Delaware
|
|
73-0785597
|
(State or other jurisdiction of incorporation or organization)
|
|
(I.R.S. employer identification number)
|
1001 Noble Energy Way
|
|
|
Houston, Texas
|
|
77070
|
(Address of principal executive offices)
|
|
(Zip Code)
|
(281) 872-3100
(Registrant’s telephone number, including area code)
|
Large accelerated filer x
|
Accelerated filer o
|
Non-accelerated filer o
|
Smaller reporting company o
|
Emerging growth company o
|
|
|
(Do not check if a smaller reporting company)
|
|
|
Part I. Financial Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Item 4. Controls and Procedures
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Item 5. Other Information
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Revenues
|
|
|
|
|
|
|
|
||||||||
Oil, NGL and Gas Sales
|
$
|
1,100
|
|
|
$
|
1,017
|
|
|
$
|
2,273
|
|
|
$
|
2,011
|
|
Income from Equity Method Investees and Other
|
130
|
|
|
42
|
|
|
243
|
|
|
84
|
|
||||
Total
|
1,230
|
|
|
1,059
|
|
|
2,516
|
|
|
2,095
|
|
||||
Costs and Expenses
|
|
|
|
|
|
|
|
|
|
||||||
Production Expense
|
292
|
|
|
283
|
|
|
613
|
|
|
586
|
|
||||
Exploration Expense
|
29
|
|
|
30
|
|
|
64
|
|
|
72
|
|
||||
Depreciation, Depletion and Amortization
|
465
|
|
|
503
|
|
|
933
|
|
|
1,031
|
|
||||
Loss on Marcellus Shale Upstream Divestiture
|
—
|
|
|
2,322
|
|
|
—
|
|
|
2,322
|
|
||||
Gain on Divestitures, Net
|
(78
|
)
|
|
—
|
|
|
(666
|
)
|
|
—
|
|
||||
Asset Impairments
|
—
|
|
|
—
|
|
|
168
|
|
|
—
|
|
||||
General and Administrative
|
105
|
|
|
103
|
|
|
209
|
|
|
202
|
|
||||
Other Operating Expense, Net
|
74
|
|
|
118
|
|
|
144
|
|
|
147
|
|
||||
Total
|
887
|
|
|
3,359
|
|
|
1,465
|
|
|
4,360
|
|
||||
Operating Income (Loss)
|
343
|
|
|
(2,300
|
)
|
|
1,051
|
|
|
(2,265
|
)
|
||||
Other (Income) Expense
|
|
|
|
|
|
|
|
|
|
||||||
Loss (Gain) on Commodity Derivative Instruments
|
249
|
|
|
(57
|
)
|
|
328
|
|
|
(167
|
)
|
||||
Interest, Net of Amount Capitalized
|
73
|
|
|
96
|
|
|
146
|
|
|
183
|
|
||||
Other Non-Operating Expense (Income), Net
|
11
|
|
|
(5
|
)
|
|
24
|
|
|
(6
|
)
|
||||
Total
|
333
|
|
|
34
|
|
|
498
|
|
|
10
|
|
||||
Income (Loss) Before Income Taxes
|
10
|
|
|
(2,334
|
)
|
|
553
|
|
|
(2,275
|
)
|
||||
Income Tax Expense (Benefit)
|
16
|
|
|
(836
|
)
|
|
(15
|
)
|
|
(824
|
)
|
||||
Net (Loss) Income and Comprehensive (Loss) Income Including Noncontrolling Interests
|
(6
|
)
|
|
(1,498
|
)
|
|
568
|
|
|
(1,451
|
)
|
||||
Less: Net Income and Comprehensive Income Attributable to Noncontrolling Interests
|
17
|
|
|
14
|
|
|
37
|
|
|
25
|
|
||||
Net (Loss) Income and Comprehensive Income (Loss) Attributable to Noble Energy
|
$
|
(23
|
)
|
|
$
|
(1,512
|
)
|
|
$
|
531
|
|
|
$
|
(1,476
|
)
|
|
|
|
|
|
|
|
|
||||||||
Net (Loss) Income Attributable to Noble Energy per Common Share
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
(0.05
|
)
|
|
$
|
(3.20
|
)
|
|
$
|
1.09
|
|
|
$
|
(3.27
|
)
|
Diluted
|
$
|
(0.05
|
)
|
|
$
|
(3.20
|
)
|
|
$
|
1.09
|
|
|
$
|
(3.27
|
)
|
Weighted Average Number of Common Shares Outstanding
|
|
|
|
|
|
|
|
||||||||
Basic
|
484
|
|
|
472
|
|
|
485
|
|
|
452
|
|
||||
Diluted
|
484
|
|
|
472
|
|
|
487
|
|
|
452
|
|
|
June 30,
2018 |
|
December 31,
2017 |
||||
ASSETS
|
|
|
|
||||
Current Assets
|
|
|
|
||||
Cash and Cash Equivalents
|
$
|
621
|
|
|
$
|
675
|
|
Accounts Receivable, Net
|
743
|
|
|
748
|
|
||
Other Current Assets
|
187
|
|
|
780
|
|
||
Total Current Assets
|
1,551
|
|
|
2,203
|
|
||
Property, Plant and Equipment
|
|
|
|
|
|
||
Oil and Gas Properties (Successful Efforts Method of Accounting)
|
28,334
|
|
|
29,678
|
|
||
Property, Plant and Equipment, Other
|
896
|
|
|
879
|
|
||
Total Property, Plant and Equipment, Gross
|
29,230
|
|
|
30,557
|
|
||
Accumulated Depreciation, Depletion and Amortization
|
(11,313
|
)
|
|
(13,055
|
)
|
||
Total Property, Plant and Equipment, Net
|
17,917
|
|
|
17,502
|
|
||
Other Noncurrent Assets
|
984
|
|
|
461
|
|
||
Goodwill
|
1,402
|
|
|
1,310
|
|
||
Total Assets
|
$
|
21,854
|
|
|
$
|
21,476
|
|
LIABILITIES AND EQUITY
|
|
|
|
||||
Current Liabilities
|
|
|
|
|
|||
Accounts Payable – Trade
|
$
|
1,308
|
|
|
$
|
1,161
|
|
Other Current Liabilities
|
745
|
|
|
578
|
|
||
Total Current Liabilities
|
2,053
|
|
|
1,739
|
|
||
Long-Term Debt
|
6,555
|
|
|
6,746
|
|
||
Deferred Income Taxes
|
970
|
|
|
1,127
|
|
||
Other Noncurrent Liabilities
|
995
|
|
|
1,245
|
|
||
Total Liabilities
|
10,573
|
|
|
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; 526 Million and 529 Million Shares Issued, respectively
|
5
|
|
|
5
|
|
||
Additional Paid in Capital
|
8,329
|
|
|
8,438
|
|
||
Accumulated Other Comprehensive Loss
|
(28
|
)
|
|
(30
|
)
|
||
Treasury Stock, at Cost; 39 Million Shares
|
(731
|
)
|
|
(725
|
)
|
||
Retained Earnings
|
2,677
|
|
|
2,248
|
|
||
Noble Energy Share of Equity
|
10,252
|
|
|
9,936
|
|
||
Noncontrolling Interests
|
1,029
|
|
|
683
|
|
||
Total Equity
|
11,281
|
|
|
10,619
|
|
||
Total Liabilities and Equity
|
$
|
21,854
|
|
|
$
|
21,476
|
|
|
Six Months Ended June 30,
|
||||||
|
2018
|
|
2017
|
||||
Cash Flows From Operating Activities
|
|
|
|
||||
Net Income (Loss) Including Noncontrolling Interests
|
$
|
568
|
|
|
$
|
(1,451
|
)
|
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
|
|
|
|
||||
Depreciation, Depletion and Amortization
|
933
|
|
|
1,031
|
|
||
Loss on Marcellus Shale Upstream Divestiture
|
—
|
|
|
2,322
|
|
||
Gain on Divestitures, Net
|
(666
|
)
|
|
—
|
|
||
Asset Impairments
|
168
|
|
|
—
|
|
||
Deferred Income Tax Benefit
|
(164
|
)
|
|
(873
|
)
|
||
Loss (Gain) on Commodity Derivative Instruments
|
328
|
|
|
(167
|
)
|
||
Net Cash (Paid) Received in Settlement of Commodity Derivative Instruments
|
(93
|
)
|
|
14
|
|
||
Stock Based Compensation
|
35
|
|
|
67
|
|
||
Other Adjustments for Noncash Items Included in Income (Loss)
|
22
|
|
|
33
|
|
||
Changes in Operating Assets and Liabilities
|
|
|
|
||||
Decrease (Increase) in Accounts Receivable
|
76
|
|
|
(123
|
)
|
||
(Decrease) Increase in Accounts Payable
|
(24
|
)
|
|
120
|
|
||
Decrease in Current Income Taxes Payable
|
3
|
|
|
(42
|
)
|
||
Other Current Assets and Liabilities, Net
|
(58
|
)
|
|
(42
|
)
|
||
Other Operating Assets and Liabilities, Net
|
(49
|
)
|
|
(12
|
)
|
||
Net Cash Provided by Operating Activities
|
1,079
|
|
|
877
|
|
||
Cash Flows From Investing Activities
|
|
|
|
||||
Additions to Property, Plant and Equipment
|
(1,782
|
)
|
|
(1,215
|
)
|
||
Proceeds from Sale of 7.5% Interest in Tamar Field
|
484
|
|
|
—
|
|
||
Proceeds from Sale of CONE Gathering LLC and CNX Midstream Partners Common Units
|
443
|
|
|
—
|
|
||
Proceeds from Gulf of Mexico Divestiture
|
383
|
|
|
—
|
|
||
Proceeds from Marcellus Shale Upstream Divestiture
|
—
|
|
|
1,028
|
|
||
Clayton Williams Energy Acquisition
|
—
|
|
|
(616
|
)
|
||
Acquisitions, Net of Cash Acquired
|
(650
|
)
|
|
(351
|
)
|
||
Proceeds from Other Divestitures
|
72
|
|
|
101
|
|
||
Additions to Equity Method Investments
|
—
|
|
|
(68
|
)
|
||
Other
|
—
|
|
|
—
|
|
||
Net Cash Used in Investing Activities
|
(1,050
|
)
|
|
(1,121
|
)
|
||
Cash Flows From Financing Activities
|
|
|
|
||||
Dividends Paid, Common Stock
|
(102
|
)
|
|
(92
|
)
|
||
Purchase and Retirement of Common Stock
|
(130
|
)
|
|
—
|
|
||
Proceeds from Noble Midstream Services Revolving Credit Facility
|
610
|
|
|
195
|
|
||
Repayment of Noble Midstream Services Revolving Credit Facility
|
(165
|
)
|
|
(5
|
)
|
||
Contributions from Noncontrolling Interest Owners
|
331
|
|
|
—
|
|
||
Issuance of Noble Midstream Partners Common Units, Net of Offering Costs
|
—
|
|
|
138
|
|
||
Proceeds from Revolving Credit Facility
|
905
|
|
|
1,310
|
|
||
Repayment of Revolving Credit Facility
|
(1,135
|
)
|
|
(1,310
|
)
|
||
Repayment of Clayton Williams Energy Long-term Debt
|
—
|
|
|
(595
|
)
|
||
Repayment of Senior Notes
|
(384
|
)
|
|
—
|
|
||
Other
|
(51
|
)
|
|
(67
|
)
|
||
Net Cash Used in Financing Activities
|
(121
|
)
|
|
(426
|
)
|
||
Decrease in Cash, Cash Equivalents, and Restricted Cash
|
(92
|
)
|
|
(670
|
)
|
||
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period
|
713
|
|
|
1,210
|
|
||
Cash, Cash Equivalents, and Restricted Cash at End of Period
|
$
|
621
|
|
|
$
|
540
|
|
|
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, 2017
|
$
|
5
|
|
|
$
|
8,438
|
|
|
$
|
(30
|
)
|
|
$
|
(725
|
)
|
|
$
|
2,248
|
|
|
$
|
683
|
|
|
$
|
10,619
|
|
Net Income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
531
|
|
|
37
|
|
|
568
|
|
|||||||
Stock-based Compensation
|
—
|
|
|
46
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
46
|
|
|||||||
Dividends (21 cents per share)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(102
|
)
|
|
—
|
|
|
(102
|
)
|
|||||||
Purchase and Retirement of Common Stock
|
—
|
|
|
(130
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(130
|
)
|
|||||||
Clayton Williams Energy Acquisition
|
—
|
|
|
(25
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(25
|
)
|
|||||||
Distributions to Noncontrolling Interest Owners
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(22
|
)
|
|
(22
|
)
|
|||||||
Contributions from Noncontrolling Interest Owners
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
331
|
|
|
331
|
|
|||||||
Other
|
—
|
|
|
—
|
|
|
2
|
|
|
(6
|
)
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
|||||||
June 30, 2018
|
$
|
5
|
|
|
$
|
8,329
|
|
|
$
|
(28
|
)
|
|
$
|
(731
|
)
|
|
$
|
2,677
|
|
|
$
|
1,029
|
|
|
$
|
11,281
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
December 31, 2016
|
$
|
5
|
|
|
$
|
6,450
|
|
|
$
|
(31
|
)
|
|
$
|
(692
|
)
|
|
$
|
3,556
|
|
|
$
|
312
|
|
|
$
|
9,600
|
|
Net (Loss) Income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,476
|
)
|
|
25
|
|
|
(1,451
|
)
|
|||||||
Clayton Williams Energy Acquisition
|
—
|
|
|
1,876
|
|
|
—
|
|
|
(25
|
)
|
|
—
|
|
|
—
|
|
|
1,851
|
|
|||||||
Stock-based Compensation
|
—
|
|
|
65
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
65
|
|
|||||||
Dividends (20 cents per share)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(92
|
)
|
|
—
|
|
|
(92
|
)
|
|||||||
Issuance of Noble Midstream Partners Common Units, Net of Offering Costs
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
138
|
|
|
138
|
|
|||||||
Distributions to Noncontrolling Interest Owners
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(12
|
)
|
|
(12
|
)
|
|||||||
Other
|
—
|
|
|
8
|
|
|
1
|
|
|
(10
|
)
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|||||||
June 30, 2017
|
$
|
5
|
|
|
$
|
8,399
|
|
|
$
|
(30
|
)
|
|
$
|
(727
|
)
|
|
$
|
1,988
|
|
|
$
|
463
|
|
|
$
|
10,098
|
|
(millions)
|
July - Dec 2018
|
2019
|
2020
|
Total
|
||||||||
Natural Gas Revenues (1)
|
$
|
107
|
|
$
|
137
|
|
$
|
169
|
|
$
|
413
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
(millions)
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Income From Equity Method Investees and Other
|
|
|
|
|
|
|
|
|
|
||||||
Income from Equity Method Investees
|
$
|
49
|
|
|
$
|
38
|
|
|
$
|
96
|
|
|
$
|
80
|
|
Sales of Purchased Oil and Gas (1)
|
66
|
|
|
—
|
|
|
119
|
|
|
—
|
|
||||
Midstream Services Revenues – Third Party
|
15
|
|
|
4
|
|
|
28
|
|
|
4
|
|
||||
Total
|
$
|
130
|
|
|
$
|
42
|
|
|
$
|
243
|
|
|
$
|
84
|
|
Production Expense
|
|
|
|
|
|
|
|
|
|
||||||
Lease Operating Expense
|
$
|
132
|
|
|
$
|
124
|
|
|
$
|
287
|
|
|
$
|
263
|
|
Production and Ad Valorem Taxes
|
50
|
|
|
32
|
|
|
104
|
|
|
73
|
|
||||
Gathering, Transportation and Processing Expense
|
100
|
|
|
121
|
|
|
195
|
|
|
240
|
|
||||
Other Royalty Expense
|
10
|
|
|
6
|
|
|
27
|
|
|
10
|
|
||||
Total
|
$
|
292
|
|
|
$
|
283
|
|
|
$
|
613
|
|
|
$
|
586
|
|
Exploration Expense
|
|
|
|
|
|
|
|
||||||||
Leasehold Impairment and Amortization
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
18
|
|
Seismic, Geological and Geophysical
|
2
|
|
|
8
|
|
|
13
|
|
|
13
|
|
||||
Staff Expense
|
13
|
|
|
16
|
|
|
27
|
|
|
29
|
|
||||
Other
|
14
|
|
|
6
|
|
|
24
|
|
|
12
|
|
||||
Total
|
$
|
29
|
|
|
$
|
30
|
|
|
$
|
64
|
|
|
$
|
72
|
|
Other Operating Expense, Net
|
|
|
|
|
|
|
|
||||||||
Marketing Expense (2)
|
$
|
7
|
|
|
$
|
14
|
|
|
$
|
12
|
|
|
$
|
33
|
|
Purchased Oil and Gas (1)
|
71
|
|
|
—
|
|
|
128
|
|
|
—
|
|
||||
Clayton Williams Energy Acquisition Expenses
|
—
|
|
|
90
|
|
|
—
|
|
|
94
|
|
||||
Other, Net
|
(4
|
)
|
|
14
|
|
|
4
|
|
|
20
|
|
||||
Total
|
$
|
74
|
|
|
$
|
118
|
|
|
$
|
144
|
|
|
$
|
147
|
|
Other Non-Operating Expense (Income), Net
|
|
|
|
|
|
|
|
||||||||
Loss on Investment in Shares of Tamar Petroleum Ltd., Net (3)
|
$
|
11
|
|
|
$
|
—
|
|
|
$
|
26
|
|
|
$
|
—
|
|
Other
|
—
|
|
|
(5
|
)
|
|
(2
|
)
|
|
(6
|
)
|
||||
Total
|
$
|
11
|
|
|
$
|
(5
|
)
|
|
$
|
24
|
|
|
$
|
(6
|
)
|
(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 have 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. The cost to purchase natural gas includes transportation expense incurred of $6 million and $11 million for second quarter and the first six months of 2018, respectively. See Note 11. Segment Information and Note 12. Commitments and Contingencies.
|
(2)
|
Expense relates to unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments.
|
(3)
|
Amounts for second quarter and the first six months of 2018 include losses of $11 million and $40 million, respectively, related to the change in fair value. The loss for the six months ended June 30, 2018 is partially offset by dividend income of $14 million. There was no dividend income for second quarter 2018.
|
(millions)
|
June 30,
2018 |
|
December 31,
2017 |
||||
Accounts Receivable, Net
|
|
|
|
||||
Commodity Sales
|
$
|
460
|
|
|
$
|
455
|
|
Joint Interest Billings
|
210
|
|
|
207
|
|
||
Other
|
89
|
|
|
103
|
|
||
Allowance for Doubtful Accounts
|
(16
|
)
|
|
(17
|
)
|
||
Total
|
$
|
743
|
|
|
$
|
748
|
|
Other Current Assets
|
|
|
|
|
|
||
Inventories, Materials and Supplies
|
$
|
46
|
|
|
$
|
66
|
|
Inventories, Crude Oil
|
27
|
|
|
16
|
|
||
Commodity Derivative Assets
|
29
|
|
|
2
|
|
||
Assets Held for Sale (1)
|
40
|
|
|
629
|
|
||
Restricted Cash (2)
|
—
|
|
|
38
|
|
||
Prepaid Expenses and Other Current Assets
|
45
|
|
|
29
|
|
||
Total
|
$
|
187
|
|
|
$
|
780
|
|
Other Noncurrent Assets
|
|
|
|
|
|
||
Equity Method Investments (3)
|
$
|
357
|
|
|
$
|
305
|
|
Customer-Related Intangible Assets (4)
|
326
|
|
|
—
|
|
||
Investment in Shares of Tamar Petroleum Ltd. (5)
|
150
|
|
|
—
|
|
||
Mutual Fund Investments
|
57
|
|
|
57
|
|
||
Net Deferred Income Tax Asset
|
25
|
|
|
25
|
|
||
Other Assets, Noncurrent
|
69
|
|
|
74
|
|
||
Total
|
$
|
984
|
|
|
$
|
461
|
|
Other Current Liabilities
|
|
|
|
|
|
||
Production and Ad Valorem Taxes
|
$
|
111
|
|
|
$
|
84
|
|
Commodity Derivative Liabilities
|
250
|
|
|
58
|
|
||
Income Taxes Payable
|
5
|
|
|
18
|
|
||
Asset Retirement Obligations
|
92
|
|
|
51
|
|
||
Interest Payable
|
64
|
|
|
67
|
|
||
Current Portion of Capital Lease Obligations
|
47
|
|
|
61
|
|
||
Liabilities Associated with Assets Held for Sale (1)
|
—
|
|
|
55
|
|
||
Compensation and Benefits Payable
|
66
|
|
|
98
|
|
||
Other Liabilities, Current
|
110
|
|
|
86
|
|
||
Total
|
$
|
745
|
|
|
$
|
578
|
|
Other Noncurrent Liabilities
|
|
|
|
|
|
||
Deferred Compensation Liabilities
|
$
|
180
|
|
|
$
|
197
|
|
Asset Retirement Obligations
|
543
|
|
|
824
|
|
||
Marcellus Shale Firm Transportation Commitment (6)
|
71
|
|
|
76
|
|
||
Production and Ad Valorem Taxes
|
39
|
|
|
69
|
|
||
Commodity Derivative Liabilities
|
85
|
|
|
15
|
|
||
Other Liabilities, Noncurrent
|
77
|
|
|
64
|
|
||
Total
|
$
|
995
|
|
|
$
|
1,245
|
|
(1)
|
Assets held for sale at June 30, 2018 include assets in the Greeley Crescent area of the DJ Basin. 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, offshore Israel, our interest in Southwest Royalties, Inc. acquired in the Clayton Williams Energy Acquisition, and the CONE investments. Liabilities associated with
|
(2)
|
Balance at December 31, 2017 represents amount held in escrow pending closing of the Saddle Butte acquisition. See Note 3. Acquisitions and Divestitures.
|
(3)
|
Includes $49 million for our investment in shares of CNX Midstream Partners LP. At December 31, 2017, this investment was included in assets held for sale. See Note 3. Acquisitions and Divestitures and Note 6. Fair Value Measurements and Disclosures.
|
(4)
|
Amount relates to intangible assets acquired in the Saddle Butte acquisition and is net of $14 million of accumulated amortization. See Note 3. Acquisitions and Divestitures.
|
(5)
|
Amount relates to our investment in shares of Tamar Petroleum Ltd. See Note 3. Acquisitions and Divestitures and Note 6. Fair Value Measurements and Disclosures.
|
(6)
|
Amounts relate to the long-term portion of retained firm transportation agreements. At June 30, 2018 and December 31, 2017, we recorded $12 million and $14 million, respectively, associated with the current portion of the Marcellus Shale firm transportation commitment. See Note 12. Commitments and Contingencies.
|
|
Six Months Ended June 30,
|
||||||
(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
|
$
|
621
|
|
|
$
|
540
|
|
Restricted Cash at End of Period
|
—
|
|
|
—
|
|
||
Cash, Cash Equivalents, and Restricted Cash at End of Period
|
$
|
621
|
|
|
$
|
540
|
|
(millions)
|
|
||
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
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
(millions, except per share amounts)
|
2018 (1)
|
|
2017
|
|
2018 (1)
|
|
2017
|
||||||||
Revenues
|
$
|
1,230
|
|
|
$
|
1,070
|
|
|
$
|
2,516
|
|
|
$
|
2,141
|
|
Net (Loss) Income and Comprehensive (Loss) Income Attributable to Noble Energy
|
(23
|
)
|
|
(1,354
|
)
|
|
531
|
|
|
(1,324
|
)
|
||||
|
|
|
|
|
|
|
|
||||||||
Net (Loss) Income Attributable to Noble Energy per Common Share
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
(0.05
|
)
|
|
$
|
(2.77
|
)
|
|
$
|
1.09
|
|
|
$
|
(2.71
|
)
|
Diluted
|
$
|
(0.05
|
)
|
|
$
|
(2.77
|
)
|
|
$
|
1.09
|
|
|
$
|
(2.71
|
)
|
(1)
|
No pro forma adjustments were made for the period as Clayton Williams Energy operations are included in our historical results.
|
|
|
|
|
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
|
||||||||||
2018
|
Swaps
|
NYMEX WTI
|
66,000
|
$
|
—
|
|
$
|
60.30
|
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
2018
|
Collars
|
NYMEX WTI
|
18,000
|
—
|
|
—
|
|
|
—
|
|
50.42
|
|
58.82
|
|
|||||
2018
|
Three-Way Collars
|
NYMEX WTI
|
10,000
|
—
|
|
—
|
|
|
45.50
|
|
52.50
|
|
69.09
|
|
|||||
2018
|
Three-Way Collars
|
Dated Brent
|
3,000
|
—
|
|
—
|
|
|
40.00
|
|
50.00
|
|
70.41
|
|
|||||
2018
|
Swaps
|
ICE Brent
|
2,000
|
—
|
|
59.00
|
|
|
—
|
|
—
|
|
—
|
|
|||||
2018
|
Collars
|
ICE Brent
|
2,000
|
—
|
|
—
|
|
|
—
|
|
50.00
|
|
55.25
|
|
|||||
2018
|
Three-Way Collars
|
ICE Brent
|
5,000
|
—
|
|
—
|
|
|
43.00
|
|
50.00
|
|
59.50
|
|
|||||
2018
|
Basis Swaps
|
(1)
|
20,000
|
(2.30
|
)
|
—
|
|
|
—
|
|
—
|
|
—
|
|
|||||
2019
|
Swaps
|
NYMEX WTI
|
44,000
|
—
|
|
58.37
|
|
|
—
|
|
—
|
|
—
|
|
|||||
2019
|
Three-Way Collars
|
NYMEX WTI
|
6,000
|
—
|
|
—
|
|
|
50.00
|
|
60.00
|
|
72.75
|
|
|||||
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 (2)
|
NYMEX WTI
|
5,000
|
—
|
|
61.79
|
|
|
—
|
|
—
|
|
—
|
|
|||||
2020
|
Basis Swaps
|
(1)
|
15,000
|
(5.01
|
)
|
—
|
|
|
—
|
|
—
|
|
—
|
|
|
Fair Value of Derivative Instruments
|
||||||||||||||||||||||
|
Asset Derivative Instruments
|
|
Liability Derivative Instruments
|
||||||||||||||||||||
|
June 30,
2018 |
|
December 31,
2017 |
|
June 30,
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
|
|
$
|
29
|
|
|
Current Assets
|
|
$
|
2
|
|
|
Current Liabilities
|
|
$
|
250
|
|
|
Current Liabilities
|
|
$
|
58
|
|
|
Noncurrent Assets
|
|
—
|
|
|
Noncurrent Assets
|
|
—
|
|
|
Noncurrent Liabilities
|
|
85
|
|
|
Noncurrent Liabilities
|
|
15
|
|
||||
Total
|
|
|
$
|
29
|
|
|
|
|
$
|
2
|
|
|
|
|
$
|
335
|
|
|
|
|
$
|
73
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
(millions)
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Cash Paid (Received) in Settlement of Commodity Derivative Instruments
|
|
|
|
|
|
|
|
||||||||
Crude Oil
|
$
|
66
|
|
|
$
|
(11
|
)
|
|
$
|
96
|
|
|
$
|
(16
|
)
|
Natural Gas
|
(1
|
)
|
|
—
|
|
|
(3
|
)
|
|
2
|
|
||||
Total Cash Paid (Received) in Settlement of Commodity Derivative Instruments
|
65
|
|
|
(11
|
)
|
|
93
|
|
|
(14
|
)
|
||||
Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments
|
|
|
|
|
|
|
|
||||||||
Crude Oil
|
181
|
|
|
(28
|
)
|
|
231
|
|
|
(91
|
)
|
||||
Natural Gas
|
3
|
|
|
(18
|
)
|
|
4
|
|
|
(62
|
)
|
||||
Total Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments
|
184
|
|
|
(46
|
)
|
|
235
|
|
|
(153
|
)
|
||||
Loss (Gain) on Commodity Derivative Instruments
|
|
|
|
|
|
|
|
||||||||
Crude Oil
|
247
|
|
|
(39
|
)
|
|
327
|
|
|
(107
|
)
|
||||
Natural Gas
|
2
|
|
|
(18
|
)
|
|
1
|
|
|
(60
|
)
|
||||
Total Loss (Gain) on Commodity Derivative Instruments
|
$
|
249
|
|
|
$
|
(57
|
)
|
|
$
|
328
|
|
|
$
|
(167
|
)
|
|
June 30,
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
|
530
|
|
|
3.25
|
%
|
|
85
|
|
|
2.75
|
%
|
||
Leviathan Term Loan Facility, due February 23, 2025
|
—
|
|
|
—
|
%
|
|
—
|
|
|
—
|
%
|
||
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
|
241
|
|
|
—
|
%
|
|
273
|
|
|
—
|
%
|
||
Total
|
6,663
|
|
|
|
|
6,859
|
|
|
|
||||
Unamortized Discount
|
(23
|
)
|
|
|
|
(24
|
)
|
|
|
||||
Unamortized Premium (1)
|
—
|
|
|
|
|
12
|
|
|
|
||||
Unamortized Debt Issuance Costs
|
(38
|
)
|
|
|
|
(40
|
)
|
|
|
||||
Total Debt, Net of Unamortized Discount, Premium and Debt Issuance Costs
|
6,602
|
|
|
|
|
6,807
|
|
|
|
||||
Less Amounts Due Within One Year
|
|
|
|
|
|
|
|
||||||
Capital Lease Obligations
|
(47
|
)
|
|
|
|
(61
|
)
|
|
|
||||
Long-Term Debt Due After One Year
|
$
|
6,555
|
|
|
|
|
$
|
6,746
|
|
|
|
|
Fair Value Measurements Using
|
|
|
|
|
||||||||||||||
(millions)
|
Quoted Prices in
Active Markets
(Level 1) (1)
|
|
Significant Other
Observable Inputs
(Level 2) (2)
|
|
Significant
Unobservable
Inputs (Level 3) (3)
|
|
Adjustment (4)
|
|
Fair Value Measurement
|
||||||||||
June 30, 2018
|
|
|
|
|
|
|
|
|
|
||||||||||
Financial Assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Mutual Fund Investments
|
$
|
57
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
57
|
|
Commodity Derivative Instruments
|
—
|
|
|
72
|
|
|
—
|
|
|
(43
|
)
|
|
29
|
|
|||||
Investment in Tamar Petroleum Ltd. (38,495,575 Shares) (5)
|
—
|
|
|
150
|
|
|
—
|
|
|
—
|
|
|
150
|
|
|||||
Financial Liabilities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Commodity Derivative Instruments
|
—
|
|
|
(378
|
)
|
|
—
|
|
|
43
|
|
|
(335
|
)
|
|||||
Portion of Deferred Compensation Liability Measured at Fair Value
|
(73
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(73
|
)
|
|||||
Stock Based Compensation Liability Measured at Fair Value
|
(12
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(12
|
)
|
|||||
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)
|
Level 1 measurements are fair value measurements which use quoted market prices (unadjusted) in active markets for identical assets or liabilities. We use Level 1 inputs when available as Level 1 inputs generally provide the most reliable evidence of fair value.
|
(2)
|
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.
|
(3)
|
Level 3 measurements are fair value measurements which use unobservable inputs.
|
(4)
|
Amount represents the impact of netting provisions within our master agreements that allow us to net cash settle asset and liability positions with the same counterparty.
|
(5)
|
As of June 30, 2018, the closing price on the TASE of publicly traded and unrestricted shares of Tamar Petroleum Ltd. was $4.60 per share.
|
|
June 30, 2018
|
|
December 31, 2017
|
||||||||||||
(millions)
|
Carrying Amount
|
|
Fair Value
|
|
Carrying Amount
|
|
Fair Value
|
||||||||
Investment in CNX Midstream Partners (14,217,198 Common Units and 21,692,198 Common Units, respectively) (1)
|
$
|
49
|
|
|
$
|
276
|
|
|
$
|
70
|
|
|
$
|
364
|
|
(1)
|
During second quarter 2018, we sold 7.5 million common units, reducing our ownership in CNX Midstream Partners. See Note 3. Acquisitions and Divestitures.
|
|
June 30, 2018
|
|
December 31, 2017
|
||||||||||||
(millions)
|
Carrying Amount
|
|
Fair Value
|
|
Carrying Amount
|
|
Fair Value
|
||||||||
Long-Term Debt (1)
|
$
|
6,422
|
|
|
$
|
6,591
|
|
|
$
|
6,586
|
|
|
$
|
7,142
|
|
(1)
|
Excludes unamortized discount, premium, debt issuance costs and capital lease obligations.
|
(millions)
|
Six Months Ended June 30, 2018
|
||
Capitalized Exploratory Well Costs, Beginning of Period
|
$
|
520
|
|
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves
|
4
|
|
|
Divestitures (1)
|
(167
|
)
|
|
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves
|
(1
|
)
|
|
Capitalized Exploratory Well Costs Charged to Expense
|
—
|
|
|
Capitalized Exploratory Well Costs, End of Period
|
$
|
356
|
|
(millions)
|
June 30,
2018 |
|
December 31,
2017 |
||||
Exploratory Well Costs Capitalized for a Period of One Year or Less
|
$
|
8
|
|
|
$
|
10
|
|
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling
|
348
|
|
|
510
|
|
||
Balance at End of Period
|
$
|
356
|
|
|
$
|
520
|
|
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling
|
7
|
|
|
8
|
|
|
Six Months Ended June 30,
|
||||||
(millions)
|
2018
|
|
2017
|
||||
Asset Retirement Obligations, Beginning Balance
|
$
|
875
|
|
|
$
|
935
|
|
Liabilities Incurred
|
14
|
|
|
82
|
|
||
Liabilities Settled
|
(261
|
)
|
|
(32
|
)
|
||
Revisions of Estimates
|
(10
|
)
|
|
(15
|
)
|
||
Accretion Expense (1)
|
17
|
|
|
23
|
|
||
Asset Retirement Obligations, Ending Balance
|
$
|
635
|
|
|
$
|
993
|
|
(1)
|
Accretion expense is included in depreciation, depletion and amortization (DD&A) expense in the consolidated statements of operations.
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
(millions, except percentages)
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Current
|
$
|
23
|
|
|
$
|
37
|
|
|
$
|
149
|
|
|
$
|
49
|
|
Deferred
|
(7
|
)
|
|
(873
|
)
|
|
(164
|
)
|
|
(873
|
)
|
||||
Total Income Tax Expense (Benefit)
|
$
|
16
|
|
|
$
|
(836
|
)
|
|
$
|
(15
|
)
|
|
$
|
(824
|
)
|
Effective Tax Rate
|
160.0
|
%
|
|
35.8
|
%
|
|
(2.7
|
)%
|
|
36.2
|
%
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
(millions, except per share amounts)
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Net (Loss) Income and Comprehensive (Loss) Income Attributable to Noble Energy
|
$
|
(23
|
)
|
|
$
|
(1,512
|
)
|
|
$
|
531
|
|
|
$
|
(1,476
|
)
|
Weighted Average Number of Shares Outstanding, Basic
|
484
|
|
|
472
|
|
|
485
|
|
|
452
|
|
||||
Incremental Shares from Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust
|
—
|
|
|
—
|
|
|
2
|
|
|
—
|
|
||||
Weighted Average Number of Shares Outstanding, Diluted
|
484
|
|
|
472
|
|
|
487
|
|
|
452
|
|
||||
(Loss) Income Per Share, Basic
|
$
|
(0.05
|
)
|
|
$
|
(3.20
|
)
|
|
$
|
1.09
|
|
|
$
|
(3.27
|
)
|
(Loss) Income Per Share, Diluted
|
(0.05
|
)
|
|
(3.20
|
)
|
|
1.09
|
|
|
(3.27
|
)
|
||||
Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above
|
14
|
|
|
16
|
|
|
14
|
|
|
15
|
|
|
|
|
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
|
||||||||||||||||
Three Months Ended June 30, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
Crude Oil Sales
|
$
|
749
|
|
|
$
|
635
|
|
|
$
|
2
|
|
|
$
|
112
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
NGL Sales
|
137
|
|
|
137
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Natural Gas Sales
|
214
|
|
|
98
|
|
|
111
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Total Crude Oil, NGL and Natural Gas Sales
|
1,100
|
|
|
870
|
|
|
113
|
|
|
117
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Income from Equity Method Investees and Other
|
64
|
|
|
—
|
|
|
—
|
|
|
36
|
|
|
—
|
|
|
28
|
|
|
—
|
|
|
—
|
|
||||||||
Sales of Purchased Oil and Gas
|
66
|
|
|
24
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
42
|
|
|
—
|
|
|
—
|
|
||||||||
Intersegment Revenues
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
85
|
|
|
(85
|
)
|
|
—
|
|
||||||||
Total Revenues
|
1,230
|
|
|
894
|
|
|
113
|
|
|
153
|
|
|
—
|
|
|
155
|
|
|
(85
|
)
|
|
—
|
|
||||||||
Lease Operating Expense
|
132
|
|
|
114
|
|
|
5
|
|
|
19
|
|
|
—
|
|
|
—
|
|
|
(6
|
)
|
|
—
|
|
||||||||
Production and Ad Valorem Taxes
|
50
|
|
|
48
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
—
|
|
||||||||
Gathering, Transportation and Processing Expense
|
100
|
|
|
133
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
22
|
|
|
(55
|
)
|
|
—
|
|
||||||||
Other Royalty Expense
|
10
|
|
|
10
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Total Production Expense
|
292
|
|
|
305
|
|
|
5
|
|
|
19
|
|
|
—
|
|
|
24
|
|
|
(61
|
)
|
|
—
|
|
||||||||
DD&A
|
465
|
|
|
394
|
|
|
15
|
|
|
26
|
|
|
—
|
|
|
22
|
|
|
(4
|
)
|
|
12
|
|
||||||||
Loss (Gain) on Divestitures
|
(78
|
)
|
|
21
|
|
|
10
|
|
|
—
|
|
|
—
|
|
|
(109
|
)
|
|
—
|
|
|
—
|
|
Purchased Oil and Gas
|
71
|
|
|
31
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
40
|
|
|
—
|
|
|
—
|
|
||||||||
Loss on Commodity Derivative Instruments
|
249
|
|
|
196
|
|
|
—
|
|
|
53
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
(Loss) Income Before Income Taxes
|
10
|
|
|
(90
|
)
|
|
62
|
|
|
48
|
|
|
(13
|
)
|
|
175
|
|
|
(18
|
)
|
|
(154
|
)
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Three Months Ended June 30, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Crude Oil Sales
|
$
|
557
|
|
|
$
|
458
|
|
|
$
|
1
|
|
|
$
|
98
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
NGL Sales
|
108
|
|
|
108
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Natural Gas Sales
|
352
|
|
|
214
|
|
|
132
|
|
|
6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Total Crude Oil, NGL and Natural Gas Sales
|
1,017
|
|
|
780
|
|
|
133
|
|
|
104
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Income from Equity Method Investees and Other
|
42
|
|
|
—
|
|
|
—
|
|
|
25
|
|
|
—
|
|
|
17
|
|
|
—
|
|
|
—
|
|
||||||||
Intersegment Revenues
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
69
|
|
|
(69
|
)
|
|
—
|
|
||||||||
Total Revenues
|
1,059
|
|
|
780
|
|
|
133
|
|
|
129
|
|
|
—
|
|
|
86
|
|
|
(69
|
)
|
|
—
|
|
||||||||
Lease Operating Expense
|
124
|
|
|
105
|
|
|
6
|
|
|
18
|
|
|
—
|
|
|
—
|
|
|
(5
|
)
|
|
—
|
|
||||||||
Production and Ad Valorem Taxes
|
32
|
|
|
32
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Gathering, Transportation and Processing Expense
|
121
|
|
|
142
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
17
|
|
|
(38
|
)
|
|
—
|
|
||||||||
Other Royalty Expense
|
6
|
|
|
6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Total Production Expense
|
283
|
|
|
285
|
|
|
6
|
|
|
18
|
|
|
—
|
|
|
17
|
|
|
(43
|
)
|
|
—
|
|
||||||||
DD&A
|
503
|
|
|
427
|
|
|
19
|
|
|
39
|
|
|
1
|
|
|
5
|
|
|
—
|
|
|
12
|
|
||||||||
Loss on Marcellus Shale Upstream Divestiture
|
2,322
|
|
|
2,322
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Loss on Commodity Derivative Instruments
|
(57
|
)
|
|
(51
|
)
|
|
—
|
|
|
(6
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
(Loss) Income Before Income Taxes
|
(2,334
|
)
|
|
(2,319
|
)
|
|
106
|
|
|
72
|
|
|
(4
|
)
|
|
58
|
|
|
(13
|
)
|
|
(234
|
)
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Six Months Ended June 30, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Crude Oil Sales
|
$
|
1,522
|
|
|
$
|
1,317
|
|
|
$
|
4
|
|
|
$
|
201
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
NGL Sales
|
283
|
|
|
283
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Natural Gas Sales
|
468
|
|
|
218
|
|
|
240
|
|
|
10
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Total Crude Oil, NGL and Natural Gas Sales
|
2,273
|
|
|
1,818
|
|
|
244
|
|
|
211
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Income from Equity Method Investees and Other
|
124
|
|
|
—
|
|
|
—
|
|
|
71
|
|
|
—
|
|
|
53
|
|
|
—
|
|
|
—
|
|
||||||||
Sales of Purchased Oil and Gas
|
119
|
|
|
55
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
64
|
|
|
—
|
|
|
—
|
|
||||||||
Intersegment Revenues
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
166
|
|
|
(166
|
)
|
|
—
|
|
||||||||
Total Revenues
|
2,516
|
|
|
1,873
|
|
|
244
|
|
|
282
|
|
|
—
|
|
|
283
|
|
|
(166
|
)
|
|
—
|
|
||||||||
Lease Operating Expense
|
287
|
|
|
240
|
|
|
12
|
|
|
41
|
|
|
—
|
|
|
—
|
|
|
(6
|
)
|
|
—
|
|
||||||||
Production and Ad Valorem Taxes
|
104
|
|
|
101
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
—
|
|
|
—
|
|
||||||||
Gathering, Transportation and Processing Expense
|
195
|
|
|
260
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
43
|
|
|
(108
|
)
|
|
—
|
|
||||||||
Other Royalty Expense
|
27
|
|
|
27
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Total Production Expense
|
613
|
|
|
628
|
|
|
12
|
|
|
41
|
|
|
—
|
|
|
46
|
|
|
(114
|
)
|
|
—
|
|
||||||||
DD&A
|
933
|
|
|
800
|
|
|
28
|
|
|
52
|
|
|
—
|
|
|
38
|
|
|
(8
|
)
|
|
23
|
|
||||||||
Gain on Divestitures
|
(666
|
)
|
|
15
|
|
|
(376
|
)
|
|
—
|
|
|
—
|
|
|
(305
|
)
|
|
—
|
|
|
—
|
|
Asset Impairments
|
168
|
|
|
168
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Purchased Oil and Gas
|
128
|
|
|
67
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
61
|
|
|
—
|
|
|
—
|
|
||||||||
Loss on Commodity Derivative Instruments
|
328
|
|
|
260
|
|
|
—
|
|
|
68
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Income (Loss) Before Income Taxes
|
553
|
|
|
(127
|
)
|
|
535
|
|
|
112
|
|
|
(27
|
)
|
|
428
|
|
|
(40
|
)
|
|
(328
|
)
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Six Months Ended June 30, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Crude Oil Sales
|
$
|
1,084
|
|
|
$
|
897
|
|
|
$
|
2
|
|
|
$
|
185
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
NGL Sales
|
213
|
|
|
213
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Natural Gas Sales
|
714
|
|
|
440
|
|
|
263
|
|
|
11
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Total Crude Oil, NGL and Natural Gas Sales
|
2,011
|
|
|
1,550
|
|
|
265
|
|
|
196
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Income from Equity Method Investees and Other
|
84
|
|
|
—
|
|
|
—
|
|
|
52
|
|
|
—
|
|
|
32
|
|
|
—
|
|
|
—
|
|
||||||||
Intersegment Revenues
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
127
|
|
|
(127
|
)
|
|
—
|
|
||||||||
Total Revenues
|
2,095
|
|
|
1,550
|
|
|
265
|
|
|
248
|
|
|
—
|
|
|
159
|
|
|
(127
|
)
|
|
—
|
|
||||||||
Lease Operating Expense
|
263
|
|
|
211
|
|
|
14
|
|
|
40
|
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
—
|
|
||||||||
Production and Ad Valorem Taxes
|
73
|
|
|
72
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
||||||||
Gathering, Transportation and Processing Expense
|
240
|
|
|
280
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
32
|
|
|
(72
|
)
|
|
—
|
|
||||||||
Other Royalty Expense
|
10
|
|
|
10
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Total Production Expense
|
586
|
|
|
573
|
|
|
14
|
|
|
40
|
|
|
—
|
|
|
33
|
|
|
(74
|
)
|
|
—
|
|
||||||||
DD&A
|
1,031
|
|
|
886
|
|
|
37
|
|
|
74
|
|
|
2
|
|
|
10
|
|
|
—
|
|
|
22
|
|
||||||||
Loss on Marcellus Shale Upstream Divestiture
|
2,322
|
|
|
2,322
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Gain on Commodity Derivative Instruments
|
(167
|
)
|
|
(154
|
)
|
|
—
|
|
|
(13
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Income (Loss) Before Income Taxes
|
(2,275
|
)
|
|
(2,251
|
)
|
|
207
|
|
|
138
|
|
|
(11
|
)
|
|
107
|
|
|
(35
|
)
|
|
(430
|
)
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
June 30, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Goodwill (2)
|
$
|
1,402
|
|
|
$
|
1,291
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
111
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Total Assets
|
21,854
|
|
|
15,138
|
|
|
2,996
|
|
|
1,275
|
|
|
62
|
|
|
2,280
|
|
|
(140
|
)
|
|
243
|
|
||||||||
December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Goodwill (2)
|
1,310
|
|
|
1,310
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Total Assets
|
21,476
|
|
|
15,767
|
|
|
2,846
|
|
|
1,308
|
|
|
114
|
|
|
1,357
|
|
|
(163
|
)
|
|
247
|
|
•
|
•
|
•
|
•
|
•
|
•
|
•
|
commodity prices which, if subject to a significant decline, could result in certain existing production becoming uneconomic;
|
•
|
overall level and timing of capital expenditures which, as discussed below and dependent upon our drilling success, will impact near-term production volumes;
|
•
|
increased industry drilling activity in the basins in which we operate, which may cause US onshore cost inflation pressure and result in certain current production becoming less profitable or uneconomic;
|
•
|
Israeli industrial and residential demand for electricity, which is largely impacted by weather conditions and conversion of the Israeli electricity portfolio from coal to natural gas;
|
•
|
timing of crude oil and condensate liftings impacting sales volumes in West Africa;
|
•
|
natural field decline in the US onshore and offshore Equatorial Guinea;
|
•
|
additional purchases of producing properties or divestments of operating assets;
|
•
|
potential weather-related volume curtailments (e.g., due to winter storms and flooding) impacting US onshore operations;
|
•
|
availability or reliability of supplier materials and services, including access to support equipment and/or facilities which may cause delays in operations;
|
•
|
availability of, or curtailments imposed by, third party processing facilities, which could result in capacity constraints, and interruptions in midstream processing, which may cause production and sales volumes impacts;
|
•
|
occurrence of pipeline disruptions, which may cause delays, restrictions or interruptions in production and/or midstream processing;
|
•
|
access to transportation and takeaway pipelines for increasing US onshore production volumes, such as in the Delaware Basin, which may cause infield bottlenecks and/or widening of location-basis differentials;
|
•
|
malfunctions and/or mechanical failures at terminals or other US onshore delivery points;
|
•
|
impact of enhanced completion efforts for US onshore assets;
|
•
|
potential growth from participation in future, or decline from existing, non-operated wells;
|
•
|
abandonment of low-margin US onshore wells;
|
•
|
shut-in of US producing properties if storage capacity becomes unavailable; and
|
•
|
potential drilling and/or completion permit delays due to future regulatory changes.
|
•
|
commodity prices, including price realizations on specific crude oil, natural gas and NGL production;
|
•
|
operating and development costs;
|
•
|
production, drilling and delivery commitments, or other contractual obligations;
|
•
|
access and availability of gathering, transportation, takeaway and processing capacity for US onshore production volumes;
|
•
|
drilling results;
|
•
|
property acquisitions and divestitures;
|
•
|
exploration activity;
|
•
|
cash flows from operations;
|
•
|
indebtedness levels;
|
•
|
availability of financing or other sources of funding;
|
•
|
impact of new laws and regulations on our business practices, including potential legislative or regulatory changes regarding the use of hydraulic fracturing; and
|
•
|
potential changes in the fiscal regimes of the US and other countries in which we operate.
|
•
|
total average daily sales volumes of 346 MBoe/d, net;
|
•
|
record average daily sales volumes for US onshore crude oil of 105 MBbl/d, net;
|
•
|
record average daily sales volumes of over 1 Bcf/d, gross, in Israel, primarily from the Tamar field;
|
•
|
closed the Gulf of Mexico asset divestiture; and
|
•
|
executed Heads of Agreement regarding framework for development of natural gas from the Alen field, offshore Equatorial Guinea.
|
•
|
net cash proceeds of $383 million, after closing adjustments, received from the Gulf of Mexico asset sale;
|
•
|
total loss of $249 million on commodity derivative instruments;
|
•
|
pre-tax income of $7 million, as compared with pre-tax loss of $2.1 billion for second quarter 2017; and
|
•
|
capital expenditures, excluding acquisitions, of $787 million, as compared with $613 million for second quarter 2017.
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
(millions)
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Oil, NGL and Gas Sales to Third Parties (1)
|
$
|
1,100
|
|
|
$
|
1,017
|
|
|
$
|
2,273
|
|
|
$
|
2,011
|
|
Sales of Purchased Gas (2)
|
24
|
|
|
—
|
|
|
55
|
|
|
—
|
|
||||
Income from Equity Method Investees
|
36
|
|
|
25
|
|
|
71
|
|
|
52
|
|
||||
Total Revenues
|
1,160
|
|
|
1,042
|
|
|
2,399
|
|
|
2,063
|
|
||||
Production Expense (1)
|
329
|
|
|
309
|
|
|
681
|
|
|
627
|
|
||||
Exploration Expense
|
29
|
|
|
30
|
|
|
64
|
|
|
72
|
|
||||
Depreciation, Depletion and Amortization
|
435
|
|
|
486
|
|
|
880
|
|
|
999
|
|
||||
Purchases of Gas (2)
|
31
|
|
|
—
|
|
|
67
|
|
|
—
|
|
||||
Loss on Marcellus Shale Upstream Divestiture
|
—
|
|
|
2,322
|
|
|
—
|
|
|
2,322
|
|
||||
(Loss) Gain on Divestitures (3)
|
31
|
|
|
—
|
|
|
(361
|
)
|
|
—
|
|
||||
Asset Impairments (3)
|
—
|
|
|
—
|
|
|
168
|
|
|
—
|
|
||||
Loss (Gain) on Commodity Derivative Instruments
|
249
|
|
|
(57
|
)
|
|
328
|
|
|
(167
|
)
|
||||
Clayton Williams Energy Acquisition Expenses (3)
|
—
|
|
|
90
|
|
|
—
|
|
|
94
|
|
||||
Income (Loss) Before Income Taxes
|
7
|
|
|
(2,145
|
)
|
|
493
|
|
|
(1,917
|
)
|
(1)
|
On January 1, 2018, we adopted ASC 606. As a result of adoption, we changed the presentation of certain US midstream processing arrangements as related to net and gross presentation of revenues and expenses. This presentation change resulted in increases to revenues, and corresponding increases to production expense, of $2 million and $7 million for second quarter and the first six months of 2018, respectively. See Item 1. Financial Statements – Note 2. Basis of Presentation.
|
(2)
|
Beginning in first quarter 2018, as part of our Marcellus Shale firm transportation mitigation efforts, we entered into certain transactions for the purchase of third party natural gas and the subsequent sale of natural gas to other third parties.
|
(3)
|
Amount relates to the Gulf of Mexico asset sale. See Item 1. Financial Statements - Note 3. Acquisitions and Divestitures.
|
|
Sales Volumes (1)
|
|
Average Realized Sales Prices (1)
|
||||||||||||||||||||
|
Crude Oil & Condensate
(MBbl/d)
|
|
NGLs
(MBbl/d)
|
|
Natural
Gas
(MMcf/d)
|
|
Total
(MBoe/d) (2)
|
|
Crude Oil & Condensate
(Per Bbl)
|
|
NGLs
(Per Bbl)
|
|
Natural
Gas
(Per Mcf)
|
||||||||||
Three Months Ended June 30, 2018
|
|||||||||||||||||||||||
United States (3)
|
108
|
|
|
62
|
|
|
467
|
|
|
247
|
|
|
$
|
64.67
|
|
|
$
|
24.46
|
|
|
$
|
2.29
|
|
Eastern Mediterranean
|
—
|
|
|
—
|
|
|
225
|
|
|
38
|
|
|
—
|
|
|
—
|
|
|
5.46
|
|
|||
West Africa (4)
|
17
|
|
|
—
|
|
|
225
|
|
|
54
|
|
|
72.79
|
|
|
—
|
|
|
0.27
|
|
|||
Total Consolidated Operations
|
125
|
|
|
62
|
|
|
917
|
|
|
339
|
|
|
65.77
|
|
|
24.46
|
|
|
2.57
|
|
|||
Equity Investees (5)
|
2
|
|
|
5
|
|
|
—
|
|
|
7
|
|
|
76.07
|
|
|
43.36
|
|
|
—
|
|
|||
Total
|
127
|
|
|
67
|
|
|
917
|
|
|
346
|
|
|
$
|
65.93
|
|
|
$
|
25.90
|
|
|
$
|
2.57
|
|
Three Months Ended June 30, 2017
|
|||||||||||||||||||||||
United States
|
110
|
|
|
63
|
|
|
736
|
|
|
296
|
|
|
$
|
45.78
|
|
|
$
|
18.79
|
|
|
$
|
3.20
|
|
Eastern Mediterranean
|
—
|
|
|
—
|
|
|
272
|
|
|
46
|
|
|
—
|
|
|
—
|
|
|
5.34
|
|
|||
West Africa (4)
|
22
|
|
|
—
|
|
|
231
|
|
|
60
|
|
|
49.53
|
|
|
—
|
|
|
0.27
|
|
|||
Total Consolidated Operations
|
132
|
|
|
63
|
|
|
1,239
|
|
|
402
|
|
|
46.40
|
|
|
18.79
|
|
|
3.13
|
|
|||
Equity Investees (5)
|
2
|
|
|
4
|
|
|
—
|
|
|
6
|
|
|
50.93
|
|
|
34.46
|
|
|
—
|
|
|||
Total
|
134
|
|
|
67
|
|
|
1,239
|
|
|
408
|
|
|
$
|
46.49
|
|
|
$
|
19.84
|
|
|
$
|
3.13
|
|
Six Months Ended June 30, 2018
|
|||||||||||||||||||||||
United States (3)
|
115
|
|
|
63
|
|
|
486
|
|
|
259
|
|
|
$
|
63.23
|
|
|
$
|
25.00
|
|
|
$
|
2.47
|
|
Eastern Mediterranean
|
—
|
|
|
—
|
|
|
243
|
|
|
41
|
|
|
—
|
|
|
—
|
|
|
5.47
|
|
|||
West Africa (4)
|
16
|
|
|
—
|
|
|
215
|
|
|
51
|
|
|
70.65
|
|
|
—
|
|
|
0.27
|
|
|||
Total Consolidated Operations
|
131
|
|
|
63
|
|
|
944
|
|
|
351
|
|
|
64.13
|
|
|
25.00
|
|
|
2.74
|
|
|||
Equity Investees (5)
|
2
|
|
|
5
|
|
|
—
|
|
|
7
|
|
|
71.56
|
|
|
41.61
|
|
|
—
|
|
|||
Total
|
133
|
|
|
68
|
|
|
944
|
|
|
358
|
|
|
$
|
64.22
|
|
|
$
|
26.27
|
|
|
$
|
2.74
|
|
Six Months Ended June 30, 2017
|
|||||||||||||||||||||||
United States
|
105
|
|
|
56
|
|
|
733
|
|
|
283
|
|
|
$
|
47.31
|
|
|
$
|
21.04
|
|
|
$
|
3.32
|
|
Eastern Mediterranean
|
—
|
|
|
—
|
|
|
272
|
|
|
46
|
|
|
—
|
|
|
—
|
|
|
5.33
|
|
|||
West Africa (4)
|
20
|
|
|
—
|
|
|
237
|
|
|
59
|
|
|
51.28
|
|
|
—
|
|
|
0.27
|
|
|||
Total Consolidated Operations
|
125
|
|
|
56
|
|
|
1,242
|
|
|
388
|
|
|
47.95
|
|
|
21.04
|
|
|
3.18
|
|
|||
Equity Investees (5)
|
2
|
|
|
5
|
|
|
—
|
|
|
7
|
|
|
51.71
|
|
|
35.38
|
|
|
—
|
|
|||
Total
|
127
|
|
|
61
|
|
|
1,242
|
|
|
395
|
|
|
$
|
48.01
|
|
|
$
|
22.29
|
|
|
$
|
3.18
|
|
(1)
|
On January 1, 2018, we adopted ASC 606. As a result of adoption, we changed the presentation of certain US midstream processing arrangements as related to net and gross presentation of revenues and expenses. See Item 1. Financial Statements – Note 2. Basis of Presentation. This presentation change resulted in the following:
|
◦
|
increases in NGL revenues, and corresponding increases in production expense, of $4 million and $9 million for second quarter 2018 and the first six months of 2018, respectively;
|
◦
|
decreases in natural gas revenues, and corresponding decreases in production expense, of $2 million for both second quarter 2018 and the first six months of 2018;
|
◦
|
increases in NGL and natural gas sales volumes of 5 MBbl/d and 31 MMcf/d, respectively, for both second quarter 2018 and the first six months of 2018, respectively; and
|
◦
|
reductions in average realized NGL and natural gas sales prices of $1.31/Bbl and $0.11/Mcf, respectively, for second quarter 2018 and $1.09/Bbl and $0.10/Mcf, respectively, for the first six months of 2018.
|
(2)
|
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 prices for a barrel of crude oil equivalent for US natural gas and NGLs are significantly less than the price for a barrel of crude oil. In Israel, we sell natural gas under contracts where the majority of the price is fixed, resulting in less commodity price disparity between reporting periods.
|
(3)
|
Includes 3 MBoe/d and 14 MBoe/d for second quarter and the first six months of 2018, respectively, related to Gulf of Mexico assets sold in April 2018. See Item Financial Statements – Note 3. Acquisitions and Divestitures.
|
(4)
|
Natural gas from the Alba field in Equatorial Guinea is sold under contract for $0.25 per MMBtu to a methanol plant, an LPG plant, an LNG plant and a power generation plant. The methanol and LPG plants are owned by affiliated entities accounted for under the equity method of accounting.
|
(5)
|
Volumes represent sales of condensate and LPG from the LPG plant in Equatorial Guinea. See Income from Equity Method Investees, below.
|
|
Sales Revenues
|
||||||||||||||
(millions)
|
Crude Oil & Condensate
|
|
NGLs
|
|
Natural
Gas
|
|
Total
|
||||||||
Three Months Ended June 30, 2017
|
$
|
557
|
|
|
$
|
108
|
|
|
$
|
352
|
|
|
$
|
1,017
|
|
Changes due to
|
|
|
|
|
|
|
|
||||||||
Decrease in Sales Volumes
|
(31
|
)
|
|
(10
|
)
|
|
(107
|
)
|
|
(148
|
)
|
||||
Increase (Decrease) in Sales Prices (1)
|
223
|
|
|
35
|
|
|
(29
|
)
|
|
229
|
|
||||
Impact of ASC 606 Adoption
|
—
|
|
|
4
|
|
|
(2
|
)
|
|
2
|
|
||||
Three Months Ended June 30, 2018
|
$
|
749
|
|
|
$
|
137
|
|
|
$
|
214
|
|
|
$
|
1,100
|
|
|
|
|
|
|
|
|
|
||||||||
Six Months Ended June 30, 2017
|
$
|
1,084
|
|
|
$
|
213
|
|
|
$
|
714
|
|
|
$
|
2,011
|
|
Changes due to
|
|
|
|
|
|
|
|
||||||||
Increase (Decrease) in Sales Volumes
|
49
|
|
|
1
|
|
|
(192
|
)
|
|
(142
|
)
|
||||
Increase (Decrease) in Sales Prices (1)
|
389
|
|
|
60
|
|
|
(52
|
)
|
|
397
|
|
||||
Impact of ASC 606 Adoption
|
—
|
|
|
9
|
|
|
(2
|
)
|
|
7
|
|
||||
Six Months Ended June 30, 2018
|
$
|
1,522
|
|
|
$
|
283
|
|
|
$
|
468
|
|
|
$
|
2,273
|
|
•
|
increases of 42% and 34% for second quarter and the first six months of 2018, respectively, in average realized prices due to the partial rebalancing of global supply and demand factors; and
|
•
|
higher US onshore sales volumes of 17 MBbl/d and 22 MBbl/d for second quarter and the first six months of 2018, respectively, primarily driven by an increase in development activity in the Delaware Basin and DJ Basin and the Clayton Williams Energy acquisition;
|
•
|
lower Gulf of Mexico sales volumes of 19 MBbl/d and 12 MBbl/d for second quarter and the first six months of 2018, respectively, due to natural field decline as well as the sale of the Gulf of Mexico assets in April 2018; and
|
•
|
lower offshore Equatorial Guinea sales volumes of 5 MBbl/d and 4 MBbl/d for second quarter and the first six months of 2018, respectively, due to natural field decline.
|
•
|
higher US onshore sales volumes of 4 MBbl/d (exclusive of 5 MBbl/d from adoption of ASC 606) and 13 MBbl/d (exclusive of 5 MBbl/d from adoption of ASC 606) for second quarter and the first six months of 2018, respectively, primarily attributable to development activities in the southern area of Gates Ranch in the Eagle Ford Shale;
|
•
|
increases of 37% and 24% in average realized prices for second quarter and the first six months of 2018, respectively, due to the partial rebalancing of domestic supply and demand factors; and
|
•
|
increases of $4 million and $9 million for second quarter and the first six months of 2018, respectively, associated with the adoption of ASC 606;
|
•
|
lower sales volumes of 9 MBbl/d for second quarter and the first six months of 2018, due to the divestiture of the Marcellus Shale upstream assets in second quarter 2017.
|
•
|
lower sales volumes of 331 MMcf/d and 350 MMcf/d for second quarter and the first six months of 2018, respectively, due to the divestiture of the Marcellus Shale upstream assets in second quarter 2017;
|
•
|
lower sales volumes in Israel due to the sale of a 7.5% interest in the Tamar field;
|
•
|
lower Gulf of Mexico sales volume of 14 MMcf/d and 8 MMcf/d for the second quarter and the first six months of 2018, respectively, due to natural field decline as well as the sale of the Gulf of Mexico assets in April 2018;
|
•
|
lower sales volumes of 6 MMcf/d and 21 MMcf/d for second quarter and the first six months of 2018, respectively, from the Alba field, offshore Equatorial Guinea, due to natural field decline and timing of field maintenance; and
|
•
|
decreases of 14% and 10% in average realized prices for second quarter and the first six months of 2018, respectively, due to the impact of increased onshore US supply, as well as wider summer price differentials for both DJ and Delaware Basin volumes;
|
•
|
higher US onshore sales volumes of 53 MMcf/d (exclusive of 31 MMcf/d from adoption of ASC 606) and 89 MMcf/d (exclusive of 31 MMcf/d from adoption of ASC 606) the second quarter and the first six months of 2018, respectively, primarily attributable to development activities in the DJ Basin and the southern area of Gates Ranch in the Eagle Ford Shale; and
|
•
|
higher sales volumes in Israel due to increased demand.
|
(millions, except unit rate)
|
Total per BOE (1) (2)
|
|
Total
|
|
United
States (2)
|
|
Eastern
Mediter- ranean |
|
West Africa
|
||||||||||
Three Months Ended June 30, 2018
|
|
|
|
|
|
|
|
|
|
||||||||||
Lease Operating Expense (3)
|
$
|
4.47
|
|
|
$
|
138
|
|
|
$
|
114
|
|
|
$
|
5
|
|
|
$
|
19
|
|
Production and Ad Valorem Taxes
|
1.56
|
|
|
48
|
|
|
48
|
|
|
—
|
|
|
—
|
|
|||||
Gathering, Transportation and Processing (4)
|
4.31
|
|
|
133
|
|
|
133
|
|
|
—
|
|
|
—
|
|
|||||
Other Royalty Expense
|
0.33
|
|
|
10
|
|
|
10
|
|
|
—
|
|
|
—
|
|
|||||
Total Production Expense
|
$
|
10.67
|
|
|
$
|
329
|
|
|
$
|
305
|
|
|
$
|
5
|
|
|
$
|
19
|
|
Total Production Expense per BOE
|
|
|
$
|
10.67
|
|
|
$
|
13.55
|
|
|
$
|
1.47
|
|
|
$
|
3.84
|
|
||
Three Months Ended June 30, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Lease Operating Expense (3)
|
$
|
3.54
|
|
|
$
|
129
|
|
|
$
|
105
|
|
|
$
|
6
|
|
|
$
|
18
|
|
Production and Ad Valorem Taxes
|
0.89
|
|
|
32
|
|
|
32
|
|
|
—
|
|
|
—
|
|
|||||
Gathering, Transportation and Processing (4)
|
3.89
|
|
|
142
|
|
|
142
|
|
|
—
|
|
|
—
|
|
|||||
Other Royalty Expense
|
0.16
|
|
|
6
|
|
|
6
|
|
|
—
|
|
|
—
|
|
|||||
Total Production Expense
|
$
|
8.48
|
|
|
$
|
309
|
|
|
$
|
285
|
|
|
$
|
6
|
|
|
$
|
18
|
|
Total Production Expense per BOE
|
|
|
$
|
8.48
|
|
|
$
|
10.60
|
|
|
$
|
1.46
|
|
|
$
|
3.28
|
|
||
Six Months Ended June 30, 2018
|
|
|
|
|
|
|
|
|
|
||||||||||
Lease Operating Expense (3)
|
$
|
4.62
|
|
|
$
|
293
|
|
|
$
|
240
|
|
|
$
|
12
|
|
|
$
|
41
|
|
Production and Ad Valorem Taxes
|
1.59
|
|
|
101
|
|
|
101
|
|
|
—
|
|
|
—
|
|
|||||
Gathering, Transportation and Processing (4)
|
4.10
|
|
|
260
|
|
|
260
|
|
|
—
|
|
|
—
|
|
|||||
Other Royalty Expense
|
0.43
|
|
|
27
|
|
|
27
|
|
|
—
|
|
|
—
|
|
|||||
Total Production Expense
|
$
|
10.74
|
|
|
$
|
681
|
|
|
$
|
628
|
|
|
$
|
12
|
|
|
$
|
41
|
|
Total Production Expense per BOE
|
|
|
$
|
10.74
|
|
|
$
|
13.42
|
|
|
$
|
1.64
|
|
|
$
|
4.39
|
|
||
Six Months Ended June 30, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Lease Operating Expense (3)
|
$
|
3.78
|
|
|
$
|
265
|
|
|
$
|
211
|
|
|
$
|
14
|
|
|
$
|
40
|
|
Production and Ad Valorem Taxes
|
1.03
|
|
|
72
|
|
|
72
|
|
|
—
|
|
|
—
|
|
|||||
Gathering, Transportation and Processing (4)
|
3.99
|
|
|
280
|
|
|
280
|
|
|
—
|
|
|
—
|
|
|||||
Other Royalty Expense
|
0.14
|
|
|
10
|
|
|
10
|
|
|
—
|
|
|
—
|
|
|||||
Total Production Expense
|
$
|
8.94
|
|
|
$
|
627
|
|
|
$
|
573
|
|
|
$
|
14
|
|
|
$
|
40
|
|
Total Production Expense per BOE
|
|
|
$
|
8.94
|
|
|
$
|
11.20
|
|
|
$
|
1.71
|
|
|
$
|
3.72
|
|
(1)
|
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.
|
(2)
|
United States E&P production expense includes charges from our midstream operations that are eliminated on a consolidated basis. See Item 1. Financial Statements – Note 11. 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)
|
Upon adoption of ASC 606 on January 1, 2018, we changed the presentation for certain of our gathering, transportation and processing expenses in accordance with the control model under the new standard. As such, we reflected increases of $2 million and $7 million to gathering, transportation and processing expense related to US operations for second quarter and the first six months of 2018, respectively. On a per BOE basis, including the increase in production volumes, the presentation change resulted in decreases of $0.46/Boe and $0.35/Boe for US production expense for the second quarter and the first six months of 2018, respectively. No other geographical locations were affected by the presentation change. Comparative information for the prior period has not been recast and continues to be reported under ASC 605, Revenue Recognition, the accounting standard in effect for the prior period.
|
•
|
an increase in US lease operating expense primarily due to increased development activities resulting in added production in across each of our onshore US basins;
|
•
|
an increase in US production and ad valorem taxes due to higher commodity prices;
|
•
|
an increase in US gathering, transportation and processing expense attributable to development activities in the southern area of Gates Ranch in the Eagle Ford Shale which led to increased sales volumes; and
|
•
|
an increase in US other royalty expense due to increased commodity market prices;
|
•
|
a decrease in first quarter 2018 in US lease operating expense in the Gulf of Mexico due to lower production caused by natural field decline and the subsequent sale of the assets in second quarter 2018; and
|
•
|
decreases in US lease operating and gathering, transportation and processing expenses due to the divestiture of the Marcellus Shale upstream assets in second quarter 2017.
|
(millions, except unit rate)
|
Total
|
|
United
States |
|
Eastern
Mediter- ranean |
|
West
Africa
|
|
Other Int'l
|
||||||||||
Three Months Ended June 30, 2018
|
|
|
|
|
|
|
|
|
|
||||||||||
DD&A Expense
|
$
|
435
|
|
|
$
|
394
|
|
|
$
|
15
|
|
|
$
|
26
|
|
|
$
|
—
|
|
Unit Rate per BOE (1)
|
$
|
14.10
|
|
|
$
|
17.51
|
|
|
$
|
4.41
|
|
|
$
|
5.25
|
|
|
$
|
—
|
|
Three Months Ended June 30, 2017
|
|
|
|
|
|
|
|
|
|
||||||||||
DD&A Expense
|
$
|
486
|
|
|
$
|
427
|
|
|
$
|
19
|
|
|
$
|
39
|
|
|
$
|
1
|
|
Unit Rate per BOE (1)
|
$
|
13.32
|
|
|
$
|
15.89
|
|
|
$
|
4.62
|
|
|
$
|
7.11
|
|
|
$
|
—
|
|
Six Months Ended June 30, 2018
|
|
|
|
|
|
|
|
|
|
||||||||||
DD&A Expense
|
$
|
880
|
|
|
$
|
800
|
|
|
$
|
28
|
|
|
$
|
52
|
|
|
$
|
—
|
|
Unit Rate per BOE (1)
|
$
|
13.87
|
|
|
$
|
17.10
|
|
|
$
|
3.82
|
|
|
$
|
5.56
|
|
|
$
|
—
|
|
Six Months Ended June 30, 2017
|
|
|
|
|
|
|
|
|
|
||||||||||
DD&A Expense
|
$
|
999
|
|
|
$
|
886
|
|
|
$
|
37
|
|
|
$
|
74
|
|
|
$
|
2
|
|
Unit Rate per BOE (1)
|
$
|
14.25
|
|
|
$
|
17.32
|
|
|
$
|
4.52
|
|
|
$
|
6.88
|
|
|
$
|
—
|
|
(1)
|
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.
|
•
|
year-end reserve additions, primarily in US onshore due to enhanced well design and completion techniques in our horizontal drilling program as well as reserve additions in the Tamar field due to well results and geological evaluation, and globally due to positive commodity price revisions;
|
•
|
the Marcellus Shale upstream divestiture in second quarter 2017, which reduced DD&A expense by $99 million and $118 million for second quarter and the first six months of 2018, respectively;
|
•
|
lower sales volumes in Gulf of Mexico due to natural field decline and classification of the assets as held for sale in first quarter 2018, resulting in the cessation of DD&A expense, together resulting in decreases of $62 million and $109 million for second quarter and the first six months of 2018, respectively; and
|
•
|
reclassification of a 7.5% working interest in the Tamar field, offshore Israel, as asset held for sale at December 31, 2017, resulting in the cessation of DD&A expense and decreases of $3 million and $7 million for second quarter and the first six months of 2018, respectively;
|
•
|
higher sales volumes in the Delaware Basin, which more than doubled, due to increased development activities subsequent to the Clayton Williams Energy Acquisition in second quarter 2017;
|
•
|
increased development activities in the southern area of Gates Ranch in the Eagle Ford Shale; and
|
•
|
higher sales volumes from the Tamar field, offshore Israel, due to higher domestic demand.
|
•
|
net cash settlement payment of $93 million; and
|
•
|
net non-cash increase of $235 million in the fair value of our net commodity derivative liability, primarily driven by increases in the forward commodity price curve for crude oil.
|
•
|
net cash settlement receipt of $14 million; and
|
•
|
net non-cash increase of $153 million in the fair value of our net commodity derivative asset, driven by changes in the forward commodity price curves for both crude oil and natural gas.
|
•
|
commenced gathering services in the Mustang IDP area in the DJ Basin;
|
•
|
completed construction of the Collier and Billy Miner Train II CGFs in the Delaware Basin;
|
•
|
secured long-term dedications, from existing and new third party customers, for the Black Diamond system, a large, integrated gathering system in the DJ Basin acquired in the Saddle Butte acquisition; and
|
•
|
received a third party producer's activity set and development plan for Delaware Basin acreage, with gathering services expected to commence in late 2018.
|
•
|
net proceeds of approximately $135 million received, and gain of $109 million recognized, on the sale of a portion of our investment in CNX Midstream Partners common units;
|
•
|
pre-tax income of $175 million, as compared with pre-tax income of $58 million for second quarter 2017; and
|
•
|
capital expenditures, excluding acquisitions, of $157 million, as compared with $88 million for second quarter 2017.
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
(millions)
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Midstream Services Revenues – Third Party
|
$
|
15
|
|
|
$
|
4
|
|
|
$
|
28
|
|
|
$
|
4
|
|
Sales of Purchased Oil
|
42
|
|
|
—
|
|
|
64
|
|
|
—
|
|
||||
Income from Equity Method Investees
|
13
|
|
|
13
|
|
|
25
|
|
|
28
|
|
||||
Intersegment Revenues
|
85
|
|
|
69
|
|
|
166
|
|
|
127
|
|
||||
Total Revenues
|
155
|
|
|
86
|
|
|
283
|
|
|
159
|
|
||||
Operating Costs and Expenses
|
27
|
|
|
23
|
|
|
61
|
|
|
42
|
|
||||
Depreciation and Amortization
|
22
|
|
|
5
|
|
|
38
|
|
|
10
|
|
||||
Gain on Divestitures
|
(109
|
)
|
|
—
|
|
|
(305
|
)
|
|
—
|
|
||||
Purchased Oil
|
40
|
|
|
—
|
|
|
61
|
|
|
—
|
|
||||
Total (Income) Expense
|
(20
|
)
|
|
28
|
|
|
(145
|
)
|
|
52
|
|
||||
Income Before Income Taxes
|
$
|
175
|
|
|
$
|
58
|
|
|
$
|
428
|
|
|
$
|
107
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
(millions, except unit rate)
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
G&A Expense
|
$
|
105
|
|
|
$
|
103
|
|
|
$
|
209
|
|
|
$
|
202
|
|
Unit Rate per BOE (1)
|
$
|
3.40
|
|
|
$
|
2.82
|
|
|
$
|
3.29
|
|
|
$
|
2.88
|
|
(1)
|
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
(millions, except unit rate)
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Interest Expense, Gross
|
$
|
91
|
|
|
$
|
107
|
|
|
$
|
181
|
|
|
$
|
206
|
|
Capitalized Interest
|
(18
|
)
|
|
(11
|
)
|
|
(35
|
)
|
|
(23
|
)
|
||||
Interest Expense, Net
|
$
|
73
|
|
|
$
|
96
|
|
|
$
|
146
|
|
|
$
|
183
|
|
Unit Rate per BOE (1)
|
$
|
2.37
|
|
|
$
|
2.63
|
|
|
$
|
2.30
|
|
|
$
|
2.61
|
|
(1)
|
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.
|
•
|
redemption of $379 million in outstanding senior notes;
|
•
|
acquisition of 1.8 million shares of Noble Energy stock, for $63 million, resulting in year to date repurchases of 4.0 million shares for $130 million, pursuant to the Board of Directors' authorized $750 million share repurchase program; and
|
•
|
announcement in July 2018 of an August 2018 dividend of 11 cents per common share, which continues the 10% increase over 2017.
|
•
|
repaid all amounts outstanding under the Revolving Credit Facility;
|
•
|
extended the Revolving Credit Facility maturity date by two and a half years to March 2023;
|
•
|
amended the Noble Midstream Services Revolving Credit Facility to increase the capacity from $350 million to $800 million; and
|
•
|
extended the maturity date of the Noble Midstream Services Revolving Credit Facility by one and a half years to March 2023.
|
|
June 30,
|
|
December 31,
|
||||
(millions, except percentages)
|
2018
|
|
2017
|
||||
Total Cash (1)
|
$
|
621
|
|
|
$
|
713
|
|
Amount Available to be Borrowed Under Revolving Credit Facility (2)
|
4,000
|
|
|
3,770
|
|
||
Total Liquidity
|
$
|
4,621
|
|
|
$
|
4,483
|
|
Total Debt (3)
|
$
|
6,663
|
|
|
$
|
6,859
|
|
Noble Energy Share of Equity
|
10,252
|
|
|
9,936
|
|
||
Ratio of Debt-to-Book Capital (4)
|
39
|
%
|
|
41
|
%
|
(1)
|
As of June 30, 2018, total cash included cash and cash equivalents of $15 million related to Noble Midstream Partners. As of December 31, 2017, total cash included $18 million cash of Noble Midstream Partners and $38 million restricted cash related to the Saddle Butte acquisition that closed first quarter 2018.
|
(2)
|
Excludes amounts available to be borrowed under the Noble Midstream Services Revolving Credit Facility and Leviathan Term Loan Facility, which are not available to Noble Energy for general corporate purposes. See discussion below.
|
(3)
|
Total debt includes capital lease obligations and excludes unamortized debt discount/premium. See Item 1. Financial Statements – Note 5. Debt.
|
(4)
|
We define our ratio of debt-to-book capital as total debt (which includes long-term debt excluding unamortized discount, 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.
|
|
Six Months Ended June 30,
|
||||||
(millions)
|
2018
|
|
2017
|
||||
Total Cash Provided By (Used in)
|
|
|
|
||||
Operating Activities
|
$
|
1,079
|
|
|
$
|
877
|
|
Investing Activities
|
(1,050
|
)
|
|
(1,121
|
)
|
||
Financing Activities
|
(121
|
)
|
|
(426
|
)
|
||
Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash
|
$
|
(92
|
)
|
|
$
|
(670
|
)
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
(millions)
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Acquisition, Capital and Exploration Expenditures
|
|
|
|
|
|
|
|
|
|
|
|
||||
Unproved Property Acquisition (1)
|
$
|
—
|
|
|
$
|
1,581
|
|
|
$
|
—
|
|
|
$
|
1,826
|
|
Proved Property Acquisition (2)
|
—
|
|
|
782
|
|
|
—
|
|
|
840
|
|
||||
Exploration and Development
|
771
|
|
|
605
|
|
|
1,427
|
|
|
1,199
|
|
||||
Midstream (3)
|
157
|
|
|
152
|
|
|
616
|
|
|
245
|
|
||||
Corporate and Other
|
16
|
|
|
10
|
|
|
27
|
|
|
15
|
|
||||
Total
|
$
|
944
|
|
|
$
|
3,130
|
|
|
$
|
2,070
|
|
|
$
|
4,125
|
|
Investment in Equity Method Investee (4)
|
$
|
—
|
|
|
$
|
67
|
|
|
$
|
—
|
|
|
$
|
67
|
|
•
|
our growth strategies;
|
•
|
our future results of operations;
|
•
|
our liquidity and ability to finance our exploration, development and acquisitions activities;
|
•
|
our ability to satisfy contractual commitments, including utilization or commercialization of firm transportation commitments in the Marcellus Shale;
|
•
|
our ability to make and integrate acquisitions;
|
•
|
our ability to successfully and economically explore for and develop crude oil, natural gas and NGL resources;
|
•
|
anticipated trends in our business;
|
•
|
market conditions in the oil and gas industry;
|
•
|
the impact of governmental fiscal regulation, including federal, state, local, and foreign host regulations, and/or terms, such as those involving the protection of the environment or marketing of production, as well as other regulations; and
|
•
|
access to resources.
|
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)
|
||||||
4/1/2018 - 4/30/2018
|
216
|
|
|
$
|
31.72
|
|
|
—
|
|
|
|
||
5/1/2018 - 5/31/2018
|
837,995
|
|
|
32.84
|
|
|
837,418
|
|
|
|
|||
6/1/2018 - 6/30/2018
|
941,779
|
|
|
35.65
|
|
|
941,502
|
|
|
|
|||
Total
|
1,779,990
|
|
|
$
|
34.33
|
|
|
1,778,920
|
|
|
$
|
620
|
|
(1)
|
Includes stock repurchases of 1,070 during the period relating to common stock received by us from employees for the payment of withholding taxes due on shares of common stock issued under stock-based compensation plans.
|
(2)
|
During second quarter 2018, we repurchased and retired 1.8 million shares of common stock at an average purchase price of $35.15 per share pursuant to the $750 million share repurchase program, authorized by our Board of Directors, which expires December 31, 2020.
|
|
||
Exhibit Number
|
|
Exhibit*
|
|
|
|
2.1
|
|
|
|
|
|
2.2
|
|
|
|
|
|
2.3
|
|
|
|
|
|
3.1
|
|
|
|
|
|
3.2
|
|
|
|
|
|
3.3
|
|
|
|
|
|
3.4
|
|
|
|
|
|
10.1*
|
|
|
|
|
|
12.1
|
|
|
|
|
|
31.1
|
|
|
|
|
|
31.2
|
|
|
|
|
|
32.1
|
|
|
|
|
|
32.2
|
|
|
|
|
|
101.INS
|
|
Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL 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.
|
|
|
|
|
NOBLE ENERGY, INC.
|
|
|
|
|
(Registrant)
|
|
|
|
|
|
Date
|
|
August 3, 2018
|
|
/s/ Kenneth M. Fisher
|
|
|
|
|
Kenneth M. Fisher
Executive Vice President, Chief Financial Officer
|
Noble Energy, Inc.
|
||||||||||||||||||||||||
Calculation of Ratio of Earnings to Fixed Charges
|
||||||||||||||||||||||||
|
|
Six Months Ended June 30,
|
|
Year Ended December 31,
|
||||||||||||||||||||
|
|
2018
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
||||||||||||
(millions, except ratio amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Income (Loss) From Continuing Operations Before Income Tax, Non-controlling Interests and Income From Equity Investees
|
|
$
|
420
|
|
|
$
|
(2,436
|
)
|
|
$
|
(1,887
|
)
|
|
$
|
(2,309
|
)
|
|
$
|
1,540
|
|
|
$
|
1,138
|
|
Add (Deduct)
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Fixed Charges
|
|
195
|
|
|
426
|
|
|
440
|
|
|
435
|
|
|
349
|
|
|
296
|
|
||||||
Capitalized Interest
|
|
(35
|
)
|
|
(49
|
)
|
|
(84
|
)
|
|
(144
|
)
|
|
(116
|
)
|
|
(121
|
)
|
||||||
Distributed Income From Equity Investees
|
|
85
|
|
|
139
|
|
|
83
|
|
|
77
|
|
|
226
|
|
|
204
|
|
||||||
Earnings (Loss) as Defined
|
|
$
|
665
|
|
|
$
|
(1,920
|
)
|
|
$
|
(1,448
|
)
|
|
$
|
(1,941
|
)
|
|
$
|
1,999
|
|
|
$
|
1,517
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net Interest Expense
|
|
146
|
|
|
354
|
|
|
328
|
|
|
263
|
|
|
210
|
|
|
158
|
|
||||||
Capitalized Interest
|
|
35
|
|
|
49
|
|
|
84
|
|
|
144
|
|
|
116
|
|
|
121
|
|
||||||
Interest Portion of Rental Expense
|
|
14
|
|
|
23
|
|
|
28
|
|
|
28
|
|
|
23
|
|
|
17
|
|
||||||
Fixed Charges as Defined
|
|
$
|
195
|
|
|
$
|
426
|
|
|
$
|
440
|
|
|
$
|
435
|
|
|
$
|
349
|
|
|
$
|
296
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Ratio of Earnings to Fixed Charges
|
|
3.4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5.7
|
|
|
5.1
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Amount by Which Earnings Were Insufficient to Cover Fixed Charges
|
|
$
|
—
|
|
|
$
|
2,346
|
|
|
$
|
1,888
|
|
|
$
|
2,376
|
|
|
$
|
—
|
|
|
$
|
—
|
|
1.
|
I have reviewed this quarterly report on Form 10-Q 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:
|
August 3, 2018
|
|
|
|
|
|
|
/s/ David L. Stover
|
|
||
David L. Stover
|
|
||
Chief Executive Officer
|
|
1.
|
I have reviewed this quarterly report on Form 10-Q 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:
|
August 3, 2018
|
|
|
|
|
|
|
/s/ Kenneth M. Fisher
|
|
||
Kenneth M. Fisher
|
|
||
Chief Financial Officer
|
|
(1)
|
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and
|
(2)
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
Date:
|
August 3, 2018
|
|
/s/ David L. Stover
|
|
|
|
David L. Stover
|
|
|
|
Chief Executive Officer
|
(1)
|
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and
|
(2)
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
Date:
|
August 3, 2018
|
|
/s/ Kenneth M. Fisher
|
|
|
|
Kenneth M. Fisher
|
|
|
|
Chief Financial Officer
|