
|
Noble Energy, Inc.
|
|
|
Supplemental Oil and Gas Information
|
|
|
|
(Unaudited)
|
|
(millions)
|
|
United
States
|
|
Israel
|
|
Equatorial
Guinea
|
|
Other
Int'l
|
|
Total
|
||||||||||
Year Ended December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Revenues
|
|
$
|
3,590
|
|
|
$
|
480
|
|
|
$
|
543
|
|
|
$
|
—
|
|
|
$
|
4,613
|
|
Production Costs (1)
|
|
1,276
|
|
|
37
|
|
|
110
|
|
|
2
|
|
|
1,425
|
|
|||||
Exploration Expense
|
|
48
|
|
|
2
|
|
|
1
|
|
|
78
|
|
|
129
|
|
|||||
DD&A
|
|
1,642
|
|
|
60
|
|
|
115
|
|
|
2
|
|
|
1,819
|
|
|||||
Loss (Gain) on Divestitures, Net (2)
|
|
36
|
|
|
(376
|
)
|
|
—
|
|
|
—
|
|
|
(340
|
)
|
|||||
Asset Impairments (3)
|
|
169
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
169
|
|
|||||
Marketing Expense
|
|
40
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
40
|
|
|||||
Gain on Asset Retirement Obligation Revisions
|
|
—
|
|
|
(8
|
)
|
|
—
|
|
|
(17
|
)
|
|
(25
|
)
|
|||||
Income (Loss) before Income Taxes
|
|
379
|
|
|
765
|
|
|
317
|
|
|
(65
|
)
|
|
1,396
|
|
|||||
Income Tax Expense (4)
|
|
80
|
|
|
176
|
|
|
79
|
|
|
—
|
|
|
335
|
|
|||||
Results of Operations (5)
|
|
$
|
299
|
|
|
$
|
589
|
|
|
$
|
238
|
|
|
$
|
(65
|
)
|
|
$
|
1,061
|
|
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 and Other (6)
|
|
2,286
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,286
|
|
|||||
Asset Impairments (3)
|
|
63
|
|
|
—
|
|
|
—
|
|
|
7
|
|
|
70
|
|
|||||
Marketing Expense
|
|
47
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
47
|
|
|||||
Gain on Asset Retirement Obligation Revisions
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(42
|
)
|
|
(42
|
)
|
|||||
(Loss) Income before Income Taxes
|
|
(2,280
|
)
|
|
409
|
|
|
120
|
|
|
(56
|
)
|
|
(1,807
|
)
|
|||||
Income Tax (Benefit) Expense (4)
|
|
(798
|
)
|
|
98
|
|
|
30
|
|
|
—
|
|
|
(670
|
)
|
|||||
Results of Operations (5)
|
|
$
|
(1,482
|
)
|
|
$
|
311
|
|
|
$
|
90
|
|
|
$
|
(56
|
)
|
|
$
|
(1,137
|
)
|
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues
|
|
$
|
2,416
|
|
|
$
|
540
|
|
|
$
|
433
|
|
|
$
|
—
|
|
|
$
|
3,389
|
|
Production Costs (1)
|
|
1,108
|
|
|
49
|
|
|
118
|
|
|
1
|
|
|
1,276
|
|
|||||
Exploration Expense (7)
|
|
245
|
|
|
26
|
|
|
469
|
|
|
185
|
|
|
925
|
|
|||||
DD&A
|
|
2,103
|
|
|
81
|
|
|
205
|
|
|
6
|
|
|
2,395
|
|
|||||
Asset Impairments (3)
|
|
—
|
|
|
88
|
|
|
—
|
|
|
4
|
|
|
92
|
|
|||||
(Loss) Income before Income Taxes
|
|
(1,040
|
)
|
|
296
|
|
|
(359
|
)
|
|
(196
|
)
|
|
(1,299
|
)
|
|||||
Income Tax (Benefit) Expense (4)
|
|
(364
|
)
|
|
74
|
|
|
(90
|
)
|
|
—
|
|
|
(380
|
)
|
|||||
Results of Operations (5)
|
|
$
|
(676
|
)
|
|
$
|
222
|
|
|
$
|
(269
|
)
|
|
$
|
(196
|
)
|
|
$
|
(919
|
)
|
(1)
|
Production costs consist of lease operating expense, production and ad valorem taxes, royalty expense, transportation and gathering expense, and general and administrative expense supporting oil and gas operations.
|
(2)
|
(3)
|
2018 asset impairments relate to the sale of our Gulf of Mexico assets.
|
(4)
|
Income tax expense is based upon respective corporate statutory tax rates. During 2018, 2017, and 2016, 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 activities and overhead and interest costs. See Note 13. Derivative Instruments and Hedging Activities.
|
Noble Energy, Inc.
|
|
|
Supplemental Oil and Gas Information
|
|
|
|
(Unaudited)
|
|
(6)
|
Amount reflects reclassification of $93 million accrued exit costs for retained Marcellus Shale firm transportation commitments from our US oil and gas exploration and production reportable segment to our Corporate segment. See Note 1. Summary of Significant Accounting Policies, Note 3. Segment Information and Note 10. Marcellus Shale Firm Transportation Commitments.
|
(7)
|
Equatorial Guinea exploration expense includes amounts related to the write off of costs associated with certain discoveries. See Note 7. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
|
(millions)
|
|
United
States
|
|
Israel
|
|
Equatorial
Guinea
|
|
Other
Int'l (1)
|
|
Total
|
||||||||||
December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Property Acquisition Costs
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Proved (2)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Unproved (2)
|
|
41
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
41
|
|
|||||
Exploration Costs (3)
|
|
58
|
|
|
12
|
|
|
10
|
|
|
73
|
|
|
153
|
|
|||||
Development Costs (4)
|
|
2,303
|
|
|
663
|
|
|
20
|
|
|
(16
|
)
|
|
2,970
|
|
|||||
Total Consolidated Operations
|
|
$
|
2,402
|
|
|
$
|
675
|
|
|
$
|
30
|
|
|
$
|
57
|
|
|
$
|
3,164
|
|
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 (3)
|
|
264
|
|
|
26
|
|
|
25
|
|
|
44
|
|
|
359
|
|
|||||
Development Costs (4)
|
|
905
|
|
|
109
|
|
|
31
|
|
|
—
|
|
|
1,045
|
|
|||||
Total Consolidated Operations
|
|
$
|
1,403
|
|
|
$
|
135
|
|
|
$
|
56
|
|
|
$
|
44
|
|
|
$
|
1,638
|
|
(1)
|
Other International includes Newfoundland, Suriname (until November 2018), Falkland Islands (until December 2018), other new ventures and previous North Sea operations, which are in the process of being decommissioned.
|
(2)
|
2018 unproved property acquisition costs include US onshore undeveloped leasehold activity during the year.
|
(3)
|
2018 exploration costs relate primarily to seismic expense, drilling costs, and lease rentals.
|
(4)
|
Worldwide development costs include amounts spent to develop PUDs of approximately $1.0 billion in 2018, $1.2 billion in 2017, and $656 million in 2016.
|
Noble Energy, Inc.
|
|
|
Supplemental Oil and Gas Information
|
|
|
|
(Unaudited)
|
|
|
|
December 31,
|
||||||
(millions)
|
|
2018
|
|
2017
|
||||
Unproved Oil and Gas Properties (1)
|
|
$
|
2,321
|
|
|
$
|
2,978
|
|
Proved Oil and Gas Properties (2)
|
|
24,955
|
|
|
26,111
|
|
||
Total Oil and Gas Properties
|
|
27,276
|
|
|
29,089
|
|
||
Accumulated DD&A
|
|
(10,867
|
)
|
|
(12,538
|
)
|
||
Net Capitalized Costs
|
|
$
|
16,409
|
|
|
$
|
16,551
|
|
(1)
|
Unproved oil and gas property costs at December 31, 2018 include previous acquisition costs of $2.2 billion related to Delaware Basin properties and $100 million related to Eagle Ford Shale properties.
|
(2)
|
Proved oil and gas properties at December 31, 2018 include asset retirement costs of $966 million and assets held for sale of $133 million.
|
Noble Energy, Inc.
|
|
|
Supplemental Oil and Gas Information
|
|
|
|
(Unaudited)
|
|
(millions)
|
|
United
States
|
|
Israel (1)
|
|
Equatorial
Guinea
|
|
Other
Int'l (2)
|
|
Total
|
||||||||||
December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Future Cash Inflows (3)
|
|
$
|
38,542
|
|
|
$
|
27,559
|
|
|
$
|
2,528
|
|
|
$
|
—
|
|
|
$
|
68,629
|
|
Future Production Costs (4)
|
|
(14,793
|
)
|
|
(2,478
|
)
|
|
(1,180
|
)
|
|
—
|
|
|
(18,451
|
)
|
|||||
Future Development Costs (5)
|
|
(5,793
|
)
|
|
(1,038
|
)
|
|
(170
|
)
|
|
(32
|
)
|
|
(7,033
|
)
|
|||||
Future Income Tax Expense (6)
|
|
(2,061
|
)
|
|
(12,185
|
)
|
|
(277
|
)
|
|
—
|
|
|
(14,523
|
)
|
|||||
Future Net Cash Flows
|
|
15,895
|
|
|
11,858
|
|
|
901
|
|
|
(32
|
)
|
|
28,622
|
|
|||||
10% Annual Discount for Estimated Timing of Cash Flows
|
|
(6,493
|
)
|
|
(8,037
|
)
|
|
(158
|
)
|
|
4
|
|
|
(14,684
|
)
|
|||||
Standardized Measure of Discounted Future Net Cash Flows
|
|
$
|
9,402
|
|
|
$
|
3,821
|
|
|
$
|
743
|
|
|
$
|
(28
|
)
|
|
$
|
13,938
|
|
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
|
|
(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
|
|
(1)
|
In accordance with the Framework, we were 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. During 2018, we reduced our ownership to 25% through the sale of a 7.5% interest. Therefore, amounts at December 31, 2018 reflect a 25% interest while amounts at December 31, 2017 and 2016 reflect a 32.5% working interest. See Note 5. Acquisitions and Divestitures. 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 8. 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, 2018, 2017 and 2016, 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, 2018
|
|
|
|
|
|
|
|
|
||||||||
Average Crude Oil and Condensate Price per Bbl
|
|
$
|
66.66
|
|
|
$
|
63.94
|
|
|
$
|
70.92
|
|
|
$
|
66.88
|
|
Average Natural Gas Price per Mcf
|
|
2.17
|
|
|
5.49
|
|
|
0.27
|
|
|
4.34
|
|
||||
Average NGL Price per Bbl
|
|
24.48
|
|
|
—
|
|
|
45.15
|
|
|
25.19
|
|
||||
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
|
|
Noble Energy, Inc.
|
|
|
Supplemental Oil and Gas Information
|
|
|
|
(Unaudited)
|
|
|
|
Year Ended December 31,
|
||||||||||
(millions)
|
|
2018
|
|
2017
|
|
2016
|
||||||
Standardized Measure of Discounted Future Net Cash Flows, Beginning of Year
|
|
$
|
11,258
|
|
|
$
|
5,686
|
|
|
$
|
6,628
|
|
Changes in Standardized Measure of Discounted Future Net Cash Flows
|
|
|
|
|
|
|
||||||
Sales of Oil and Gas Produced, Net of Production Costs
|
|
(3,190
|
)
|
|
(2,674
|
)
|
|
(2,230
|
)
|
|||
Net Changes in Prices and Production Costs (1)
|
|
2,327
|
|
|
2,436
|
|
|
(593
|
)
|
|||
Extensions, Discoveries and Improved Recovery, Less Related Costs
|
|
2,036
|
|
|
3,711
|
|
|
463
|
|
|||
Changes in Estimated Future Development Costs
|
|
(738
|
)
|
|
(537
|
)
|
|
(373
|
)
|
|||
Development Costs Incurred During the Period
|
|
2,986
|
|
|
1,975
|
|
|
1,090
|
|
|||
Revisions of Previous Quantity Estimates
|
|
(9
|
)
|
|
1,462
|
|
|
364
|
|
|||
Purchases of Minerals in Place (2)
|
|
—
|
|
|
423
|
|
|
161
|
|
|||
Sales of Minerals in Place (3)
|
|
(1,873
|
)
|
|
(643
|
)
|
|
(951
|
)
|
|||
Accretion of Discount
|
|
1,538
|
|
|
778
|
|
|
919
|
|
|||
Net Change in Income Taxes (4)
|
|
(11
|
)
|
|
(1,669
|
)
|
|
414
|
|
|||
Change in Timing of Estimated Future Production and Other
|
|
(386
|
)
|
|
310
|
|
|
(206
|
)
|
|||
Aggregate Change in Standardized Measure of Discounted Future Net Cash Flows
|
|
$
|
2,680
|
|
|
$
|
5,572
|
|
|
$
|
(942
|
)
|
Standardized Measure of Discounted Future Net Cash Flows, End of Year
|
|
$
|
13,938
|
|
|
$
|
11,258
|
|
|
$
|
5,686
|
|
(1)
|
The increases in 2018 and 2017 were driven primarily by higher 12-month average commodity prices.
|
(2)
|
Purchase of minerals in 2017 relates to reserves acquired in the Clayton Williams Energy Acquisition.
|
(3)
|
(4)
|
The increase in 2018 future income tax expense relates primarily to the increase in US tax expense due to higher future taxable income and a reduction of NOL carryforwards utilized to offset future taxable income from $3.2 billion as of December 31, 2017 to $1.7 billion as of December 31, 2018. The increase is partially offset by a decrease in future taxes in Israel driven by the sale of 7.5% working interest in Tamar.
|
Noble Energy, Inc.
|
|
|
Supplemental Quarterly Financial Information
|
|
|
|
(Unaudited)
|
|
|
|
Quarter Ended
|
||||||||||||||||||
|
|
March 31,
|
|
June 30,
|
|
Sep 30,
|
|
Dec 31,
|
|
Total
|
||||||||||
(millions except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
2018 (1) (3)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues
|
|
$
|
1,286
|
|
|
$
|
1,230
|
|
|
$
|
1,273
|
|
|
$
|
1,197
|
|
|
$
|
4,986
|
|
Income (Loss) Before Income Taxes
|
|
543
|
|
|
10
|
|
|
307
|
|
|
(720
|
)
|
|
140
|
|
|||||
Net Income (Loss) Including Noncontrolling Interests
|
|
574
|
|
|
(6
|
)
|
|
248
|
|
|
(802
|
)
|
|
14
|
|
|||||
Less: Net Income Attributable to Noncontrolling Interests
|
|
20
|
|
|
17
|
|
|
21
|
|
|
22
|
|
|
80
|
|
|||||
Net Income (Loss) Attributable to Noble Energy
|
|
554
|
|
|
(23
|
)
|
|
227
|
|
|
(824
|
)
|
|
(66
|
)
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net Income (Loss) Per Share, Basic
|
|
1.14
|
|
|
(0.05
|
)
|
|
0.47
|
|
|
(1.72
|
)
|
|
(0.14
|
)
|
|||||
Net Income (Loss) Per Share, Diluted
|
|
1.14
|
|
|
(0.05
|
)
|
|
0.47
|
|
|
(1.71
|
)
|
|
(0.14
|
)
|
|||||
2017 (2) (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
|
)
|
•
|
$376 million pre-tax gain on sale of 7.5% working interest in Tamar field. See Note 5. Acquisitions and Divestitures;
|
•
|
$196 million pre-tax gain on sale of our 50% interest in CONE Gathering. See Note 5. Acquisitions and Divestitures;
|
•
|
$168 million impairment expense related to Gulf of Mexico asset divestiture. See Note 5. Acquisitions and Divestitures;
|
•
|
$145 million discrete tax benefit, net, related to changes in federal income tax regulations. See Note 12. Income Taxes; and
|
•
|
$79 million loss on commodity derivative instruments, including non-cash portion of loss on commodity derivative instruments of $51 million. See Note 13. Derivative Instruments and Hedging Activities.
|
•
|
$249 million loss on commodity derivative instruments, including non-cash portion of loss on commodity derivative instrument of $184 million. See Note 13. Derivative Instruments and Hedging Activities; and
|
•
|
$109 million gain on sale of 7.5 million CNX Midstream Partners units. See Note 5. Acquisitions and Divestitures.
|
•
|
$198 million gain on sale of 14.2 million CNX Midstream Partners units. See Note 5. Acquisitions and Divestitures; and
|
•
|
$155 million loss on commodity derivative instruments, including non-cash portion of loss on commodity derivative instruments of $88 million. See Note 13. Derivative Instruments and Hedging Activities.
|
•
|
•
|
$546 million gain on commodity derivative instruments, including non-cash portion of gain on commodity derivative instruments of $547 million. See Note 13. Derivative Instruments and Hedging Activities; and
|
•
|
$38 million impairment expense primarily related to midstream assets. See Note 14. Fair Value Measurements and Disclosures.
|
•
|
No unusual or infrequent activity.
|
•
|
$2.3 billion loss on Marcellus Shale upstream divestiture. See Note 5. Acquisitions and Divestitures.
|
•
|
•
|
$270 million deferred tax benefit, net, related to changes in federal income tax regulations; and
|
•
|
(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
|
—
|
|
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 7.25% 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 (File No. 001-07964) 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
|
—
|
|
10.52
|
—
|
|
10.53
|
—
|
|
10.54
|
—
|
|
10.55†
|
—
|
|
10.56
|
—
|
|
10.57*
|
—
|
|
21.1
|
—
|
|
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 19, 2019
|
By: /s/ David L. Stover
|
|
|
David L. Stover,
|
|
|
Chairman of the Board and Chief Executive Officer
|
|
|
|
Date:
|
February 19, 2019
|
By: /s/ Kenneth M. Fisher
|
|
|
Kenneth M. Fisher,
|
|
|
Executive Vice President, Chief Financial Officer
|
|
|
|
Date:
|
February 19, 2019
|
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 and Chief Executive Officer
|
|
February 19, 2019
|
David L. Stover
|
|
(Principal Executive Officer)
|
|
|
|
|
|
|
|
/s/ Kenneth M. Fisher
|
|
Executive Vice President, Chief Financial Officer
|
|
February 19, 2019
|
Kenneth M. Fisher
|
|
(Principal Financial Officer)
|
|
|
|
|
|
|
|
/s/ Dustin A. Hatley
|
|
Vice President, Chief Accounting Officer and Controller
|
|
February 19, 2019
|
Dustin A. Hatley
|
|
(Principal Accounting Officer)
|
|
|
|
|
|
|
|
/s/ Jeffrey L. Berenson
|
|
Director
|
|
February 19, 2019
|
Jeffrey L. Berenson
|
|
|
|
|
|
|
|
|
|
/s/ Michael A. Cawley
|
|
Director
|
|
February 19, 2019
|
Michael A. Cawley
|
|
|
|
|
|
|
|
|
|
/s/ Edward F. Cox
|
|
Director
|
|
February 19, 2019
|
Edward F. Cox
|
|
|
|
|
|
|
|
|
|
/s/ James E. Craddock
|
|
Director
|
|
February 19, 2019
|
James E. Craddock
|
|
|
|
|
|
|
|
|
|
/s/ Barbara J. Duganier
|
|
Director
|
|
February 19, 2019
|
Barbara J. Duganier
|
|
|
|
|
|
|
|
|
|
/s/ Thomas J. Edelman
|
|
Director
|
|
February 19, 2019
|
Thomas J. Edelman
|
|
|
|
|
|
|
|
|
|
/s/ Holli C. Ladhani
|
|
Director
|
|
February 19, 2019
|
Holli C. Ladhani
|
|
|
|
|
|
|
|
|
|
/s/ Scott D. Urban
|
|
Director
|
|
February 19, 2019
|
Scott D. Urban
|
|
|
|
|
|
|
|
|
|
/s/ William T. Van Kleef
|
|
Director
|
|
February 19, 2019
|
William T. Van Kleef
|
|
|
|
|
Participant Name:
|
|
|
|
Number of RSUs Awarded:
|
|
|
|
Award Date:
|
|
|
|
Vesting Date:
|
The third anniversary of the Award Date
|
Participant Name:
|
|
|
|
Number of Restricted Shares Awarded:
|
|
|
|
Award Date:
|
|
Vesting Schedule:
|
The Restricted Shares will be subject to a restricted period (the “Restricted Period”) that will commence on the Award Date and end on the third anniversary of the Award Date. During the Restricted Period, the Restricted Shares will be subject to the restrictions described in the Agreement, provided, however, that the restrictions will be removed as to:
|
(i)
|
40% of the Restricted Shares (or if such percentage results in a number of shares that includes a fraction, then the next lower whole number of shares) on the first anniversary of the Award Date, provided Participant is in the continuous employ or service of Noble Energy,Inc. (“Noble”) or an Affiliate until such date;
|
(ii)
|
40% of the Restricted Shares (or if such percentage results in a number of shares that includes a fraction, then the next lower whole number of shares) on the second anniversary of the Award Date, provided Participant is in the continuous employ or service of Noble Energy, Inc. (“Noble”) or an Affiliate until such date; and
|
(ii)
|
the remaining Restricted Shares on the third anniversary of the Award Date, provided Participant is in the continuous employ or service of Noble or an Affiliate until such date.
|
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
|
Black Diamond Rockies Midstream LLC*
|
|
Delaware
|
Black Diamond Rockies Storage and Terminals LLC*
|
|
Delaware
|
Blanco River DevCo GP LLC
|
|
Delaware
|
Blanco River DevCo LP
|
|
Delaware
|
Clayton Williams Pipeline Corporation
|
|
Delaware
|
Colorado River DevCo GP LLC
|
|
Delaware
|
Colorado River DevCo LP
|
|
Delaware
|
Delaware Crossing Holdings LLC
|
|
Delaware
|
Delaware Crossing LLC
|
|
Delaware
|
Delaware Crossing Operating LLC
|
|
Delaware
|
EDC Ecuador Ltd.
|
|
Delaware
|
EDC South America Limited
|
|
Cayman Islands
|
EMED Pipeline B.V.*
|
|
Amsterdam
|
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 Congo Holding LLC (fka NBL Nicaragua Holding, LLC)
|
|
Delaware
|
NBL Congo Limited (fka NBL Nicaragua Limited)
|
|
Cayman Islands
|
NBL Cumbia Limited
|
|
Cayman Islands
|
NBL Eastern Mediterranean Marketing Limited
|
|
Cayman Islands
|
NBL Energy Royalties, Inc. (fka NBL Royalties, Inc.)
|
|
Delaware
|
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 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 Colombia Holding LLC
|
|
Delaware
|
Noble Energy Colombia Limited
|
|
Cayman Islands
|
Noble Energy EG Ltd.
|
|
Cayman Islands
|
Noble Energy Egypt Holding LLC
|
|
Delaware
|
Noble Energy Egypt Limited
|
|
Cayman Islands
|
Noble Energy Egypt Marketing LLC
|
|
New Cairo
|
Noble Energy EMEA Ventures Limited (fka EDC Ireland)
|
|
Cayman Islands
|
Noble Energy EMed Midstream Limited
|
|
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
|
Optimized Energy Solutions, LLC*
|
|
Delaware
|
Pecos River Holdings GP LLC
|
|
Delaware
|
Pecos River Holdings LP
|
|
Delaware
|
Rosetta Resources Holdings, LLC (fka Calpine Natural Gas Holdings, LLC)
|
|
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
|
San Juan River DevCo GP LLC
|
|
Delaware
|
San Juan River DevCo LP
|
|
Delaware
|
Seven Oaks Insurance Limited
|
|
Bermuda
|
Tamar 10 Inch Pipeline Ltd.*
|
|
Tel Aviv
|
Tamar Mediterranean Gas Ltd.*
|
|
Tel Aviv
|
Trinity Delaware Holdings LLC
|
|
Delaware
|
Trinity River DevCo LLC
|
|
Delaware
|
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 19, 2019
|
|
|
|
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 19, 2019
|
|
|
|
|
|
|
/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 19, 2019
|
|
|
|
|
|
|
/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 19, 2019
|
|
/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 19, 2019
|
|
/s/ Kenneth M. Fisher
|
|
|
|
Kenneth M. Fisher
|
|
|
|
Chief Financial Officer
|
|
|
Net Reserves
|
|||||||
|
|
Oil
|
|
NGL
|
|
Gas
|
|||
Category
|
|
(MBBL)
|
|
(MBBL)
|
|
(MMCF)
|
|||
|
|
|
|
|
|
|
|||
Proved Developed Producing
|
|
192,029.584
|
|
|
129,320.904
|
|
|
2,099,331.072
|
|
Proved Developed Non-Producing
|
|
1,349.934
|
|
|
767.596
|
|
|
479,651.200
|
|
Proved Undeveloped
|
|
263,776.528
|
|
|
136,163.200
|
|
|
4,652,199.936
|
|
|
|
|
|
|
|
|
|||
Total Proved
|
|
457,156.064
|
|
|
266,251.680
|
|
|
7,231,182.848
|
|
Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.
|