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Share Name | Share Symbol | Market | Type |
---|---|---|---|
Noble Energy Inc | NYSE:NBL | NYSE | Common Stock |
Price Change | % Change | Share Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
---|---|---|---|---|---|---|---|---|
0.00 | 0.00% | 24.62 | 0 | 01:00:00 |
Delaware
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73-0785597
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(State or other jurisdiction of incorporation or organization)
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(I.R.S. employer identification number)
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1001 Noble Energy Way
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Houston, Texas
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77070
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(Address of principal executive offices)
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(Zip Code)
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(281) 872-3100
(Registrant’s telephone number, including area code)
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Large accelerated filer
x
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Accelerated filer
o
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Non-accelerated filer
o
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Smaller reporting company
o
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Emerging growth company
o
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(Do not check if a smaller reporting company)
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Part I.
Financial Information
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Item 4.
Controls and Procedures
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Item 5.
Other Information
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Three Months Ended March 31,
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||||||
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2018
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2017
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||||
Revenues
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|
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||||
Oil, NGL and Gas Sales
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$
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1,173
|
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$
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994
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Income from Equity Method Investees and Other
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113
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42
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Total
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1,286
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1,036
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Costs and Expenses
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||||
Production Expense
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321
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303
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Exploration Expense
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35
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42
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Depreciation, Depletion and Amortization
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468
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528
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Asset Impairments
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168
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—
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Gain on Divestitures
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(588
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)
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—
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General and Administrative
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104
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99
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Other Operating Expense, Net
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70
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29
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Total
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578
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1,001
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Operating Income
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708
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35
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Other (Income) Expense
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Loss (Gain) on Commodity Derivative Instruments
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79
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(110
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)
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Interest, Net of Amount Capitalized
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73
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87
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Other Non-Operating Expense (Income), Net
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13
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(1
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)
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Total
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165
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(24
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)
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Income Before Income Taxes
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543
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59
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Income Tax (Benefit) Expense
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(31
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)
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12
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Net Income and Comprehensive Income Including Noncontrolling Interests
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574
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47
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Less: Net Income and Comprehensive Income Attributable to Noncontrolling Interests
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20
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11
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Net Income and Comprehensive Income Attributable to Noble Energy
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$
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554
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$
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36
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||||
Net Income Attributable to Noble Energy per Common Share
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Basic
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$
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1.14
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$
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0.08
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Diluted
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$
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1.14
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$
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0.08
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Weighted Average Number of Common Shares Outstanding
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Basic
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487
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431
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Diluted
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488
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434
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March 31,
2018 |
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December 31,
2017 |
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ASSETS
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Current Assets
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Cash and Cash Equivalents
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$
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992
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$
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675
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Accounts Receivable, Net
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707
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748
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Other Current Assets
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895
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780
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Total Current Assets
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2,594
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2,203
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Property, Plant and Equipment
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Oil and Gas Properties (Successful Efforts Method of Accounting)
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27,426
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29,678
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Property, Plant and Equipment, Other
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887
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879
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Total Property, Plant and Equipment, Gross
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28,313
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30,557
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Accumulated Depreciation, Depletion and Amortization
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(10,882
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)
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(13,055
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)
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Total Property, Plant and Equipment, Net
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17,431
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17,502
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Other Noncurrent Assets
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1,021
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461
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Goodwill
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1,402
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1,310
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Total Assets
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$
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22,448
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$
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21,476
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LIABILITIES AND EQUITY
|
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Current Liabilities
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Accounts Payable – Trade
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$
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1,423
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$
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1,161
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Other Current Liabilities
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791
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578
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Total Current Liabilities
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2,214
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1,739
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Long-Term Debt
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6,858
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6,746
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Deferred Income Taxes
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976
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1,127
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Other Noncurrent Liabilities
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1,013
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1,245
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Total Liabilities
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11,061
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10,857
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Commitments and Contingencies
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Shareholders’ Equity
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Preferred Stock - Par Value $1.00 per share; 4 Million Shares Authorized; None Issued
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—
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—
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Common Stock - Par Value $0.01 per share; 1 Billion Shares Authorized; 528 Million and 529 Million Shares Issued, respectively
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5
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5
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Additional Paid in Capital
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8,363
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8,438
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Accumulated Other Comprehensive Loss
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(29
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)
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(30
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)
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Treasury Stock, at Cost; 39 Million Shares
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(731
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)
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(725
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)
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Retained Earnings
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2,754
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2,248
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Noble Energy Share of Equity
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10,362
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9,936
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Noncontrolling Interests
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1,025
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683
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Total Equity
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11,387
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10,619
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Total Liabilities and Equity
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$
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22,448
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$
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21,476
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Three Months Ended March 31,
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||||||
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2018
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2017
|
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Cash Flows From Operating Activities
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Net Income Including Noncontrolling Interests
|
$
|
574
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$
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47
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Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities
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Depreciation, Depletion and Amortization
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468
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528
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Asset Impairments
|
168
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—
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Deferred Income Tax Benefit
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(157
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)
|
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—
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Loss (Gain) on Commodity Derivative Instruments
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79
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(110
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)
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Net Cash (Paid) Received in Settlement of Commodity Derivative Instruments
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(28
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)
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3
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Gain on Divestitures
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(588
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)
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—
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Other Adjustments for Noncash Items Included in Income
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(2
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)
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20
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Changes in Operating Assets and Liabilities
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Decrease in Accounts Receivable
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89
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59
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(Decrease) Increase in Accounts Payable
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(33
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)
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45
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Increase (Decrease) in Current Income Taxes Payable
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14
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(23
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)
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Other Current Assets and Liabilities, Net
|
(18
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)
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(35
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)
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Other Operating Assets and Liabilities, Net
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17
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2
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Net Cash Provided by Operating Activities
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583
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536
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Cash Flows From Investing Activities
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||||
Additions to Property, Plant and Equipment
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(787
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)
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(587
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)
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Acquisitions, Net of Cash Acquired
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(650
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)
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(346
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)
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Proceeds from Sale of 7.5% Interest in Tamar Field
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487
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|
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—
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Proceeds from Sale of CONE Gathering LLC
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308
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|
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—
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Proceeds from Divestitures
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70
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|
40
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Net Cash Used in Investing Activities
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(572
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)
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(893
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)
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Cash Flows From Financing Activities
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Dividends Paid, Common Stock
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(48
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)
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(44
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)
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Purchase and Retirement of Common Stock
|
(67
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)
|
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—
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Proceeds from Noble Midstream Services Revolving Credit Facility
|
405
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|
|
—
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Repayment of Noble Midstream Services Revolving Credit Facility
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(55
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)
|
|
—
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||
Contributions from Noncontrolling Interest and Other
|
333
|
|
|
—
|
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Proceeds from Revolving Credit Facility
|
245
|
|
|
—
|
|
||
Repayment of Revolving Credit Facility
|
(475
|
)
|
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—
|
|
||
Other
|
(40
|
)
|
|
(22
|
)
|
||
Net Cash Provided by (Used in) by Financing Activities
|
298
|
|
|
(66
|
)
|
||
Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash
|
309
|
|
|
(423
|
)
|
||
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period
|
713
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|
1,210
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Cash, Cash Equivalents, and Restricted Cash at End of Period
|
$
|
1,022
|
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$
|
787
|
|
|
Attributable to Noble Energy
|
|
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|
|
||||||||||||||||||||||
|
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
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
554
|
|
|
20
|
|
|
574
|
|
|||||||
Stock-based Compensation
|
—
|
|
|
17
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
17
|
|
|||||||
Dividends (10 cents per share)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(48
|
)
|
|
—
|
|
|
(48
|
)
|
|||||||
Purchase and Retirement of Common Stock
|
—
|
|
|
(67
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(67
|
)
|
|||||||
Clayton Williams Energy Acquisition
|
—
|
|
|
(25
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(25
|
)
|
|||||||
Distributions to Noncontrolling Interest Owners
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(11
|
)
|
|
(11
|
)
|
|||||||
Contributions from Noncontrolling Interest Owners
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
331
|
|
|
331
|
|
|||||||
Other
|
—
|
|
|
—
|
|
|
1
|
|
|
(6
|
)
|
|
—
|
|
|
2
|
|
|
(3
|
)
|
|||||||
March 31, 2018
|
$
|
5
|
|
|
$
|
8,363
|
|
|
$
|
(29
|
)
|
|
$
|
(731
|
)
|
|
$
|
2,754
|
|
|
$
|
1,025
|
|
|
$
|
11,387
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
December 31, 2016
|
$
|
5
|
|
|
$
|
6,450
|
|
|
$
|
(31
|
)
|
|
$
|
(692
|
)
|
|
$
|
3,556
|
|
|
$
|
312
|
|
|
$
|
9,600
|
|
Net Income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
36
|
|
|
11
|
|
|
47
|
|
|||||||
Stock-based Compensation
|
—
|
|
|
13
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
13
|
|
|||||||
Dividends (10 cents per share)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(44
|
)
|
|
—
|
|
|
(44
|
)
|
|||||||
Distributions to Noncontrolling Interest Owners
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6
|
)
|
|
(6
|
)
|
|||||||
Other
|
—
|
|
|
9
|
|
|
—
|
|
|
(11
|
)
|
|
1
|
|
|
—
|
|
|
(1
|
)
|
|||||||
March 31, 2017
|
$
|
5
|
|
|
$
|
6,472
|
|
|
$
|
(31
|
)
|
|
$
|
(703
|
)
|
|
$
|
3,549
|
|
|
$
|
317
|
|
|
$
|
9,609
|
|
(millions)
|
April - Dec 2018
|
2019
|
2020
|
Total
|
||||||||
Natural Gas Revenues
(1)
|
$
|
215
|
|
$
|
137
|
|
$
|
169
|
|
$
|
521
|
|
|
Three Months Ended March 31,
|
||||||
(millions)
|
2018
|
|
2017
|
||||
Income From Equity Method Investees and Other
|
|
|
|
||||
Income from Equity Method Investees
|
$
|
47
|
|
|
$
|
42
|
|
Sales of Purchased Oil and Gas
(1)
|
53
|
|
|
—
|
|
||
Midstream Services Revenues – Third Party
|
13
|
|
|
—
|
|
||
Total
|
$
|
113
|
|
|
$
|
42
|
|
Production Expense
|
|
|
|
||||
Lease Operating Expense
|
$
|
155
|
|
|
$
|
139
|
|
Production and Ad Valorem Taxes
|
54
|
|
|
41
|
|
||
Gathering, Transportation and Processing Expense
|
95
|
|
|
119
|
|
||
Other Royalty Expense
|
17
|
|
|
4
|
|
||
Total
|
$
|
321
|
|
|
$
|
303
|
|
Exploration Expense
|
|
|
|
||||
Leasehold Impairment and Amortization
|
$
|
—
|
|
|
$
|
18
|
|
Seismic, Geological and Geophysical
|
11
|
|
|
5
|
|
||
Staff Expense
|
14
|
|
|
13
|
|
||
Other
|
10
|
|
|
6
|
|
||
Total
|
$
|
35
|
|
|
$
|
42
|
|
Other Operating Expense, Net
|
|
|
|
||||
Marketing Expense
(2)
|
$
|
5
|
|
|
$
|
19
|
|
Purchased Oil and Gas
(1)
|
57
|
|
|
—
|
|
||
Other, Net
|
8
|
|
|
10
|
|
||
Total
|
$
|
70
|
|
|
$
|
29
|
|
Other Non-Operating Expense (Income), Net
|
|
|
|
||||
Loss on Investment in Tamar Petroleum Ltd., Net
(3)
|
$
|
15
|
|
|
$
|
—
|
|
Other
|
(2
|
)
|
|
(1
|
)
|
||
Total
|
$
|
13
|
|
|
$
|
(1
|
)
|
(1)
|
As part of the Midstream 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, in first quarter 2018, as part of our Marcellus Shale upstream 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. The cost to purchase natural gas includes transportation expense incurred of
$5 million
. See
Note
11. Segment Information
.
|
(2)
|
Expense relates to unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments.
|
(3)
|
Amount includes a
$29 million
loss related to the change in fair value, net of
$14 million
of dividend income related to our investment in Tamar Petroleum Ltd. shares.
|
(millions)
|
March 31,
2018 |
|
December 31,
2017 |
||||
Accounts Receivable, Net
|
|
|
|
||||
Commodity Sales
|
$
|
413
|
|
|
$
|
455
|
|
Joint Interest Billings
|
234
|
|
|
207
|
|
||
Other
|
77
|
|
|
103
|
|
||
Allowance for Doubtful Accounts
|
(17
|
)
|
|
(17
|
)
|
||
Total
|
$
|
707
|
|
|
$
|
748
|
|
Other Current Assets
|
|
|
|
|
|
||
Inventories, Materials and Supplies
|
$
|
43
|
|
|
$
|
66
|
|
Inventories, Crude Oil
|
17
|
|
|
16
|
|
||
Assets Held for Sale
(1)
|
751
|
|
|
629
|
|
||
Restricted Cash
(2)
|
30
|
|
|
38
|
|
||
Prepaid Expenses and Other Current Assets
(3)
|
54
|
|
|
31
|
|
||
Total
|
$
|
895
|
|
|
$
|
780
|
|
Other Noncurrent Assets
|
|
|
|
|
|
||
Equity Method Investments
(4)
|
$
|
378
|
|
|
$
|
305
|
|
Customer-Related Intangible Assets
(5)
|
334
|
|
|
—
|
|
||
Investment in Tamar Petroleum Ltd.
(6)
|
162
|
|
|
—
|
|
||
Mutual Fund Investments
|
56
|
|
|
57
|
|
||
Net Deferred Income Tax Asset
|
25
|
|
|
25
|
|
||
Other Assets, Noncurrent
|
66
|
|
|
74
|
|
||
Total
|
$
|
1,021
|
|
|
$
|
461
|
|
Other Current Liabilities
|
|
|
|
|
|
||
Production and Ad Valorem Taxes
|
$
|
93
|
|
|
$
|
84
|
|
Commodity Derivative Liabilities
|
112
|
|
|
58
|
|
||
Income Taxes Payable
|
32
|
|
|
18
|
|
||
Asset Retirement Obligations
|
51
|
|
|
51
|
|
||
Interest Payable
|
94
|
|
|
67
|
|
||
Current Portion of Capital Lease Obligations
|
54
|
|
|
61
|
|
||
Liabilities Associated with Assets Held for Sale
(1)
|
231
|
|
|
55
|
|
||
Other Liabilities, Current
|
124
|
|
|
184
|
|
||
Total
|
$
|
791
|
|
|
$
|
578
|
|
Other Noncurrent Liabilities
|
|
|
|
|
|
||
Deferred Compensation Liabilities
|
$
|
180
|
|
|
$
|
197
|
|
Asset Retirement Obligations
|
577
|
|
|
824
|
|
||
Marcellus Shale Firm Transportation Commitment
(7)
|
73
|
|
|
76
|
|
||
Production and Ad Valorem Taxes
|
86
|
|
|
69
|
|
||
Other Liabilities, Noncurrent
|
97
|
|
|
79
|
|
||
Total
|
$
|
1,013
|
|
|
$
|
1,245
|
|
(1)
|
Assets held for sale at
March 31, 2018
include our Gulf of Mexico assets and 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 assets held for sale primarily represent asset retirement obligations and other liabilities to be assumed by the purchaser. See
Note
3. Acquisitions and Divestitures
.
|
(2)
|
Balance at
March 31, 2018
represents amount held in escrow pending closing of the Gulf of Mexico asset sale. Balance at
December 31, 2017
represents amount held in escrow pending closing of the Saddle Butte acquisition. See
Note
3. Acquisitions and Divestitures
.
|
(3)
|
Balance at
March 31, 2018
includes
$14 million
of accrued dividends receivable on shares of Tamar Petroleum Ltd.
|
(4)
|
Includes
$72 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
.
|
(5)
|
Amount relates to intangible assets acquired in the Saddle Butte acquisition. See
Note
3. Acquisitions and Divestitures
.
|
(6)
|
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
.
|
(7)
|
Amounts relate to the long-term portion of retained firm transportation agreements. At
March 31, 2018
and
December 31, 2017
, we recorded
$11 million
and
$14 million
, respectively, associated with the current portion of the Marcellus Shale firm transportation commitment. See
Note
12. Commitments and Contingencies
.
|
|
Three Months Ended March 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
|
$
|
992
|
|
|
$
|
787
|
|
Restricted Cash at End of Period
|
30
|
|
|
—
|
|
||
Cash, Cash Equivalents, and Restricted Cash at End of Period
|
$
|
1,022
|
|
|
$
|
787
|
|
(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 March 31,
|
||||||
(millions, except per share amounts)
|
2018
(1)
|
|
2017
|
||||
Revenues
|
$
|
1,286
|
|
|
$
|
933
|
|
Net Income and Comprehensive Income Attributable to Noble Energy
|
554
|
|
|
51
|
|
||
|
|
|
|
||||
Net Income Attributable to Noble Energy per Common Share
|
|
|
|
||||
Basic
|
$
|
1.14
|
|
|
$
|
0.10
|
|
Diluted
|
$
|
1.14
|
|
|
$
|
0.10
|
|
(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
|
Three-Way Collars
|
NYMEX WTI
|
10,000
|
$
|
—
|
|
$
|
—
|
|
|
$
|
45.50
|
|
$
|
52.50
|
|
$
|
69.09
|
|
2018
|
Swaps
|
NYMEX WTI
|
58,000
|
—
|
|
59.74
|
|
|
—
|
|
—
|
|
—
|
|
|||||
2018
|
Two-Way Collars
|
NYMEX WTI
|
18,000
|
—
|
|
—
|
|
|
—
|
|
50.42
|
|
58.82
|
|
|||||
2018
|
Three-Way Collars
|
Dated Brent
|
3,000
|
—
|
|
—
|
|
|
40.00
|
|
50.00
|
|
70.41
|
|
|||||
2018
|
Swaps
|
ICE Brent
|
2,000
|
—
|
|
59.00
|
|
|
—
|
|
—
|
|
—
|
|
|||||
2018
|
Two-Way Collars
|
ICE Brent
|
2,000
|
—
|
|
—
|
|
|
—
|
|
50.00
|
|
55.25
|
|
|||||
2018
|
Three-Way Collars
|
ICE Brent
|
5,000
|
—
|
|
—
|
|
|
43.00
|
|
50.00
|
|
59.50
|
|
|||||
2018
|
Basis Swaps
|
(1)
|
12,000
|
(0.60
|
)
|
—
|
|
|
—
|
|
—
|
|
—
|
|
|||||
2019
|
Swaps
|
NYMEX WTI
|
31,000
|
—
|
|
57.77
|
|
|
—
|
|
—
|
|
—
|
|
|||||
2019
|
Swaps
|
ICE Brent
|
5,000
|
—
|
|
57.00
|
|
|
—
|
|
—
|
|
—
|
|
|||||
2019
|
Three-Way Collars
|
ICE Brent
|
3,000
|
—
|
|
—
|
|
|
43.00
|
|
50.00
|
|
64.07
|
|
|||||
2019
|
Basis Swaps
|
(1)
|
12,000
|
(1.01
|
)
|
—
|
|
|
—
|
|
—
|
|
—
|
|
|||||
2020
|
Swaption
(2)
|
NYMEX WTI
|
5,000
|
—
|
|
61.79
|
|
|
—
|
|
—
|
|
—
|
|
|
Fair Value of Derivative Instruments
|
||||||||||||||||||||||
|
Asset Derivative Instruments
|
|
Liability Derivative Instruments
|
||||||||||||||||||||
|
March 31,
2018 |
|
December 31,
2017 |
|
March 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
|
|
$
|
8
|
|
|
Current Assets
|
|
$
|
2
|
|
|
Current Liabilities
|
|
$
|
112
|
|
|
Current Liabilities
|
|
$
|
58
|
|
|
Noncurrent Assets
|
|
2
|
|
|
Noncurrent Assets
|
|
—
|
|
|
Noncurrent Liabilities
|
|
20
|
|
|
Noncurrent Liabilities
|
|
15
|
|
||||
Total
|
|
|
$
|
10
|
|
|
|
|
$
|
2
|
|
|
|
|
$
|
132
|
|
|
|
|
$
|
73
|
|
|
Three Months Ended March 31,
|
||||||
(millions)
|
2018
|
|
2017
|
||||
Cash Paid (Received) in Settlement of Commodity Derivative Instruments
|
|
|
|
||||
Crude Oil
|
$
|
30
|
|
|
$
|
(5
|
)
|
Natural Gas
|
(2
|
)
|
|
2
|
|
||
Total Cash Paid (Received) in Settlement of Commodity Derivative Instruments
|
28
|
|
|
(3
|
)
|
||
Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments
|
|
|
|
||||
Crude Oil
|
50
|
|
|
(63
|
)
|
||
Natural Gas
|
1
|
|
|
(44
|
)
|
||
Total Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments
|
51
|
|
|
(107
|
)
|
||
Loss (Gain) on Commodity Derivative Instruments
|
|
|
|
||||
Crude Oil
|
80
|
|
|
(68
|
)
|
||
Natural Gas
|
(1
|
)
|
|
(42
|
)
|
||
Total Loss (Gain) on Commodity Derivative Instruments
|
$
|
79
|
|
|
$
|
(110
|
)
|
|
March 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
|
435
|
|
|
2.78
|
%
|
|
85
|
|
|
2.49
|
%
|
||
Leviathan Term Loan Facility, due February 23, 2025
|
—
|
|
|
—
|
%
|
|
—
|
|
|
—
|
%
|
||
Senior Notes, due May 1, 2021
(1)
|
379
|
|
|
5.63
|
%
|
|
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
|
257
|
|
|
—
|
%
|
|
273
|
|
|
—
|
%
|
||
Total
|
6,963
|
|
|
|
|
6,859
|
|
|
|
||||
Unamortized Discount
|
(24
|
)
|
|
|
|
(24
|
)
|
|
|
||||
Unamortized Premium
|
11
|
|
|
|
|
12
|
|
|
|
||||
Unamortized Debt Issuance Costs
|
(38
|
)
|
|
|
|
(40
|
)
|
|
|
||||
Total Debt, Net of Unamortized Discount, Premium and Debt Issuance Costs
|
6,912
|
|
|
|
|
6,807
|
|
|
|
||||
Less Amounts Due Within One Year
|
|
|
|
|
|
|
|
||||||
Capital Lease Obligations
|
(54
|
)
|
|
|
|
(61
|
)
|
|
|
||||
Long-Term Debt Due After One Year
|
$
|
6,858
|
|
|
|
|
$
|
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
|
||||||||||
March 31, 2018
|
|
|
|
|
|
|
|
|
|
||||||||||
Financial Assets
|
|
|
|
|
|
|
|
|
|
||||||||||
Mutual Fund Investments
|
$
|
56
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
56
|
|
Commodity Derivative Instruments
|
—
|
|
|
29
|
|
|
—
|
|
|
(19
|
)
|
|
10
|
|
|||||
Investment in Tamar Petroleum Ltd.
|
—
|
|
|
162
|
|
|
—
|
|
|
—
|
|
|
162
|
|
|||||
Financial Liabilities
|
|
|
|
|
|
|
|
|
|
||||||||||
Commodity Derivative Instruments
|
—
|
|
|
(151
|
)
|
|
—
|
|
|
19
|
|
|
(132
|
)
|
|||||
Portion of Deferred Compensation Liability Measured at Fair Value
|
(70
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(70
|
)
|
|||||
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.
|
|
March 31, 2018
|
|
December 31, 2017
|
||||||||||||
(millions)
|
Carrying Amount
|
|
Fair Value
|
|
Carrying Amount
|
|
Fair Value
|
||||||||
Investment in CNX Midstream Partners (21,692,198 Units)
|
$
|
72
|
|
|
$
|
399
|
|
|
$
|
70
|
|
|
$
|
364
|
|
|
March 31, 2018
|
|
December 31, 2017
|
||||||||||||
(millions)
|
Carrying Amount
|
|
Fair Value
|
|
Carrying Amount
|
|
Fair Value
|
||||||||
Long-Term Debt
(1)
|
$
|
6,706
|
|
|
$
|
7,096
|
|
|
$
|
6,586
|
|
|
$
|
7,142
|
|
(1)
|
Excludes unamortized discount, premium, debt issuance costs and capital lease obligations.
|
(millions)
|
Three Months Ended March 31, 2018
|
||
Capitalized Exploratory Well Costs, Beginning of Period
|
$
|
520
|
|
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves
|
3
|
|
|
Reclassified to Assets Held for Sale
(1)
|
(159
|
)
|
|
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves
|
(1
|
)
|
|
Capitalized Exploratory Well Costs, End of Period
|
$
|
363
|
|
(millions)
|
March 31,
2018 |
|
December 31,
2017 |
||||
Exploratory Well Costs Capitalized for a Period of One Year or Less
|
$
|
3
|
|
|
$
|
10
|
|
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling
|
360
|
|
|
510
|
|
||
Balance at End of Period
|
$
|
363
|
|
|
$
|
520
|
|
|
Three Months Ended March 31,
|
||||||
(millions)
|
2018
|
|
2017
|
||||
Asset Retirement Obligations, Beginning Balance
|
$
|
875
|
|
|
$
|
935
|
|
Liabilities Incurred
|
2
|
|
|
1
|
|
||
Liabilities Settled
|
(20
|
)
|
|
(9
|
)
|
||
Revisions of Estimates
|
(11
|
)
|
|
(7
|
)
|
||
Reclassification to Liabilities Associated with Assets Held for Sale
|
(227
|
)
|
|
—
|
|
||
Accretion Expense
(1)
|
9
|
|
|
12
|
|
||
Asset Retirement Obligations, Ending Balance
|
$
|
628
|
|
|
$
|
932
|
|
(1)
|
Accretion expense is included in depreciation, depletion and amortization (DD&A)
expense in the consolidated statements of
operations.
|
|
Three Months Ended March 31,
|
||||||
(millions, except percentages)
|
2018
|
|
2017
|
||||
Current
|
$
|
126
|
|
|
$
|
12
|
|
Deferred
|
(157
|
)
|
|
—
|
|
||
Total Income Tax (Benefit) Expense
|
$
|
(31
|
)
|
|
$
|
12
|
|
Effective Tax Rate
|
(5.7
|
)%
|
|
20.3
|
%
|
|
Three Months Ended
March 31, |
||||||
(millions, except per share amounts)
|
2018
|
|
2017
|
||||
Net Income and Comprehensive Income Attributable to Noble Energy
|
$
|
554
|
|
|
$
|
36
|
|
Weighted Average Number of Shares Outstanding, Basic
|
487
|
|
|
431
|
|
||
Incremental Shares from Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust
|
1
|
|
|
3
|
|
||
Weighted Average Number of Shares Outstanding, Diluted
|
488
|
|
|
434
|
|
||
Income Per Share, Basic
|
$
|
1.14
|
|
|
$
|
0.08
|
|
Income Per Share, Diluted
|
1.14
|
|
|
0.08
|
|
||
Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above
|
16
|
|
|
14
|
|
|
|
|
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 March 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Crude Oil Sales
|
$
|
773
|
|
|
$
|
682
|
|
|
$
|
2
|
|
|
$
|
89
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
NGL Sales
|
146
|
|
|
146
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Natural Gas Sales
|
254
|
|
|
120
|
|
|
129
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Total Crude Oil, NGL and Natural Gas Sales
|
1,173
|
|
|
948
|
|
|
131
|
|
|
94
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Income from Equity Method Investees and Other
|
60
|
|
|
—
|
|
|
—
|
|
|
35
|
|
|
—
|
|
|
25
|
|
|
—
|
|
|
—
|
|
|||||||||
Intersegment Revenues
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
81
|
|
|
(81
|
)
|
|
—
|
|
|||||||||
Sales of Purchased Oil and Gas
|
53
|
|
|
31
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
22
|
|
|
—
|
|
|
—
|
|
|||||||||
Total Revenues
|
1,286
|
|
|
979
|
|
|
131
|
|
|
129
|
|
|
—
|
|
|
128
|
|
|
(81
|
)
|
|
—
|
|
|||||||||
Lease Operating Expense
|
155
|
|
|
126
|
|
|
7
|
|
|
22
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Production and Ad Valorem Taxes
|
54
|
|
|
53
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|||||||||
Gathering, Transportation and Processing Expense
|
95
|
|
|
128
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
20
|
|
|
(53
|
)
|
|
—
|
|
|||||||||
Other Royalty Expense
|
17
|
|
|
17
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Total Production Expense
|
321
|
|
|
324
|
|
|
7
|
|
|
22
|
|
|
—
|
|
|
21
|
|
|
(53
|
)
|
|
—
|
|
|||||||||
DD&A
|
468
|
|
|
404
|
|
|
13
|
|
|
26
|
|
|
—
|
|
|
17
|
|
|
(3
|
)
|
|
11
|
|
|||||||||
Asset Impairments
|
168
|
|
|
168
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Gain on Divestitures
|
(588
|
)
|
|
(6
|
)
|
|
(386
|
)
|
|
—
|
|
|
—
|
|
|
(196
|
)
|
|
—
|
|
—
|
|
—
|
|
||||||||
Purchased Oil and Gas
|
57
|
|
|
36
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
21
|
|
|
—
|
|
|
—
|
|
|||||||||
Loss on Commodity Derivative Instruments
|
79
|
|
|
64
|
|
|
—
|
|
|
15
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Income (Loss) Before Income Taxes
|
543
|
|
|
(43
|
)
|
|
473
|
|
|
64
|
|
|
(9
|
)
|
|
247
|
|
|
(15
|
)
|
|
(174
|
)
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
Three Months Ended March 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Crude Oil Sales
|
$
|
527
|
|
|
$
|
439
|
|
|
$
|
1
|
|
|
$
|
87
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
NGL Sales
|
105
|
|
|
105
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Natural Gas Sales
|
362
|
|
|
226
|
|
|
130
|
|
|
6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Total Crude Oil, NGL and Natural Gas Sales
|
994
|
|
|
770
|
|
|
131
|
|
|
93
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Income from Equity Method Investees and Other
|
42
|
|
|
—
|
|
|
—
|
|
|
28
|
|
|
—
|
|
|
14
|
|
|
—
|
|
|
—
|
|
|||||||||
Intersegment Revenues
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
58
|
|
|
(58
|
)
|
|
—
|
|
|||||||||
Total Revenues
|
1,036
|
|
|
770
|
|
|
131
|
|
|
121
|
|
|
—
|
|
|
72
|
|
|
(58
|
)
|
|
—
|
|
Lease Operating Expense
|
139
|
|
|
108
|
|
|
8
|
|
|
23
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Production and Ad Valorem Taxes
|
41
|
|
|
40
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|||||||||
Gathering, Transportation and Processing Expense
|
119
|
|
|
142
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
15
|
|
|
(38
|
)
|
|
—
|
|
|||||||||
Other Royalty Expense
|
4
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Total Production Expense
|
303
|
|
|
294
|
|
|
8
|
|
|
23
|
|
|
—
|
|
|
16
|
|
|
(38
|
)
|
|
—
|
|
|||||||||
DD&A
|
528
|
|
|
459
|
|
|
19
|
|
|
34
|
|
|
1
|
|
|
5
|
|
|
—
|
|
|
10
|
|
|||||||||
Gain on Commodity Derivative Instruments
|
(110
|
)
|
|
(102
|
)
|
|
—
|
|
|
(8
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Income (Loss) Before Income Taxes
|
59
|
|
|
62
|
|
|
101
|
|
|
66
|
|
|
(21
|
)
|
|
49
|
|
|
(22
|
)
|
|
(176
|
)
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
March 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Goodwill
(2)
|
$
|
1,402
|
|
|
$
|
1,291
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
111
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Total Assets
|
22,448
|
|
|
15,622
|
|
|
3,263
|
|
|
1,306
|
|
|
85
|
|
|
2,141
|
|
|
(217
|
)
|
|
248
|
|
|||||||||
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 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 due to winter storms and flooding impacting US onshore operations;
|
•
|
availability or reliability of supplier services, including access to support equipment and facilities, potential processing facility capacity constraints, and/or 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;
|
•
|
drilling results;
|
•
|
property acquisitions and divestitures;
|
•
|
exploration activity;
|
•
|
cash flows from operations, including cash flows from potential midstream drop-down transactions;
|
•
|
indebtedness levels;
|
•
|
availability of financing or other sources of funding;
|
•
|
impact of new laws and regulations on our business practices, including potential legislative or regulatory changes regarding the use of hydraulic fracturing; and
|
•
|
potential changes in the fiscal regimes of the US and other countries in which we operate.
|
•
|
total average daily sales volumes of
370
MBoe/d;
|
•
|
average daily sales volumes for US onshore crude oil of
103
MBbl/d; and
|
•
|
average daily sales volumes of
263
MMcfe/d, net, in Israel, and a first quarter record for average daily gross sales volumes of 959 MMcfe/d, primarily from the Tamar field.
|
•
|
$386 million
pre-tax gain on sale of a 7.5% interest in the Tamar field;
|
•
|
$168 million impairment expense related to Gulf of Mexico assets held for sale;
|
•
|
pre-tax income of
$485 million
, as compared with pre-tax income of
$208 million
for
first quarter 2017
; and
|
•
|
capital expenditures of
$667 million
, excluding acquisitions, as compared with $
598 million
for
first quarter 2017
.
|
|
Three Months Ended March 31,
|
||||||
(millions)
|
2018
|
|
2017
|
||||
Oil, NGL and Gas Sales to Third Parties
(1)
|
$
|
1,173
|
|
|
$
|
994
|
|
Sales of Purchased Gas
(2)
|
31
|
|
|
—
|
|
||
Income from Equity Method Investees
|
35
|
|
|
28
|
|
||
Total Revenues
|
1,239
|
|
|
1,022
|
|
||
Production Expense
(1)
|
353
|
|
|
325
|
|
||
Exploration Expense
|
35
|
|
|
42
|
|
||
Depreciation, Depletion and Amortization
|
443
|
|
|
513
|
|
||
Purchases of Gas
(2)
|
36
|
|
|
—
|
|
||
Gain on Divestitures
(3)
|
(392
|
)
|
|
—
|
|
||
Asset Impairments
(3)
|
168
|
|
|
—
|
|
||
Loss (Gain) on Commodity Derivative Instruments
|
79
|
|
|
(110
|
)
|
||
Income Before Income Taxes
|
485
|
|
|
208
|
|
(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 an increase of $5 million to our NGL revenues with a corresponding increase of $5 million to production expense. See
Item 1. Financial Statements – Note 2. Basis of Presentation
.
|
(2)
|
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)
|
|
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 March 31, 2018
|
|||||||||||||||||||||||
United States
(3)
|
122
|
|
|
64
|
|
|
504
|
|
|
270
|
|
|
$
|
61.95
|
|
|
$
|
25.53
|
|
|
$
|
2.63
|
|
Eastern Mediterranean
|
—
|
|
|
—
|
|
|
261
|
|
|
44
|
|
|
—
|
|
|
—
|
|
|
5.48
|
|
|||
West Africa
(4)
|
15
|
|
|
—
|
|
|
206
|
|
|
49
|
|
|
68.14
|
|
|
—
|
|
|
0.27
|
|
|||
Total Consolidated Operations
|
137
|
|
|
64
|
|
|
971
|
|
|
363
|
|
|
62.60
|
|
|
25.53
|
|
|
2.90
|
|
|||
Equity Investees
(5)
|
2
|
|
|
5
|
|
|
—
|
|
|
7
|
|
|
66.08
|
|
|
39.90
|
|
|
—
|
|
|||
Total
|
139
|
|
|
69
|
|
|
971
|
|
|
370
|
|
|
$
|
62.64
|
|
|
$
|
26.62
|
|
|
$
|
2.90
|
|
Three Months Ended March 31, 2017
|
|||||||||||||||||||||||
United States
|
99
|
|
|
49
|
|
|
730
|
|
|
270
|
|
|
$
|
49.03
|
|
|
$
|
23.97
|
|
|
$
|
3.44
|
|
Eastern Mediterranean
|
—
|
|
|
—
|
|
|
271
|
|
|
46
|
|
|
—
|
|
|
—
|
|
|
5.32
|
|
|||
West Africa
(4)
|
18
|
|
|
—
|
|
|
244
|
|
|
58
|
|
|
53.42
|
|
|
—
|
|
|
0.27
|
|
|||
Total Consolidated Operations
|
117
|
|
|
49
|
|
|
1,245
|
|
|
374
|
|
|
49.70
|
|
|
23.97
|
|
|
3.23
|
|
|||
Equity Investees
(5)
|
2
|
|
|
6
|
|
|
—
|
|
|
8
|
|
|
52.59
|
|
|
36.04
|
|
|
—
|
|
|||
Total
|
119
|
|
|
55
|
|
|
1,245
|
|
|
382
|
|
|
$
|
49.73
|
|
|
$
|
25.34
|
|
|
$
|
3.23
|
|
(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 an increase of $5 million to our NGL revenues with a corresponding increase of $5 million to production expense. Furthermore, we recorded additional NGL and natural gas sales volumes of 4 MBbl/d and 31 MMcf/d, respectively, due to ASC 606 adoption. The resulting impact reduced our average realized NGL and natural gas sales prices by $0.87/Bbl and $0.10/Mcf, respectively. See
Item 1. Financial Statements – Note 2. Basis of Presentation
.
|
(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 24 MBoe/d related to the Gulf of Mexico assets, which were sold in April 2018.
|
(4)
|
Natural gas from the Alba field in Equatorial Guinea is under contract for $0.25 per MMBtu to a methanol plant, an LPG plant, an LNG plant and a power generation plant. The methanol and LPG plants are owned in part 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 March 31, 2017
|
$
|
527
|
|
|
$
|
105
|
|
|
$
|
362
|
|
|
$
|
994
|
|
Changes due to
|
|
|
|
|
|
|
|
||||||||
Increase (Decrease) in Sales Volumes
|
94
|
|
|
15
|
|
|
(84
|
)
|
|
25
|
|
||||
Increase (Decrease) in Sales Prices
|
152
|
|
|
21
|
|
|
(24
|
)
|
|
149
|
|
||||
Impact of ASC 606 Adoption
|
—
|
|
|
5
|
|
|
—
|
|
|
5
|
|
||||
Three Months Ended March 31, 2018
|
$
|
773
|
|
|
$
|
146
|
|
|
$
|
254
|
|
|
$
|
1,173
|
|
•
|
26%
increase in average realized prices due to the partial rebalancing of global supply and demand factors; and
|
•
|
higher US onshore sales volumes of 28 MBbl/d, primarily driven by an increase in development activity in the DJ Basin and Delaware Basin. Delaware Basin sales volumes more than doubled compared to first quarter 2017 due to increased development activities and sales volumes from the acquired Clayton Williams Energy assets in second quarter 2017;
|
•
|
lower sales volumes of 5 MBbl/d in the Gulf of Mexico due to natural field decline; and
|
•
|
lower sales volumes of 4 MBbl/d offshore West Africa due to timing of liftings.
|
•
|
higher US onshore sales volumes of 11 MBbl/d (exclusive of 4 MBbl/d from adoption of ASC 606), primarily attributable to development activities in the southern area of Gates Ranch in the Eagle Ford Shale;
|
•
|
10% increase in average realized prices due to the partial rebalancing of domestic supply and demand factors; and
|
•
|
$
5 million
increase associated with the adoption of ASC 606;
|
•
|
lower sales volumes of 10 MBbl/d due to the divestiture of the Marcellus Shale upstream assets in second quarter 2017.
|
•
|
lower sales volumes of 370 MMcf/d due to the divestiture of the Marcellus Shale upstream assets in second quarter 2017; and
|
•
|
lower sales volumes of 38 MMcf/d from the Alba field, offshore Equatorial Guinea, due to natural field decline;
|
•
|
7% decrease in average realized prices due to the impact of differentials for US onshore sales volumes;
|
•
|
higher US onshore sales volumes of 124 MMcf/d (exclusive of 31 MMcf/d from adoption of ASC 606), primarily attributable to development activities in the southern area of Gates Ranch in the Eagle Ford Shale.
|
(millions, except unit rate)
|
Total per BOE
(1) (2)
|
|
Total
|
|
United
States
(2)
|
|
Eastern
Mediter- ranean |
|
West Africa
|
||||||||||
Three Months Ended March 31, 2018
|
|
|
|
|
|
|
|
|
|
||||||||||
Lease Operating Expense
(3)
|
$
|
4.75
|
|
|
$
|
155
|
|
|
$
|
126
|
|
|
$
|
7
|
|
|
$
|
22
|
|
Production and Ad Valorem Taxes
|
1.62
|
|
|
53
|
|
|
53
|
|
|
—
|
|
|
—
|
|
|||||
Gathering, Transportation and Processing
(4)
|
3.92
|
|
|
128
|
|
|
128
|
|
|
—
|
|
|
—
|
|
|||||
Other Royalty Expense
|
N/M
|
|
|
17
|
|
|
17
|
|
|
—
|
|
|
—
|
|
|||||
Total Production Expense
|
$
|
10.29
|
|
|
$
|
353
|
|
|
$
|
324
|
|
|
$
|
7
|
|
|
$
|
22
|
|
Total Production Expense per BOE
|
|
|
$
|
10.29
|
|
|
$
|
13.31
|
|
|
$
|
1.79
|
|
|
$
|
5.01
|
|
||
Three Months Ended March 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Lease Operating Expense
(3)
|
$
|
4.13
|
|
|
$
|
139
|
|
|
$
|
108
|
|
|
$
|
8
|
|
|
$
|
23
|
|
Production and Ad Valorem Taxes
|
1.19
|
|
|
40
|
|
|
40
|
|
|
—
|
|
|
—
|
|
|||||
Gathering, Transportation and Processing
(4)
|
4.22
|
|
|
142
|
|
|
142
|
|
|
—
|
|
|
—
|
|
|||||
Other Royalty Expense
|
N/M
|
|
|
4
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|||||
Total Production Expense
|
$
|
9.54
|
|
|
$
|
325
|
|
|
$
|
294
|
|
|
$
|
8
|
|
|
$
|
23
|
|
Total Production Expense per BOE
|
|
|
$
|
9.54
|
|
|
$
|
12.11
|
|
|
$
|
1.95
|
|
|
$
|
4.36
|
|
(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 an increase of $5 million to gathering, transportation and processing expense related to US operations for first quarter 2018. On a per BOE basis, the presentation change resulted in a decrease of
$0.25
/Boe for US production expense and
$0.12
/Boe for total production expense. 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 in the Delaware Basin;
|
•
|
an increase in US production and ad valorem taxes due to higher commodity prices;
|
•
|
an increase in US gathering, transportation and processing expense primarily 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 US lease operating expense in the Gulf of Mexico due to lower production caused by natural field decline; 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 March 31, 2018
|
|
|
|
|
|
|
|
|
|
||||||||||
DD&A Expense
|
$
|
443
|
|
|
$
|
404
|
|
|
$
|
13
|
|
|
$
|
26
|
|
|
$
|
—
|
|
Unit Rate per BOE
(1)
|
$
|
13.57
|
|
|
$
|
16.60
|
|
|
$
|
3.32
|
|
|
$
|
5.92
|
|
|
N/M
|
|
|
Three Months Ended March 31, 2017
|
|
|
|
|
|
|
|
|
|
||||||||||
DD&A Expense
|
$
|
513
|
|
|
$
|
459
|
|
|
$
|
19
|
|
|
$
|
34
|
|
|
$
|
1
|
|
Unit Rate per BOE
(1)
|
$
|
15.24
|
|
|
$
|
18.90
|
|
|
$
|
4.63
|
|
|
$
|
6.44
|
|
|
N/M
|
|
(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 and globally due to positive price revisions;
|
•
|
Marcellus Shale upstream divestiture in second quarter 2017, which reduced DD&A expense by $73 million;
|
•
|
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, which reduced DD&A expense by $47 million; and
|
•
|
reclassification of a
7.5%
working interest in the Tamar field, offshore Israel, as asset held for sale, resulting in the cessation of DD&A expense and a decrease of approximately $5 million;
|
•
|
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 payments of
$28 million
; and
|
•
|
non-cash increases in the liability fair value of our derivative instruments of
$51 million
driven by changes in the forward commodity price curves for both crude oil and natural gas.
|
•
|
net cash settlement receipts of
$3 million
; and
|
•
|
non-cash decreases in the liability fair value of our derivative instruments of $
107
million driven by changes in the forward commodity price curves for both crude oil and natural gas.
|
•
|
completion of the Saddle Butte acquisition;
|
•
|
completion of the Coronado central gathering facility (CGF) construction and continued construction on two additional CGFs in the Delaware Basin;
|
•
|
commencement of compression services in the Delaware Basin and purchase of additional mainline pumps for expansion of the Advantage pipeline; and
|
•
|
continued construction of freshwater delivery infrastructure in the Mustang IDP area, which is expected to become operational mid-year 2018, and initiation of procurement and construction on the oil, gas and produced water gathering systems.
|
•
|
gain of $
196
million on the sale of CONE Gathering;
|
•
|
pre-tax income of $
247 million
compared with pre-tax income of $
49 million
for
first
quarter
2017
; and
|
•
|
capital expenditures, excluding acquisitions, of
$253 million
.
|
|
Three Months Ended March 31,
|
||||||
(millions)
|
2018
|
|
2017
|
||||
Midstream Services Revenues – Third Party
|
$
|
13
|
|
|
$
|
—
|
|
Sales of Purchased Oil
|
22
|
|
|
—
|
|
||
Income from Equity Method Investees
|
12
|
|
|
14
|
|
||
Intersegment Revenues
|
81
|
|
|
58
|
|
||
Total Revenues
|
128
|
|
|
72
|
|
||
Operating Costs and Expenses
|
39
|
|
|
18
|
|
||
Depreciation and Amortization
|
17
|
|
|
5
|
|
||
Gain on Divestiture
|
(196
|
)
|
|
—
|
|
||
Purchased Oil
|
21
|
|
|
—
|
|
||
Total (Income) Expense
|
(119
|
)
|
|
23
|
|
||
Income Before Income Taxes
|
$
|
247
|
|
|
$
|
49
|
|
|
Three Months Ended March 31,
|
||||||
(millions, except unit rate)
|
2018
|
|
2017
|
||||
G&A Expense
|
$
|
104
|
|
|
$
|
99
|
|
Unit Rate per BOE
(1)
|
$
|
3.18
|
|
|
$
|
2.94
|
|
(1)
|
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.
|
|
Three Months Ended March 31,
|
||||||
(millions, except unit rate)
|
2018
|
|
2017
|
||||
Interest Expense, Gross
|
$
|
90
|
|
|
$
|
99
|
|
Capitalized Interest
|
(17
|
)
|
|
(12
|
)
|
||
Interest Expense, Net
|
$
|
73
|
|
|
$
|
87
|
|
Unit Rate per BOE
(1)
|
$
|
2.24
|
|
|
$
|
2.58
|
|
(1)
|
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.
|
|
March 31,
|
|
December 31,
|
||||
(millions, except percentages)
|
2018
|
|
2017
|
||||
Total Cash
(1)
|
$
|
1,022
|
|
|
$
|
713
|
|
Amount Available to be Borrowed Under Revolving Credit Facility
(2)
|
4,000
|
|
|
3,770
|
|
||
Total Liquidity
|
$
|
5,022
|
|
|
$
|
4,483
|
|
Total Debt
(3)
|
$
|
6,963
|
|
|
$
|
6,859
|
|
Noble Energy Share of Equity
|
10,362
|
|
|
9,936
|
|
||
Ratio of Debt-to-Book Capital
(4)
|
40
|
%
|
|
41
|
%
|
(1)
|
As of
March 31, 2018
, total cash included cash and cash equivalents of $25 million related to Noble Midstream Partners and $30 million restricted cash related to the Gulf of Mexico asset sale, which closed in April 2018. As of
December 31, 2017
, total cash included $18 million cash of Noble Midstream Partners and $37.5 million restricted cash related to the Saddle Butte acquisition that closed in first quarter of 2018.
|
(2)
|
Excludes amounts available to be borrowed under the Noble Midstream Services Revolving Credit Facility and Leviathan Term Loan Facility, respectively, 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.
|
|
Three Months Ended March 31,
|
||||||
(millions)
|
2018
|
|
2017
|
||||
Total Cash Provided By (Used in)
|
|
|
|
||||
Operating Activities
|
$
|
583
|
|
|
$
|
536
|
|
Investing Activities
|
(572
|
)
|
|
(893
|
)
|
||
Financing Activities
|
298
|
|
|
(66
|
)
|
||
Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash
|
$
|
309
|
|
|
$
|
(423
|
)
|
|
Three Months Ended March 31,
|
||||||
(millions)
|
2018
|
|
2017
|
||||
Acquisition, Capital and Exploration Expenditures
|
|
|
|
|
|
||
Unproved Property Acquisition
(1)
|
$
|
—
|
|
|
$
|
246
|
|
Proved Property Acquisition
(1)
|
—
|
|
|
58
|
|
||
Exploration
|
15
|
|
|
10
|
|
||
Development
|
641
|
|
|
587
|
|
||
Midstream
(2)
|
459
|
|
|
93
|
|
||
Corporate and Other
|
11
|
|
|
5
|
|
||
Total
|
$
|
1,126
|
|
|
$
|
999
|
|
•
|
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)
|
||||||
1/1/2018 - 1/31/2018
|
87
|
|
|
$
|
30.19
|
|
|
—
|
|
|
|
|
|
2/1/2018 - 2/28/2018
|
544,005
|
|
|
30.84
|
|
|
334,700
|
|
|
|
|
||
3/1/2018 - 3/31/2018
|
1,907,479
|
|
|
30.15
|
|
|
1,897,700
|
|
|
|
|
||
Total
|
2,451,571
|
|
|
$
|
30.30
|
|
|
2,232,400
|
|
|
$
|
683
|
|
(1)
|
Includes stock repurchases of
219,171
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. In addition, 745,202 of common shares were retired in the period relating to the Clayton Williams Energy Acquisition.
|
(2)
|
On
February 15, 2018
, we announced that the Company's Board of Directors had authorized a $
750
million share repurchase program, which expires
December 31, 2020
. During
first quarter 2018
, we repurchased and retired
2.2
million shares of common stock at an average purchase price of $
30.21
per share.
|
|
||
Exhibit Number
|
|
Exhibit**
|
|
|
|
2.1
|
|
|
|
|
|
2.2
|
|
|
|
|
|
2.3
|
|
|
|
|
|
3.1
|
|
|
|
|
|
3.2
|
|
|
|
|
|
3.3
|
|
|
|
|
|
3.4
|
|
|
|
|
|
10.1*
|
|
|
|
|
|
10.2*
|
|
|
|
|
|
10.3*
|
|
|
|
|
|
10.4
|
|
|
|
|
|
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
|
|
May 1, 2018
|
|
/s/ Kenneth M. Fisher
|
|
|
|
|
Kenneth M. Fisher
Executive Vice President, Chief Financial Officer
|
1 Year Noble Energy Chart |
1 Month Noble Energy Chart |
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