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
|
|
|
(Do not check if a smaller reporting company)
|
|
Part I.
Financial Information
|
|
|
|
Item 1.
Financial Statements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Item 4.
Controls and Procedures
|
|
|
|
Part II.
Other Information
|
|
|
|
Item 1.
Legal Proceedings
|
|
|
|
Item 1A.
Risk Factors
|
|
|
|
|
|
Item 3.
Defaults Upon Senior Securities
|
|
|
|
Item 4.
Mine Safety Disclosures
|
|
|
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Item 5.
Other Information
|
|
|
|
Item 6.
Exhibits
|
|
|
|
|
|
|
Three Months Ended
September 30, |
|
Nine Months Ended
September 30, |
||||||||||||
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Revenues
|
|
|
|
|
|
|
|
||||||||
Oil, Gas and NGL Sales
|
$
|
882
|
|
|
$
|
783
|
|
|
$
|
2,411
|
|
|
$
|
2,264
|
|
Income from Equity Method Investees
|
28
|
|
|
36
|
|
|
70
|
|
|
60
|
|
||||
Total
|
910
|
|
|
819
|
|
|
2,481
|
|
|
2,324
|
|
||||
Costs and Expenses
|
|
|
|
|
|
|
|
|
|
||||||
Production Expense
|
274
|
|
|
247
|
|
|
820
|
|
|
715
|
|
||||
Exploration Expense
|
125
|
|
|
203
|
|
|
376
|
|
|
308
|
|
||||
Depreciation, Depletion and Amortization
|
621
|
|
|
539
|
|
|
1,859
|
|
|
1,444
|
|
||||
General and Administrative
|
95
|
|
|
109
|
|
|
293
|
|
|
308
|
|
||||
Other Operating Expense, Net
|
45
|
|
|
188
|
|
|
66
|
|
|
310
|
|
||||
Total
|
1,160
|
|
|
1,286
|
|
|
3,414
|
|
|
3,085
|
|
||||
Operating Loss
|
(250
|
)
|
|
(467
|
)
|
|
(933
|
)
|
|
(761
|
)
|
||||
Other Expense (Income)
|
|
|
|
|
|
|
|
|
|
||||||
(Gain) Loss on Commodity Derivative Instruments
|
(55
|
)
|
|
(267
|
)
|
|
53
|
|
|
(331
|
)
|
||||
Interest, Net of Amount Capitalized
|
86
|
|
|
71
|
|
|
242
|
|
|
183
|
|
||||
Other Non-Operating (Income) Expense, Net
|
(1
|
)
|
|
(12
|
)
|
|
3
|
|
|
(20
|
)
|
||||
Total
|
30
|
|
|
(208
|
)
|
|
298
|
|
|
(168
|
)
|
||||
Loss Before Income Taxes
|
(280
|
)
|
|
(259
|
)
|
|
(1,231
|
)
|
|
(593
|
)
|
||||
Income Tax (Benefit) Provision
|
(137
|
)
|
|
24
|
|
|
(486
|
)
|
|
(180
|
)
|
||||
Net Loss Including Noncontrolling Interests
|
(143
|
)
|
|
(283
|
)
|
|
(745
|
)
|
|
(413
|
)
|
||||
Less: Net Income Attributable to Noncontrolling Interests
|
1
|
|
|
—
|
|
|
1
|
|
|
—
|
|
||||
Net Loss Attributable to Noble Energy
|
$
|
(144
|
)
|
|
$
|
(283
|
)
|
|
$
|
(746
|
)
|
|
$
|
(413
|
)
|
|
|
|
|
|
|
|
|
||||||||
Net Loss Attributable to Noble Energy Per Share of Common Stock
|
|
|
|
|
|
|
|
||||||||
Loss Per Share, Basic
|
$
|
(0.33
|
)
|
|
$
|
(0.67
|
)
|
|
$
|
(1.73
|
)
|
|
$
|
(1.05
|
)
|
Loss Per Share, Diluted
|
$
|
(0.33
|
)
|
|
$
|
(0.67
|
)
|
|
$
|
(1.73
|
)
|
|
$
|
(1.05
|
)
|
|
|
|
|
|
|
|
|
||||||||
Weighted Average Number of Shares Outstanding
|
|
|
|
|
|
|
|
||||||||
Basic
|
430
|
|
|
420
|
|
|
430
|
|
|
392
|
|
||||
Diluted
|
430
|
|
|
420
|
|
|
430
|
|
|
392
|
|
|
Three Months Ended
September 30, |
|
Nine Months Ended
September 30, |
||||||||||||
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Net Loss Including Noncontrolling Interests
|
$
|
(143
|
)
|
|
$
|
(283
|
)
|
|
$
|
(745
|
)
|
|
$
|
(413
|
)
|
Other Items of Comprehensive Loss
|
|
|
|
|
|
|
|
||||||||
Net Change in Mutual Fund Investment
|
—
|
|
|
—
|
|
|
—
|
|
|
(11
|
)
|
||||
Less Tax Expense
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
||||
Net Change in Pension and Other
|
1
|
|
|
69
|
|
|
2
|
|
|
94
|
|
||||
Less Tax Benefit
|
(1
|
)
|
|
(23
|
)
|
|
(1
|
)
|
|
(33
|
)
|
||||
Other Comprehensive Income
|
—
|
|
|
46
|
|
|
1
|
|
|
53
|
|
||||
Comprehensive Loss Including Noncontrolling Interests
|
(143
|
)
|
|
(237
|
)
|
|
(744
|
)
|
|
(360
|
)
|
||||
Less: Comprehensive Income Attributable to Noncontrolling Interests
|
1
|
|
|
—
|
|
|
1
|
|
|
—
|
|
||||
Comprehensive Loss Attributable to Noble Energy
|
$
|
(144
|
)
|
|
$
|
(237
|
)
|
|
$
|
(745
|
)
|
|
$
|
(360
|
)
|
|
September 30,
2016 |
|
December 31,
2015 |
|||||
ASSETS
|
|
|
|
|||||
Current Assets
|
|
|
|
|||||
Cash and Cash Equivalents
|
$
|
1,819
|
|
|
$
|
1,028
|
|
|
Accounts Receivable, Net
|
486
|
|
|
450
|
|
|||
Commodity Derivative Assets
|
120
|
|
|
582
|
|
|||
Other Current Assets
|
352
|
|
|
216
|
|
|||
Total Current Assets
|
2,777
|
|
|
2,276
|
|
|||
Property, Plant and Equipment
|
|
|
|
|
|
|||
Oil and Gas Properties (Successful Efforts Method of Accounting)
|
30,372
|
|
|
31,220
|
|
|||
Property, Plant and Equipment, Other
|
919
|
|
|
858
|
|
|||
Total Property, Plant and Equipment, Gross
|
31,291
|
|
|
32,078
|
|
|||
Accumulated Depreciation, Depletion and Amortization
|
(12,186
|
)
|
|
(10,778
|
)
|
|||
Total Property, Plant and Equipment, Net
|
19,105
|
|
|
21,300
|
|
|||
Other Noncurrent Assets
|
587
|
|
|
620
|
|
|||
Total Assets
|
$
|
22,469
|
|
|
$
|
24,196
|
|
|
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
|
|
|||||
Current Liabilities
|
|
|
|
|
||||
Accounts Payable - Trade
|
$
|
786
|
|
|
$
|
1,128
|
|
|
Other Current Liabilities
|
742
|
|
|
677
|
|
|||
Total Current Liabilities
|
1,528
|
|
|
1,805
|
|
|||
Long-Term Debt
|
7,854
|
|
|
7,976
|
|
|||
Deferred Income Taxes
|
2,103
|
|
|
2,826
|
|
|||
Other Noncurrent Liabilities
|
1,139
|
|
|
1,219
|
|
|||
Total Liabilities
|
12,624
|
|
|
13,826
|
|
|||
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; 471 Million and 470 Million Shares Issued, respectively
|
5
|
|
|
5
|
|
|||
Additional Paid in Capital
|
6,417
|
|
|
6,360
|
|
|||
Accumulated Other Comprehensive Loss
|
(32
|
)
|
|
(33
|
)
|
|||
Treasury Stock, at Cost; 38 Million Shares
|
(696
|
)
|
|
(688
|
)
|
|||
Retained Earnings
|
3,851
|
|
|
4,726
|
|
|||
Noble Energy Share of Equity
|
9,545
|
|
|
10,370
|
|
|||
Noncontrolling Interests
|
300
|
|
—
|
|
—
|
|
||
Total Equity
|
9,845
|
|
|
10,370
|
|
|||
Total Liabilities and Equity
|
$
|
22,469
|
|
|
$
|
24,196
|
|
|
Nine Months Ended
September 30, |
||||||
|
2016
|
|
2015
|
||||
Cash Flows From Operating Activities
|
|
|
|
||||
Net Loss Including Noncontrolling Interests
|
$
|
(745
|
)
|
|
$
|
(413
|
)
|
Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities
|
|
|
|
|
|
||
Depreciation, Depletion and Amortization
|
1,859
|
|
|
1,444
|
|
||
Asset Impairments
|
—
|
|
|
43
|
|
||
Dry Hole Cost
|
105
|
|
|
154
|
|
||
Undeveloped Leasehold Impairment
|
81
|
|
|
—
|
|
||
Gain on Extinguishment of Debt
|
(80
|
)
|
|
—
|
|
||
Loss on Asset Due to Terminated Contract
|
44
|
|
|
—
|
|
||
Deferred Income Tax Benefit
|
(699
|
)
|
|
(244
|
)
|
||
Loss (Gain) on Commodity Derivative Instruments
|
53
|
|
|
(331
|
)
|
||
Net Cash Received in Settlement of Commodity Derivative Instruments
|
454
|
|
|
683
|
|
||
Stock Based Compensation
|
61
|
|
|
69
|
|
||
Non-cash Pension Termination Expense
|
—
|
|
|
81
|
|
||
Other Adjustments for Noncash Items Included in Income
|
92
|
|
|
74
|
|
||
Changes in Operating Assets and Liabilities
|
|
|
|
|
|
||
(Increase) Decrease in Accounts Receivable
|
6
|
|
|
370
|
|
||
Decrease in Accounts Payable
|
(124
|
)
|
|
(248
|
)
|
||
Increase (Decrease) in Current Income Taxes Payable
|
82
|
|
|
(118
|
)
|
||
Other Current Assets and Liabilities, Net
|
(72
|
)
|
|
(28
|
)
|
||
Other Operating Assets and Liabilities, Net
|
(63
|
)
|
|
(50
|
)
|
||
Net Cash Provided by Operating Activities
|
1,054
|
|
|
1,486
|
|
||
Cash Flows From Investing Activities
|
|
|
|
|
|
||
Additions to Property, Plant and Equipment
|
(1,164
|
)
|
|
(2,519
|
)
|
||
Cash Acquired in Rosetta Merger
|
—
|
|
|
61
|
|
||
Additions to Equity Method Investments
|
(8
|
)
|
|
(86
|
)
|
||
Proceeds from Divestitures and Other
|
786
|
|
|
151
|
|
||
Net Cash Used in Investing Activities
|
(386
|
)
|
|
(2,393
|
)
|
||
Cash Flows From Financing Activities
|
|
|
|
|
|
||
Dividends Paid, Common Stock
|
(129
|
)
|
|
(214
|
)
|
||
Proceeds from Issuance of Noble Energy Common Stock, Net of Offering Costs
|
—
|
|
|
1,112
|
|
||
Proceeds from Issuance of Noble Midstream Common Units, Net of Offering Costs
|
299
|
|
|
—
|
|
||
Proceeds from Term Loan Facility
|
1,400
|
|
|
—
|
|
||
Repayment of Credit Facility
|
—
|
|
|
(74
|
)
|
||
Repayment of Senior Notes
|
(1,383
|
)
|
|
(12
|
)
|
||
Repayment of Capital Lease Obligation
|
(39
|
)
|
|
(49
|
)
|
||
Other
|
(25
|
)
|
|
(11
|
)
|
||
Net Cash Provided by Financing Activities
|
123
|
|
|
752
|
|
||
Increase (Decrease) in Cash and Cash Equivalents
|
791
|
|
|
(155
|
)
|
||
Cash and Cash Equivalents at Beginning of Period
|
1,028
|
|
|
1,183
|
|
||
Cash and Cash Equivalents at End of Period
|
$
|
1,819
|
|
|
$
|
1,028
|
|
|
Attributable to Noble Energy
|
|
|
|
|
|||||||||||||||||||||||
|
Common
Stock
|
|
Additional
Paid in
Capital
|
|
Accumulated Other
Comprehensive
Loss
|
|
Treasury
Stock at
Cost
|
|
Retained
Earnings
|
|
Non-
controlling Interests
|
|
Total Equity
|
|||||||||||||||
December 31, 2015
|
$
|
5
|
|
|
$
|
6,360
|
|
|
$
|
(33
|
)
|
|
$
|
(688
|
)
|
|
$
|
4,726
|
|
|
$
|
—
|
|
|
$
|
10,370
|
|
|
Net (Loss) Income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(746
|
)
|
|
1
|
|
|
(745
|
)
|
||||||||
Stock-based Compensation
|
—
|
|
|
57
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
57
|
|
||||||||
Dividends (30 cents per share)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(129
|
)
|
|
—
|
|
|
(129
|
)
|
||||||||
Issuance of Noble Midstream Common Units, Net of Offering Costs
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
299
|
|
|
299
|
|
||||||||
Other
|
—
|
|
|
—
|
|
|
1
|
|
|
(8
|
)
|
|
—
|
|
|
—
|
|
|
(7
|
)
|
||||||||
September 30, 2016
|
$
|
5
|
|
|
$
|
6,417
|
|
|
$
|
(32
|
)
|
|
$
|
(696
|
)
|
|
$
|
3,851
|
|
|
$
|
300
|
|
|
$
|
9,845
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
December 31, 2014
|
$
|
4
|
|
|
$
|
3,624
|
|
|
$
|
(90
|
)
|
|
$
|
(671
|
)
|
|
$
|
7,458
|
|
|
$
|
—
|
|
|
$
|
10,325
|
|
|
Net Loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(413
|
)
|
|
—
|
|
|
(413
|
)
|
||||||||
Rosetta Merger
|
1
|
|
|
1,528
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,529
|
|
||||||||
Stock-based Compensation
|
—
|
|
|
69
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
69
|
|
||||||||
Dividends (54 cents per share)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(214
|
)
|
|
—
|
|
|
(214
|
)
|
||||||||
Issuance of Noble Energy Common Stock, Net of Offering Costs
|
—
|
|
|
1,112
|
|
|
—
|
|
|
—
|
|
—
|
|
—
|
|
|
—
|
|
|
1,112
|
|
|||||||
Other
|
—
|
|
|
9
|
|
|
53
|
|
|
(20
|
)
|
|
—
|
|
|
—
|
|
|
42
|
|
||||||||
September 30, 2015
|
$
|
5
|
|
|
$
|
6,342
|
|
|
$
|
(37
|
)
|
|
$
|
(691
|
)
|
|
$
|
6,831
|
|
|
$
|
—
|
|
|
$
|
12,450
|
|
|
Three Months Ended
September 30, |
|
Nine Months Ended
September 30, |
||||||||||||
(millions)
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Production Expense
|
|
|
|
|
|
|
|
|
|
||||||
Lease Operating Expense
|
$
|
131
|
|
|
$
|
133
|
|
|
$
|
412
|
|
|
$
|
419
|
|
Production and Ad Valorem Taxes
|
30
|
|
|
28
|
|
|
73
|
|
|
89
|
|
||||
Transportation and Gathering Expense
(1)
|
113
|
|
|
86
|
|
|
335
|
|
|
207
|
|
||||
Total
|
$
|
274
|
|
|
$
|
247
|
|
|
$
|
820
|
|
|
$
|
715
|
|
Other Operating (Income) Expense, Net
|
|
|
|
|
|
|
|
|
|
||||||
(Gain) Loss on Asset Due to Terminated Contract
(2)
|
$
|
(3
|
)
|
|
$
|
—
|
|
|
$
|
44
|
|
|
$
|
—
|
|
Marketing and Processing Expense, Net
(3)
|
20
|
|
|
10
|
|
|
58
|
|
|
25
|
|
||||
Loss on Divestitures
|
—
|
|
|
—
|
|
|
23
|
|
|
—
|
|
||||
Corporate Restructuring Expense
|
—
|
|
|
21
|
|
|
—
|
|
|
39
|
|
||||
Purchase Price Allocation Adjustment
(4)
|
—
|
|
|
—
|
|
|
(25
|
)
|
|
—
|
|
||||
Gain on Extinguishment of Debt
(5)
|
—
|
|
|
—
|
|
|
(80
|
)
|
|
—
|
|
||||
Asset Impairments
|
—
|
|
|
—
|
|
|
—
|
|
|
43
|
|
||||
Inventory Adjustment
(6)
|
14
|
|
|
—
|
|
|
14
|
|
|
—
|
|
||||
Building Exit Cost
|
4
|
|
|
18
|
|
|
8
|
|
|
18
|
|
||||
Rosetta Merger Expenses
|
—
|
|
|
71
|
|
|
—
|
|
|
73
|
|
||||
Pension Plan Expense
|
—
|
|
|
67
|
|
|
—
|
|
|
88
|
|
||||
Stacked Drilling Rig Expense
|
3
|
|
|
13
|
|
|
8
|
|
|
20
|
|
||||
Other, Net
|
7
|
|
|
(12
|
)
|
|
16
|
|
|
4
|
|
||||
Total
|
$
|
45
|
|
|
$
|
188
|
|
|
$
|
66
|
|
|
$
|
310
|
|
Other Non-Operating Expense (Income), Net
|
|
|
|
|
|
|
|
|
|
||||||
Deferred Compensation Expense (Income)
(7)
|
$
|
2
|
|
|
$
|
(13
|
)
|
|
$
|
7
|
|
|
$
|
(19
|
)
|
Other (Income) Expense, Net
|
(3
|
)
|
|
1
|
|
|
(4
|
)
|
|
(1
|
)
|
||||
Total
|
$
|
(1
|
)
|
|
$
|
(12
|
)
|
|
$
|
3
|
|
|
$
|
(20
|
)
|
(1)
|
Certain of our revenue received from purchasers was historically presented with deductions for transportation, gathering, fractionation or processing costs. Beginning in 2016, we have changed our presentation of revenue to no longer include these expenses as deductions from revenue. These costs are now included within production expense. Prior year amounts of
$18 million
and
$37 million
for the
three and nine
months ended September 30, 2015 have been reclassified to conform to the current presentation.
|
(2)
|
Amount relates to the termination of a rig contract offshore Falkland Islands as a result of a supplier's non-performance.
See Note
9. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs
and
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Executive Overview - Exploration Program Update
.
|
(3)
|
For the
three and nine
months ended
September 30, 2016
, amount includes
$12 million
and
$39 million
, respectively, of expense due to unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments.
|
(4)
|
Amount relates to an adjustment recorded to the purchase price allocation related to the Rosetta Merger.
See Note
5. Rosetta Merger
.
|
(5)
|
Amount relates to the tendering of senior notes assumed in the Rosetta Merger.
See Note
7. Debt
.
|
(6)
|
Amount relates to an adjustment of inventory to its net realizable value.
|
(7)
|
Amounts represent decreases (increases) in the fair value of shares of our common stock held in a rabbi trust.
|
(millions)
|
September 30,
2016 |
|
December 31,
2015 |
||||
Accounts Receivable, Net
|
|
|
|
||||
Commodity Sales
|
$
|
317
|
|
|
$
|
298
|
|
Joint Interest Billings
|
66
|
|
|
20
|
|
||
Proceeds Receivable
(1)
|
40
|
|
|
—
|
|
||
Other
|
86
|
|
|
151
|
|
||
Allowance for Doubtful Accounts
|
(23
|
)
|
|
(19
|
)
|
||
Total
|
$
|
486
|
|
|
$
|
450
|
|
Other Current Assets
|
|
|
|
|
|
||
Inventories, Materials and Supplies
|
$
|
75
|
|
|
$
|
92
|
|
Inventories, Crude Oil
|
25
|
|
|
23
|
|
||
Assets Held for Sale
(2)
|
214
|
|
|
67
|
|
||
Prepaid Expenses and Other Current Assets
|
38
|
|
|
34
|
|
||
Total
|
$
|
352
|
|
|
$
|
216
|
|
Other Noncurrent Assets
|
|
|
|
|
|
||
Investments in Unconsolidated Subsidiaries
|
$
|
460
|
|
|
$
|
453
|
|
Mutual Fund Investments
|
83
|
|
|
90
|
|
||
Commodity Derivative Assets
|
—
|
|
|
10
|
|
||
Other Assets
|
44
|
|
|
67
|
|
||
Total
|
$
|
587
|
|
|
$
|
620
|
|
Other Current Liabilities
|
|
|
|
|
|
||
Production and Ad Valorem Taxes
|
$
|
121
|
|
|
$
|
166
|
|
Commodity Derivative Liabilities
|
27
|
|
|
—
|
|
||
Income Taxes Payable
|
168
|
|
|
86
|
|
||
Asset Retirement Obligations
|
128
|
|
|
128
|
|
||
Interest Payable
|
93
|
|
|
83
|
|
||
Current Portion of Capital Lease Obligations
|
61
|
|
|
53
|
|
||
Other
|
144
|
|
|
161
|
|
||
Total
|
$
|
742
|
|
|
$
|
677
|
|
Other Noncurrent Liabilities
|
|
|
|
|
|
||
Deferred Compensation Liabilities
|
$
|
232
|
|
|
$
|
217
|
|
Asset Retirement Obligations
|
820
|
|
|
861
|
|
||
Production and Ad Valorem Taxes
|
35
|
|
|
68
|
|
||
Commodity Derivative Liabilities
|
8
|
|
|
—
|
|
||
Other
|
44
|
|
|
73
|
|
||
Total
|
$
|
1,139
|
|
|
$
|
1,219
|
|
(1)
|
Amount relates to proceeds to be received from our farm-out of
35%
interest in Block 12 offshore Cyprus.
See Note
4. Divestitures
.
|
(2)
|
Assets held for sale at
September 30, 2016
primarily include
$127 million
relating to our
3%
working interest in the Tamar project, offshore Israel, and certain producing and undeveloped assets in the DJ Basin and Eagle Ford Shale, onshore US. Assets held for sale at December 31, 2015 include the Karish and Tanin natural gas discoveries, offshore Israel.
See Note
4. Divestitures
.
|
•
|
1,527,584
common units, representing a
4.8%
limited partner interest in Noble Midstream;
|
•
|
15,902,584
subordinated units, representing an approximate
50.0%
limited partner interest in Noble Midstream;
|
•
|
incentive distribution rights in Noble Midstream; and
|
•
|
the right to receive a cash distribution from Noble Midstream.
|
•
|
entered into a purchase and sale agreement for the divestiture of certain producing and non-producing crude oil and natural gas interests covering approximately
33,100
net acres in the DJ Basin for
$505 million
, subject to customary closing adjustments. We have received proceeds of
$486 million
and expect to receive the remaining proceeds, subject to post-close adjustments, in mid-2017. Proceeds received were applied to the field's basis with no recognition of gain or loss;
|
•
|
closed the divestiture of our Bowdoin property in northern Montana, generating proceeds of
$43 million
, and recognized a
$23 million
loss on sale of assets;
|
•
|
closed a cashless acreage exchange within the DJ Basin to receive approximately
11,700
net acres within our Wells Ranch development area of the field in exchange for approximately
13,500
net acres primarily from our Bronco area of the field. No gain or loss was recognized for the transaction; and
|
•
|
sold certain other non-producing interests within the DJ Basin, generating net proceeds of
$20 million
, and other certain smaller onshore US property packages, resulting in net proceeds of
$19 million
, during the
first nine months of 2016
. Proceeds received were applied to the respective field's basis with no recognition of gain or loss.
|
|
(in millions, except stock price)
|
||
Shares of Noble Energy common stock issued to Rosetta shareholders
|
41
|
|
|
Noble Energy common stock price on July 20, 2015
|
$
|
36.97
|
|
Fair value of common stock issued
|
$
|
1,518
|
|
Plus: Fair value of Rosetta's restricted stock awards and performance awards assumed
|
10
|
|
|
Plus: Rosetta stock options assumed
|
1
|
|
|
Total purchase price
|
1,529
|
|
|
Plus: Liabilities assumed by Noble Energy
|
|
||
Accounts Payable
|
100
|
|
|
Current Liabilities
|
37
|
|
|
Long-Term Debt
|
1,992
|
|
|
Other Long Term Liabilities
|
23
|
|
|
Asset Retirement Obligation
|
27
|
|
|
Total purchase price plus liabilities assumed
|
$
|
3,708
|
|
|
|
||
Fair Value of Rosetta Assets
|
|
||
Cash and Equivalents
|
$
|
61
|
|
Other Current Assets
|
76
|
|
|
Derivative Instruments
|
209
|
|
|
Oil and Gas Properties
|
|
||
Proved Reserves
|
1,613
|
|
|
Undeveloped Leaseholds
|
1,355
|
|
|
Gathering & Processing Assets
|
207
|
|
|
Asset Retirement Obligation
|
27
|
|
|
Other Property Plant and Equipment
|
5
|
|
|
Long Term Deferred Tax Asset
|
17
|
|
|
Goodwill
(1)
|
138
|
|
|
Total Asset Value
|
$
|
3,708
|
|
(1)
|
As of December 31, 2015, our preliminary purchase price allocation reflected goodwill of
$163 million
based on the fair value of assets acquired and liabilities assumed at the Rosetta Merger date. In conducting our goodwill impairment test as of December 31, 2015, we determined that our goodwill balance was no longer recoverable and fully impaired it, resulting in a goodwill impairment charge in fourth quarter 2015. In second quarter 2016, we finalized the purchase price allocation and recorded a
$25 million
gain to Other Operating Expense, Net driven by adjustments made based on the filing of the final Rosetta federal income tax return for the period ending on the Rosetta Merger date.
|
|
Three Months Ended
September 30, |
Nine Months Ended
September 30, |
||||||||||
(in millions, except per share amounts)
|
2016
(1)
|
2015
|
2016
(1)
|
2015
|
||||||||
Revenues
|
$
|
910
|
|
$
|
846
|
|
$
|
2,481
|
|
$
|
2,619
|
|
Net Loss Attributable to Noble Energy
|
$
|
(144
|
)
|
$
|
(202
|
)
|
$
|
(746
|
)
|
$
|
(338
|
)
|
|
|
|
|
|
||||||||
Net Loss Attributable to Noble Energy Per Share of Common Stock
|
|
|
|
|
||||||||
Basic
|
$
|
(0.33
|
)
|
$
|
(0.44
|
)
|
$
|
(1.73
|
)
|
$
|
(0.79
|
)
|
Diluted
|
$
|
(0.33
|
)
|
$
|
(0.44
|
)
|
$
|
(1.73
|
)
|
$
|
(0.79
|
)
|
(1)
|
No pro forma adjustments were made for the period as the acquisition is included in the Company's historical results.
|
|
|
|
|
Swaps
|
|
Collars
|
|||||||||||
Settlement
Period
|
Type of Contract
|
Index
|
Bbls Per
Day
|
Weighted
Average
Fixed
Price
|
|
Weighted
Average
Short Put
Price
|
Weighted
Average
Floor
Price
|
Weighted
Average
Ceiling
Price
|
|||||||||
2016
|
Call Option
(1)
|
NYMEX WTI
|
5,000
|
|
$
|
—
|
|
|
$
|
—
|
|
$
|
—
|
|
$
|
54.16
|
|
2016
|
Swaps
|
NYMEX WTI
|
16,000
|
|
67.69
|
|
|
—
|
|
—
|
|
—
|
|
||||
2016
|
Swaps
(2)
|
(3)
|
6,000
|
|
90.28
|
|
|
—
|
|
—
|
|
—
|
|
||||
2016
|
Two-Way Collars
|
NYMEX WTI
|
10,000
|
|
—
|
|
|
—
|
|
40.50
|
|
53.42
|
|
||||
2016
|
Three-Way Collars
|
NYMEX WTI
|
8,000
|
|
—
|
|
|
54.50
|
|
65.63
|
|
79.03
|
|
||||
2016
|
Swaps
|
Dated Brent
|
9,000
|
|
97.96
|
|
|
—
|
|
—
|
|
—
|
|
||||
2016
|
Three-Way Collars
|
Dated Brent
|
8,000
|
|
—
|
|
|
72.50
|
|
86.25
|
|
101.79
|
|
||||
1H17
(4)
|
Swaps
|
NYMEX WTI
|
6,000
|
55.08
|
|
|
—
|
|
—
|
|
—
|
|
|||||
1H17
(4)
|
Two-Way Collars
|
NYMEX WTI
|
2,000
|
—
|
|
|
—
|
|
40.00
|
|
50.44
|
|
|||||
1H17
(4)
|
Swaps
|
Dated Brent
|
3,000
|
62.80
|
|
|
—
|
|
—
|
|
—
|
|
|||||
2H17
(4)
|
Call Option
(1)
|
NYMEX WTI
|
3,000
|
—
|
|
|
—
|
|
—
|
|
60.12
|
|
|||||
2H17
(4)
|
Swaptions
(5)
|
Dated Brent
|
3,000
|
—
|
|
|
—
|
|
—
|
|
62.80
|
|
|||||
2H17
(4)
|
Swaptions
(5)
|
NYMEX WTI
|
3,000
|
—
|
|
|
—
|
|
—
|
|
50.05
|
|
|||||
2017
|
Two-Way Collars
|
NYMEX WTI
|
7,000
|
—
|
|
|
—
|
|
40.00
|
|
53.29
|
|
|||||
2017
|
Call Option
(1)
|
NYMEX WTI
|
3,000
|
—
|
|
|
—
|
|
—
|
|
57.00
|
|
|||||
2017
|
Swaptions
(5)
|
NYMEX WTI
|
4,000
|
—
|
|
|
—
|
|
—
|
|
47.34
|
|
|||||
2017
|
Three-Way Collars
|
NYMEX WTI
|
15,000
|
—
|
|
|
36.33
|
|
46.33
|
|
60.68
|
|
|||||
2017
|
Three-Way Collars
|
Dated Brent
|
2,000
|
—
|
|
|
35.00
|
|
45.00
|
|
66.33
|
|
|||||
2018
|
Three-Way Collars
|
Dated Brent
|
3,000
|
|
—
|
|
|
40.00
|
|
50.00
|
|
70.41
|
|
(1)
|
We have entered into crude oil derivative enhanced swaps with strike prices that are above the market value as of trade commencement. To effect the enhanced swap structure, we sold call options to the applicable counterparty to receive the above market terms.
|
(2)
|
Includes derivative instruments assumed by our subsidiary, NBL Texas, LLC, in connection with the Rosetta Merger.
|
(3)
|
The indices for these derivative instruments are NYMEX WTI and Argus LLS.
|
(4)
|
We have entered into crude oil swap contracts for portions of 2017 resulting in the difference in hedge volumes for the full year.
|
(5)
|
We have entered into certain derivative contracts (swaptions), which give counterparties the option to extend with similar terms for an additional 6-month or 12-month period.
|
|
|
|
|
Swaps
|
|
Collars
|
|||||||
Settlement
Period
|
Type of Contract
|
Index
|
MMBtu
Per Day
|
Weighted
Average
Fixed
Price
|
|
Weighted
Average
Short Put
Price
|
Weighted
Average
Floor
Price
|
Weighted
Average
Ceiling
Price
|
|||||
2016
|
Swaps
|
NYMEX HH
|
70,000
|
|
3.24
|
|
|
—
|
|
—
|
|
—
|
|
2016
|
Two-Way Collars
|
NYMEX HH
|
30,000
|
|
—
|
|
|
—
|
|
3.00
|
|
3.50
|
|
2016
|
Three-Way Collars
|
NYMEX HH
|
90,000
|
|
—
|
|
|
2.83
|
|
3.42
|
|
3.90
|
|
2016
|
Swaps
(1)
|
(2)
|
30,000
|
|
4.04
|
|
|
—
|
|
—
|
|
—
|
|
2016
|
Two-Way Collars
(1)
|
(2)
|
30,000
|
|
—
|
|
|
—
|
|
3.50
|
|
5.60
|
|
1H17
|
Swaps
|
NYMEX HH
|
30,000
|
2.92
|
|
|
—
|
|
—
|
|
—
|
|
|
2H17
|
Swaptions
(3)
|
NYMEX HH
|
30,000
|
—
|
|
|
—
|
|
—
|
|
2.92
|
|
|
2017
|
Swaps
|
NYMEX HH
|
30,000
|
3.15
|
|
|
—
|
|
—
|
|
—
|
|
|
2017
|
Swaptions
(3)
|
NYMEX HH
|
60,000
|
—
|
|
|
—
|
|
—
|
|
3.14
|
|
|
2017
|
Three-Way Collars
|
NYMEX HH
|
180,000
|
—
|
|
|
2.50
|
|
2.93
|
|
3.58
|
|
|
2017
|
Two-Way Collars
|
NYMEX HH
|
70,000
|
—
|
|
|
—
|
|
2.93
|
|
3.32
|
|
|
2018
|
Three-Way Collars
|
NYMEX HH
|
70,000
|
—
|
|
|
2.50
|
|
2.80
|
|
3.76
|
|
(1)
|
Includes derivative instruments assumed by our subsidiary, NBL Texas, LLC, in connection with the Rosetta Merger.
|
(2)
|
The index for these derivative instruments is Houston Ship Channel.
|
(3)
|
We have entered into certain natural gas derivative contracts (swaptions), which give counterparties the option to extend with similar terms for an additional 6-month or 12-month period.
|
|
Fair Value of Derivative Instruments
|
||||||||||||||||||||||
|
Asset Derivative Instruments
|
|
Liability Derivative Instruments
|
||||||||||||||||||||
|
September 30,
2016 |
|
December 31,
2015 |
|
September 30,
2016 |
|
December 31,
2015 |
||||||||||||||||
(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
|
|
$
|
120
|
|
|
Current Assets
|
|
$
|
582
|
|
|
Current Liabilities
|
|
$
|
27
|
|
|
Current Liabilities
|
|
$
|
—
|
|
|
Noncurrent Assets
|
|
—
|
|
|
Noncurrent Assets
|
|
10
|
|
|
Noncurrent Liabilities
|
|
8
|
|
|
Noncurrent Liabilities
|
|
—
|
|
||||
Total
|
|
|
$
|
120
|
|
|
|
|
$
|
592
|
|
|
|
|
$
|
35
|
|
|
|
|
$
|
—
|
|
|
Three Months Ended
September 30, |
|
Nine Months Ended
September 30, |
||||||||||||
(millions)
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Cash Received in Settlement of Commodity Derivative Instruments
|
|
|
|
|
|
|
|
||||||||
Crude Oil
|
$
|
(119
|
)
|
|
$
|
(235
|
)
|
|
$
|
(395
|
)
|
|
$
|
(578
|
)
|
Natural Gas
|
(13
|
)
|
|
(42
|
)
|
|
(59
|
)
|
|
(98
|
)
|
||||
NGLs
|
—
|
|
|
(7
|
)
|
|
—
|
|
|
(7
|
)
|
||||
Total Cash Received in Settlement of Commodity Derivative Instruments
|
(132
|
)
|
|
(284
|
)
|
|
(454
|
)
|
|
(683
|
)
|
||||
Non-cash Portion of Loss on Commodity Derivative Instruments
|
|
|
|
|
|
|
|
||||||||
Crude Oil
|
80
|
|
|
4
|
|
|
441
|
|
|
301
|
|
||||
Natural Gas
|
(3
|
)
|
|
3
|
|
|
66
|
|
|
41
|
|
||||
NGLs
|
—
|
|
|
10
|
|
|
—
|
|
|
10
|
|
||||
Total Non-cash Portion of Loss on Commodity Derivative Instruments
|
77
|
|
|
17
|
|
|
507
|
|
|
352
|
|
||||
(Gain) Loss on Commodity Derivative Instruments
|
|
|
|
|
|
|
|
||||||||
Crude Oil
|
(39
|
)
|
|
(231
|
)
|
|
46
|
|
|
(277
|
)
|
||||
Natural Gas
|
(16
|
)
|
|
(39
|
)
|
|
7
|
|
|
(57
|
)
|
||||
NGLs
|
—
|
|
|
3
|
|
|
—
|
|
|
3
|
|
||||
Total Loss (Gain) on Commodity Derivative Instruments
|
$
|
(55
|
)
|
|
$
|
(267
|
)
|
|
$
|
53
|
|
|
$
|
(331
|
)
|
|
September 30,
2016 |
|
December 31,
2015 |
|||||||||||
(millions, except percentages)
|
Debt
|
|
Interest Rate
|
|
Debt
|
|
Interest Rate
|
|||||||
Revolving Credit Facility, due August 27, 2020
|
$
|
—
|
|
|
—
|
%
|
|
$
|
—
|
|
|
—
|
%
|
|
Noble Midstream Revolving Credit Facility, due September 20, 2021
|
—
|
|
|
—
|
%
|
|
—
|
|
—
|
|
—
|
%
|
||
Capital Lease and Other Obligations
|
368
|
|
|
—
|
%
|
|
403
|
|
|
—
|
%
|
|||
Term Loan Facility, due January 6, 2019
|
1,400
|
|
|
1.70
|
%
|
|
—
|
|
|
—
|
%
|
|||
8.25% Senior Notes, due March 1, 2019
|
1,000
|
|
|
8.25
|
%
|
|
1,000
|
|
|
8.25
|
%
|
|||
5.625% Senior Notes, due May 1, 2021
|
379
|
|
|
5.625
|
%
|
|
693
|
|
|
5.625
|
%
|
|||
4.15% Senior Notes, due December 15, 2021
|
1,000
|
|
|
4.15
|
%
|
|
1,000
|
|
|
4.15
|
%
|
|||
5.875% Senior Notes, due June 1, 2022
|
18
|
|
|
5.875
|
%
|
|
597
|
|
|
5.875
|
%
|
|||
7.25% Senior Notes, due October 15, 2023
|
100
|
|
|
7.25
|
%
|
|
100
|
|
|
7.25
|
%
|
|||
5.875% Senior Notes, due June 1, 2024
|
8
|
|
|
5.875
|
%
|
|
499
|
|
|
5.875
|
%
|
|||
3.90% Senior Notes, due November 15, 2024
|
650
|
|
|
3.90
|
%
|
|
650
|
|
|
3.90
|
%
|
|||
8.00% Senior Notes, due April 1, 2027
|
250
|
|
|
8.00
|
%
|
|
250
|
|
|
8.00
|
%
|
|||
6.00% Senior Notes, due March 1, 2041
|
850
|
|
|
6.00
|
%
|
|
850
|
|
|
6.00
|
%
|
|||
5.25% Senior Notes, due November 15, 2043
|
1,000
|
|
|
5.25
|
%
|
|
1,000
|
|
|
5.25
|
%
|
|||
5.05% Senior Notes, due November 15, 2044
|
850
|
|
|
5.05
|
%
|
|
850
|
|
|
5.05
|
%
|
|||
7.25% Senior Debentures, due August 1, 2097
|
84
|
|
|
7.25
|
%
|
|
84
|
|
|
7.25
|
%
|
|||
Total
|
7,957
|
|
|
|
|
7,976
|
|
|
|
|
||||
Unamortized Discount
|
(23
|
)
|
|
|
|
|
(24
|
)
|
|
|
|
|||
Unamortized Premium
|
17
|
|
|
|
|
113
|
|
|
|
|||||
Unamortized Debt Issuance Costs
|
(36
|
)
|
|
|
|
(36
|
)
|
|
|
|||||
Total Debt, Net of Unamortized Discount, Premium and Debt Issuance Costs
|
7,915
|
|
|
|
|
|
8,029
|
|
|
|
|
|||
Less Amounts Due Within One Year
|
|
|
|
|
|
|
|
|
|
|
|
|||
Capital Lease Obligations
|
(61
|
)
|
|
|
|
|
(53
|
)
|
|
|
|
|||
Long-Term Debt Due After One Year
|
$
|
7,854
|
|
|
|
|
|
$
|
7,976
|
|
|
|
|
•
|
in the case of base rate borrowings, a rate equal to the highest of (1) the prime rate, (2) the greater of the federal funds rate or the overnight bank funding rate, plus
0.5%
and (3) the LIBOR for an interest period of one month plus
1.00%
; or
|
•
|
in the case of LIBOR borrowings, the offered rate per annum for deposits of dollars for the applicable interest period.
|
|
Fair Value Measurements Using
|
|
|
|
|
||||||||||||||
|
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
|
||||||||||
(millions)
|
|
|
|
|
|
|
|
|
|
||||||||||
September 30, 2016
|
|
|
|
|
|
|
|
|
|
||||||||||
Financial Assets
|
|
|
|
|
|
|
|
|
|
||||||||||
Mutual Fund Investments
|
$
|
83
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
83
|
|
Commodity Derivative Instruments
|
—
|
|
|
133
|
|
|
—
|
|
|
(13
|
)
|
|
120
|
|
|||||
Financial Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Commodity Derivative Instruments
|
—
|
|
|
(48
|
)
|
|
—
|
|
|
13
|
|
|
(35
|
)
|
|||||
Portion of Deferred Compensation Liability Measured at Fair Value
|
(105
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(105
|
)
|
|||||
Portion of Stock Based Compensation Liability Measured at Fair Value
|
(6
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6
|
)
|
|||||
December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Financial Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Mutual Fund Investments
|
$
|
90
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
90
|
|
Commodity Derivative Instruments
|
—
|
|
|
600
|
|
|
—
|
|
|
(8
|
)
|
|
592
|
|
|||||
Financial Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Commodity Derivative Instruments
|
—
|
|
|
(8
|
)
|
|
—
|
|
|
8
|
|
|
—
|
|
|||||
Portion of Deferred Compensation Liability Measured at Fair Value
|
(98
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(98
|
)
|
(1)
|
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.
|
|
Fair Value Measurements Using
|
|
|
|
|
||||||||||||||
|
Quoted Prices in
Active Markets (Level 1) |
|
Significant Other
Observable Inputs (Level 2) |
|
Significant
Unobservable Inputs (Level 3) |
|
Net Book Value
(1)
|
|
Total Pre-tax (Non-cash) Impairment Loss
|
||||||||||
(millions)
|
|
|
|
|
|
|
|
|
|
||||||||||
Nine Months Ended September 30, 2016
|
|
|
|
|
|
|
|
|
|||||||||||
Material and Supplies Inventory Adjustment
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
91
|
|
|
$
|
105
|
|
|
$
|
14
|
|
Loss on Divestitures
|
—
|
|
|
—
|
|
|
42
|
|
|
65
|
|
|
23
|
|
|||||
Impaired Oil and Gas Properties
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Nine Months Ended September 30, 2015
|
|
|
|
|
|
|
|
|
|||||||||||
Impaired Oil and Gas Properties
|
—
|
|
|
—
|
|
|
—
|
|
|
43
|
|
|
43
|
|
(1)
|
Amount represents net book value at the date of assessment.
|
|
September 30,
2016 |
|
December 31,
2015 |
||||||||||||
(millions)
|
Carrying Amount
|
|
Fair Value
|
|
Carrying Amount
|
|
Fair Value
|
||||||||
Long-Term Debt, Net
(1)
|
$
|
7,547
|
|
|
$
|
7,976
|
|
|
$
|
7,626
|
|
|
$
|
7,105
|
|
(1)
|
Net of unamortized discount, premium and debt issuance costs and excludes capital lease and other obligations.
|
(millions)
|
Nine Months Ended September 30, 2016
|
||
Capitalized Exploratory Well Costs, Beginning of Period
|
$
|
1,353
|
|
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves
|
83
|
|
|
Divestitures and Other
(1)
|
(143
|
)
|
|
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves
|
(1
|
)
|
|
Capitalized Exploratory Well Costs Charged to Expense
(2)
|
(83
|
)
|
|
Capitalized Exploratory Well Costs, End of Period
|
$
|
1,209
|
|
(1)
|
Includes
$143 million
relating to our farm-down of a
35%
interest in Block 12 offshore Cyprus to a new partner.
|
(2)
|
Includes amounts related to contract termination offshore Falkland Islands, Dolphin 1 exploratory well offshore Israel, and Silvergate exploratory well deepwater Gulf of Mexico.
|
(millions)
|
September 30,
2016 |
|
December 31,
2015 |
||||
Exploratory Well Costs Capitalized for a Period of One Year or Less
|
$
|
91
|
|
|
$
|
95
|
|
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling
|
1,118
|
|
|
1,258
|
|
||
Balance at End of Period
|
$
|
1,209
|
|
|
$
|
1,353
|
|
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling
|
13
|
|
|
14
|
|
|
|
|
|
||
(millions)
|
Total by Project
|
|
Progress
|
||
Country/Project:
|
|
|
|
||
Deepwater Gulf of Mexico
|
|
|
|
||
Troubadour
|
$
|
52
|
|
|
Evaluating development scenarios for this 2013 natural gas discovery including subsea tieback to existing infrastructure.
|
Katmai
|
97
|
|
|
Evaluating development scenarios for this 2014 crude oil discovery. In second quarter 2016, drilling operations at the Katmai 2 appraisal well, located in Green Canyon Block 39, were temporarily abandoned as a result of encountering high pressure in the untested fault block. We are assessing plans to progress appraisal and are evaluating tie-back options.
|
|
Offshore Equatorial Guinea Blocks I and O
|
|
|
|
|
|
Diega (Block I) and Carmen (Block O)
|
240
|
|
|
Evaluating regional development scenarios for this 2008 crude oil discovery. We drilled subsequent appraisal wells. During 2014, we conducted additional seismic activity over Blocks I and O and in early 2016, we began analyzing, interpreting and evaluating the acquired seismic data.
|
|
Carla (Block O)
|
184
|
|
|
Evaluating regional development scenarios for this 2011 crude oil discovery. We drilled subsequent appraisal wells. During 2014, we conducted additional seismic activity over Blocks I and O and in early 2016, we began analyzing, interpreting and evaluating the acquired seismic data.
|
|
Yolanda (Block I)
|
22
|
|
|
A data exchange agreement for the 2007 Yolanda condensate and natural gas discovery has been executed between Equatorial Guinea and Cameroon. Our natural gas development team is working with the governments of Equatorial Guinea and Cameroon to evaluate natural gas monetization options for both Yolanda and YoYo (Cameroon) discoveries.
|
|
Felicita (Block O)
|
45
|
|
|
Evaluating regional development scenarios for this 2008 gas discovery. During 2014, we conducted additional seismic activity over Blocks I and O and in early 2016, we began analyzing, interpreting and evaluating the acquired seismic data.
|
|
Offshore Cameroon
|
|
|
|
|
|
YoYo (YoYo Block)
|
53
|
|
|
A data exchange agreement for the 2007 YoYo condensate and natural gas discovery has been executed between Equatorial Guinea and Cameroon. Our natural gas development team is working with the governments of Equatorial Guinea and Cameroon to evaluate natural gas monetization options for both Yolanda (Equatorial Guinea) and YoYo discoveries.
|
|
Offshore Israel
|
|
|
|
|
|
Leviathan
|
196
|
|
|
Our development plan was approved by the Government of Israel and we are engaged in natural gas marketing activities to meet both Israeli domestic and regional export demands.
|
|
Leviathan-1 Deep
|
84
|
|
|
The well did not reach the target interval in 2012. We are developing future drilling plans to test this deep oil concept, which is held by the Leviathan Development and Production Leases.
|
|
Dalit
|
31
|
|
|
Our development plan was approved by the Government of Israel to develop this 2009 natural gas discovery with a tie-in to existing infrastructure at Tamar.
|
|
Offshore Cyprus
|
|
|
|
Cyprus
|
88
|
|
|
During first quarter 2016, we received proceeds of $131 million from our 35% farm-down of interest with a partner in Block 12. In second quarter 2016, we submitted an updated development plan and continue to work with the Government of Cyprus to obtain approval of the development plan and the subsequent issuance of an Exploitation License. Receiving an Exploitation License will allow us and our partners to perform the necessary engineering and design studies and progress the project to final investment decision.
|
|
Other
|
|
|
|
|
|
Individual Projects Less than $20 million
|
26
|
|
|
Continuing to assess and evaluate wells.
|
|
Total
|
$
|
1,118
|
|
|
|
|
Nine Months Ended
September 30, |
||||||
(millions)
|
2016
|
|
2015
|
||||
Asset Retirement Obligations, Beginning Balance
|
$
|
989
|
|
|
$
|
751
|
|
Liabilities Incurred
|
5
|
|
|
54
|
|
||
Liabilities Settled
|
(87
|
)
|
|
(29
|
)
|
||
Revision of Estimate
|
4
|
|
|
79
|
|
||
Accretion Expense
(1)
|
37
|
|
|
32
|
|
||
Asset Retirement Obligations, Ending Balance
|
$
|
948
|
|
|
$
|
887
|
|
(1)
|
Accretion expense is included in Depreciation, Depletion and Amortization (DD&A)
expense in the consolidated statements of
operations.
|
|
Three Months Ended
September 30, |
|
Nine Months Ended
September 30, |
||||||||||||
(millions, except per share amounts)
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Net Loss Attributable to Noble Energy
|
$
|
(144
|
)
|
|
$
|
(283
|
)
|
|
$
|
(746
|
)
|
|
$
|
(413
|
)
|
|
|
|
|
|
|
|
|
||||||||
Weighted Average Number of Shares Outstanding, Basic
(1)
|
430
|
|
|
420
|
|
|
430
|
|
|
392
|
|
||||
Weighted Average Number of Shares Outstanding, Diluted
(2)
|
430
|
|
|
420
|
|
|
430
|
|
|
392
|
|
||||
Loss Per Share, Basic
|
$
|
(0.33
|
)
|
|
$
|
(0.67
|
)
|
|
$
|
(1.73
|
)
|
|
$
|
(1.05
|
)
|
Loss Per Share, Diluted
|
(0.33
|
)
|
|
(0.67
|
)
|
|
(1.73
|
)
|
|
(1.05
|
)
|
||||
Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above
|
14
|
|
|
14
|
|
|
15
|
|
|
11
|
|
(1)
|
The weighted average number of shares outstanding includes the weighted average shares of common stock issued in connection with the underwritten public offering of
24.15 million
shares of Noble Energy common stock in first quarter 2015 and issued in connection with the exchange of approximately
41 million
shares for all outstanding shares of Rosetta common stock on July 20, 2015.
|
(2)
|
For all periods, all outstanding options and non-vested restricted shares have been excluded from the calculation of diluted loss per share as Noble Energy incurred a net loss. Therefore, inclusion of outstanding options and non-vested restricted shares in the calculation of diluted loss per share would be anti-dilutive.
|
|
Three Months Ended
September 30, |
|
Nine Months Ended
September 30, |
||||||||||||
(millions)
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Current
|
$
|
148
|
|
|
$
|
(45
|
)
|
|
$
|
213
|
|
|
$
|
64
|
|
Deferred
|
(285
|
)
|
|
69
|
|
|
(699
|
)
|
|
(244
|
)
|
||||
Total Income Tax (Benefit) Provision
|
$
|
(137
|
)
|
|
$
|
24
|
|
|
$
|
(486
|
)
|
|
$
|
(180
|
)
|
Effective Tax Rate
|
48.9
|
%
|
|
(9.3
|
)%
|
|
39.5
|
%
|
|
30.4
|
%
|
•
|
a higher loss before income taxes for the first nine months of 2016 as compared with the first nine months of 2015;
|
•
|
•
|
the change in our permanent reinvestment assumption, noted above, which resulted in additional deferred income tax expense (net of estimated foreign tax credits) being recorded on certain income items, including income from equity method investees and increased earnings in our foreign jurisdictions with rates that vary from the US statutory rate, which reduced the income tax benefit.
|
(millions)
|
Consolidated
|
|
United
States
|
|
West
Africa
|
|
Eastern
Mediterranean
|
|
Other Int'l &
Corporate
|
||||||||||
Three Months Ended September 30, 2016
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues from Third Parties
|
$
|
882
|
|
|
$
|
639
|
|
|
$
|
93
|
|
|
$
|
150
|
|
|
$
|
—
|
|
Income from Equity Method Investees
|
28
|
|
|
8
|
|
|
20
|
|
|
—
|
|
|
—
|
|
|||||
Total Revenues
|
910
|
|
|
647
|
|
|
113
|
|
|
150
|
|
|
—
|
|
|||||
DD&A
|
621
|
|
|
539
|
|
|
46
|
|
|
23
|
|
|
13
|
|
|||||
Gain on Commodity Derivative Instruments
|
(55
|
)
|
|
(48
|
)
|
|
(7
|
)
|
|
—
|
|
|
—
|
|
|||||
(Loss) Income Before Income Taxes
|
(280
|
)
|
|
(407
|
)
|
|
47
|
|
|
135
|
|
|
(55
|
)
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Three Months Ended September 30, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Revenues from Third Parties
|
$
|
783
|
|
|
$
|
510
|
|
|
$
|
120
|
|
|
$
|
152
|
|
|
$
|
1
|
|
Income from Equity Method Investees
|
36
|
|
|
16
|
|
|
20
|
|
|
—
|
|
|
—
|
|
|||||
Total Revenues
|
819
|
|
|
526
|
|
|
140
|
|
|
152
|
|
|
1
|
|
|||||
DD&A
|
539
|
|
|
437
|
|
|
67
|
|
|
22
|
|
|
13
|
|
|||||
Gain on Commodity Derivative Instruments
|
(267
|
)
|
|
(187
|
)
|
|
(80
|
)
|
|
—
|
|
|
—
|
|
|||||
(Loss) Income Before Income Taxes
|
(259
|
)
|
|
(189
|
)
|
|
98
|
|
|
107
|
|
|
(275
|
)
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Nine Months Ended September 30, 2016
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues from Third Parties
|
$
|
2,411
|
|
|
$
|
1,705
|
|
|
$
|
299
|
|
|
$
|
407
|
|
|
$
|
—
|
|
Income from Equity Method Investees
|
70
|
|
|
39
|
|
|
31
|
|
|
—
|
|
|
—
|
|
|||||
Total Revenues
|
2,481
|
|
|
1,744
|
|
|
330
|
|
|
407
|
|
|
—
|
|
|||||
DD&A
|
1,859
|
|
|
1,612
|
|
|
150
|
|
|
62
|
|
|
35
|
|
|||||
Loss on Divestitures
|
23
|
|
|
23
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Loss on Commodity Derivative Instruments
|
53
|
|
|
44
|
|
|
9
|
|
|
—
|
|
|
—
|
|
|||||
(Loss) Income Before Income Taxes
|
(1,231
|
)
|
|
(882
|
)
|
|
74
|
|
|
290
|
|
|
(713
|
)
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Nine Months Ended September 30, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Revenues from Third Parties
|
$
|
2,264
|
|
|
$
|
1,448
|
|
|
$
|
432
|
|
|
$
|
378
|
|
|
$
|
6
|
|
Income from Equity Method Investees
|
60
|
|
|
35
|
|
|
25
|
|
|
—
|
|
|
—
|
|
|||||
Total Revenues
|
2,324
|
|
|
1,483
|
|
|
457
|
|
|
378
|
|
|
6
|
|
|||||
DD&A
|
1,444
|
|
|
1,138
|
|
|
223
|
|
|
52
|
|
|
31
|
|
|||||
Gain on Commodity Derivative Instruments
|
(331
|
)
|
|
(231
|
)
|
|
(100
|
)
|
|
—
|
|
|
—
|
|
|||||
(Loss) Income Before Income Taxes
|
(593
|
)
|
|
(353
|
)
|
|
195
|
|
|
227
|
|
|
(662
|
)
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
September 30, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Total Assets
|
$
|
22,469
|
|
|
$
|
17,752
|
|
|
$
|
1,975
|
|
|
$
|
2,515
|
|
|
$
|
227
|
|
December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Total Assets
|
24,196
|
|
|
18,831
|
|
|
2,299
|
|
|
2,677
|
|
|
389
|
|
•
|
•
|
•
|
Results of Operations
; and
|
•
|
•
|
maintained cost reduction efforts in capital, lease operating expense and general and administrative areas, with sustained efforts to further optimize operational performance in the current commodity price environment (see Cost Reduction Efforts, below);
|
•
|
averaged quarterly total sales volumes of
425
MBoe/d, net, including 270 MBoe/d, net, from onshore US assets;
|
•
|
completed the initial public offering of Noble Midstream common units and generated net proceeds of
$299 million
;
|
•
|
completed an acreage exchange which further enhances our Wells Ranch position in Colorado;
|
•
|
continued to enhance well completion designs across our onshore US assets leading to capital efficiencies;
|
•
|
initiated production on our fourth operated well in the Permian Basin;
|
•
|
set a quarterly sales volume record of
313
MMcfe/d, net, in Israel, primarily reflecting seasonal demand and increased use of natural gas over coal to fuel power generation;
|
•
|
reached a cumulative gross production milestone of one trillion cubic feet from our Tamar field since initial production in first quarter 2013;
|
•
|
continued to work towards a final investment decision of our Leviathan field, including the execution of a natural gas sales agreement with NEPCO (defined below) of up to approximately 120 MMcf/d, net to Noble;
|
•
|
entered into an agreement for the divestiture of 3% working interest in the Tamar field for $369 million;
|
•
|
assumed operatorship of the Thunder Hawk Production Facility which processes production from our Big Bend and Dantzler fields in the Gulf of Mexico; and
|
•
|
completed hook-up and commissioning activities at the Alba B3 compression project, offshore Equatorial Guinea, which commenced production in July 2016.
|
•
|
net loss of
$144 million
, as compared with net loss of
$283 million
for
third
quarter
2015
;
|
•
|
net gain on commodity derivative instruments of
$55 million
, as compared with net gain on commodity derivative instruments of
$267 million
for
third
quarter
2015
;
|
•
|
reduced lease operating expense unit costs by
12%
as compared to
third
quarter
2015
, driven by increased sales volumes and cost efficiencies;
|
•
|
reduced general and administrative expense unit costs by
22%
as compared to
third
quarter
2015
, driven by a decline in total costs as a result of continued cost reduction initiatives and increased sales volumes;
|
•
|
recorded
$81 million
of exploration expense due to the write-off of certain leases and licenses in the Gulf of Mexico and offshore Falkland Islands;
|
•
|
diluted loss per share of
$0.33
, as compared with diluted loss per share of
$0.67
for
third
quarter
2015
;
|
•
|
cash flow provided by operating activities of
$614 million
, as compared with
$520 million
for
third
quarter
2015
;
|
•
|
cash proceeds from divestitures of
$19 million
, as compared with
none
for
third
quarter 2015; and
|
•
|
capital expenditures of
$297 million
, as compared with
$664 million
for
third
quarter
2015
.
|
•
|
ending cash balance of
$1.8 billion
, as compared with
$1.0 billion
at
December 31, 2015
;
|
•
|
total liquidity of approximately
$5.8 billion
at
September 30, 2016
, as compared with
$5.0 billion
at
December 31, 2015
; and
|
•
|
ratio of debt-to-book capital of
45%
at
September 30, 2016
, as compared with
43%
at
December 31, 2015
.
|
•
|
allocated capital towards areas with the most favorable returns at current prices, including focusing resources towards onshore US and Eastern Mediterranean activities, while complementing our capital program through proceeds from asset divestitures;
|
•
|
hedged a portion of our future revenues for 2016 to 2018 in order to mitigate the effects of commodity price volatility;
|
•
|
adjusted the quarterly dividend to 10 cents per common share beginning in first quarter 2016, representing a reduction of 8 cents, or 44%, from 2015 quarterly dividend levels;
|
•
|
engaged in debt refinancing activities in first quarter 2016 by tendering for certain outstanding notes and refinanced with a lower cost three year loan (
1.70%
as of
September 30, 2016
). In late 2015, we also extended our Revolving Credit Facility maturity date from 2018 to 2020;
|
•
|
completed our initial public offering of Noble Midstream common units which provided access to capital markets to support funding of our onshore US midstream investment program; and
|
•
|
prepaid
$850 million
of borrowings under our Term Loan Facility from cash on hand in November 2016.
|
•
|
we have a high-quality, globally diversified portfolio of assets, the majority of which are held by production and provide investment flexibility;
|
•
|
we have hedged a portion of our domestic natural gas and global liquids sales volumes through 2018;
|
•
|
we have significantly reduced our capital investment program which has allowed us to respond to the low commodity price conditions in 2016;
|
•
|
we have achieved substantial cost reductions impacting both operating expenses and capital expenditures;
|
•
|
we have adjusted our quarterly dividend to 10 cents per common share; and
|
•
|
we have robust liquidity of approximately
$5.8 billion
at
September 30, 2016
and ability to access capital markets.
|
•
|
commodity prices which, if subject to further decline, could result in certain current production becoming uneconomic;
|
•
|
overall level and timing of capital expenditures which, as discussed below and dependent upon our drilling success, will impact near-term production volumes;
|
•
|
Israeli industrial and residential demand for electricity, which is largely impacted by weather conditions and conversion of the Israeli electricity portfolio from coal to natural gas;
|
•
|
timing of the divestiture of 3% working interest in the Tamar field which will lower our sales volumes;
|
•
|
timing of crude oil and condensate liftings impacting sales volumes in West Africa;
|
•
|
natural field decline in the onshore US, deepwater Gulf of Mexico and offshore Equatorial Guinea;
|
•
|
potential weather-related volume curtailments due to hurricanes in the deepwater Gulf of Mexico and Gulf Coast areas, or winter storms and flooding impacting onshore US operations;
|
•
|
reliability of support equipment and facilities, pipeline disruptions, and/or potential pipeline and processing facility capacity constraints which may cause restrictions or interruptions in production and/or mid-stream processing;
|
•
|
malfunctions and/or mechanical failures at terminals or other onshore US delivery points;
|
•
|
impact of enhanced completion efforts for onshore US assets;
|
•
|
shut-in of US producing properties if storage capacity becomes unavailable;
|
•
|
drilling and/or completion permit delays due to future regulatory changes; and
|
•
|
purchases of producing properties or divestments of operating assets.
|
|
|
|
|
|
(Decrease) / Increase
from Prior Year |
|||||
(millions)
|
2016
|
|
2015
|
|
||||||
Three Months Ended September 30,
|
|
|
|
|
|
|||||
Oil, Gas and NGL Sales
|
$
|
882
|
|
|
$
|
783
|
|
|
13
|
%
|
Income from Equity Method Investees
|
28
|
|
|
36
|
|
|
(22
|
)%
|
||
Total
|
$
|
910
|
|
|
$
|
819
|
|
|
11
|
%
|
|
|
|
|
|
|
|||||
Nine Months Ended September 30,
|
|
|
|
|
|
|||||
Oil, Gas and NGL Sales
|
$
|
2,411
|
|
|
$
|
2,264
|
|
|
6
|
%
|
Income from Equity Method Investees
|
70
|
|
|
60
|
|
|
17
|
%
|
||
Total
|
$
|
2,481
|
|
|
$
|
2,324
|
|
|
7
|
%
|
|
Sales Volumes
|
|
Average Realized Sales Prices
|
||||||||||||||||||||
|
Crude Oil & Condensate
(MBbl/d)
|
|
Natural
Gas
(MMcf/d)
|
|
NGLs
(MBbl/d)
|
|
Total
(MBoe/d)
(1)
|
|
Crude Oil & Condensate
(Per Bbl)
|
|
Natural
Gas
(Per Mcf)
|
|
NGLs
(Per Bbl)
|
||||||||||
Three Months Ended September 30, 2016
|
|||||||||||||||||||||||
United States
|
99
|
|
|
874
|
|
|
55
|
|
|
299
|
|
|
$
|
41.23
|
|
|
$
|
2.38
|
|
|
$
|
14.70
|
|
Equatorial Guinea
(2)
|
22
|
|
|
261
|
|
|
—
|
|
|
65
|
|
|
43.73
|
|
|
0.27
|
|
|
—
|
|
|||
Israel
|
—
|
|
|
310
|
|
|
—
|
|
|
52
|
|
|
—
|
|
|
5.22
|
|
|
—
|
|
|||
Total Consolidated Operations
|
121
|
|
|
1,445
|
|
|
55
|
|
|
416
|
|
|
41.67
|
|
|
2.61
|
|
|
14.70
|
|
|||
Equity Investees
(3)
|
2
|
|
|
—
|
|
|
7
|
|
|
9
|
|
|
45.72
|
|
|
—
|
|
|
23.65
|
|
|||
Total
|
123
|
|
|
1,445
|
|
|
62
|
|
|
425
|
|
|
$
|
41.75
|
|
|
$
|
2.61
|
|
|
$
|
15.66
|
|
Three Months Ended September 30, 2015
|
|||||||||||||||||||||||
United States
|
83
|
|
|
741
|
|
|
49
|
|
|
255
|
|
|
$
|
42.42
|
|
|
$
|
2.01
|
|
|
$
|
11.37
|
|
Equatorial Guinea
(2)
|
27
|
|
|
231
|
|
|
—
|
|
|
65
|
|
|
45.99
|
|
|
0.27
|
|
|
—
|
|
|||
Israel
|
—
|
|
|
303
|
|
|
—
|
|
|
51
|
|
|
—
|
|
|
5.39
|
|
|
—
|
|
|||
Total Consolidated Operations
|
110
|
|
|
1,275
|
|
|
49
|
|
|
371
|
|
|
43.30
|
|
|
2.50
|
|
|
11.37
|
|
|||
Equity Investees
(3)
|
2
|
|
|
—
|
|
|
6
|
|
|
8
|
|
|
51.41
|
|
|
—
|
|
|
24.86
|
|
|||
Total
|
112
|
|
|
1,275
|
|
|
55
|
|
|
379
|
|
|
$
|
43.44
|
|
|
$
|
2.50
|
|
|
$
|
12.73
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Nine Months Ended September 30, 2016
|
|||||||||||||||||||||||
United States
|
99
|
|
|
902
|
|
|
56
|
|
|
304
|
|
|
$
|
37.23
|
|
|
$
|
2.00
|
|
|
$
|
13.38
|
|
Equatorial Guinea
(2)
|
25
|
|
|
230
|
|
|
—
|
|
|
64
|
|
|
40.74
|
|
|
0.27
|
|
|
—
|
|
|||
Israel
|
—
|
|
|
284
|
|
|
—
|
|
|
48
|
|
|
—
|
|
|
5.19
|
|
|
—
|
|
|||
Total Consolidated Operations
|
124
|
|
|
1,416
|
|
|
56
|
|
|
416
|
|
|
37.94
|
|
|
2.36
|
|
|
13.38
|
|
|||
Equity Investees
(3)
|
2
|
|
|
—
|
|
|
5
|
|
|
7
|
|
|
43.95
|
|
|
—
|
|
|
24.43
|
|
|||
Total
|
126
|
|
|
1,416
|
|
|
61
|
|
|
423
|
|
|
$
|
38.02
|
|
|
$
|
2.36
|
|
|
$
|
14.32
|
|
Nine Months Ended September 30, 2015
|
|||||||||||||||||||||||
United States
|
73
|
|
|
658
|
|
|
34
|
|
|
217
|
|
|
$
|
46.02
|
|
|
$
|
2.20
|
|
|
$
|
13.77
|
|
Equatorial Guinea
(2)
|
29
|
|
|
221
|
|
|
—
|
|
|
66
|
|
|
52.15
|
|
|
0.27
|
|
|
—
|
|
|||
Israel
|
—
|
|
|
254
|
|
|
—
|
|
|
43
|
|
|
—
|
|
|
5.39
|
|
|
—
|
|
|||
Other International
(4)
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
55.52
|
|
|
—
|
|
|
—
|
|
|||
Total Consolidated Operations
|
103
|
|
|
1,133
|
|
|
34
|
|
|
327
|
|
|
47.79
|
|
|
2.54
|
|
|
13.77
|
|
|||
Equity Investees
(3)
|
2
|
|
|
—
|
|
|
5
|
|
|
6
|
|
|
51.67
|
|
|
—
|
|
|
28.77
|
|
|||
Total
|
105
|
|
|
1,133
|
|
|
39
|
|
|
333
|
|
|
$
|
47.85
|
|
|
$
|
2.54
|
|
|
$
|
15.64
|
|
(1)
|
Natural gas is converted on the basis of six Mcf of gas per one barrel of crude oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Given commodity price disparities, the price for a barrel of crude oil equivalent for US natural gas and NGLs 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.
|
(2)
|
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.
|
(3)
|
Volumes represent sales of condensate and LPG from the LPG plant in Equatorial Guinea. See
Income from Equity Method Investees,
below.
|
(4)
|
Other International includes de minimis North Sea sales volumes with last production in May 2015.
|
|
Sales Revenues
|
||||||||||||||
(millions)
|
Crude Oil & Condensate
|
|
Natural
Gas
|
|
NGLs
|
|
Total
|
||||||||
Three Months Ended September 30, 2015
|
$
|
438
|
|
|
$
|
293
|
|
|
$
|
52
|
|
|
$
|
783
|
|
Changes due to
|
|
|
|
|
|
|
|
|
|
|
|
||||
Increase in Sales Volumes
|
34
|
|
|
29
|
|
|
10
|
|
|
73
|
|
||||
(Decrease) Increase in Sales Prices
|
(11
|
)
|
|
25
|
|
|
12
|
|
|
26
|
|
||||
Three Months Ended September 30, 2016
|
$
|
461
|
|
|
$
|
347
|
|
|
$
|
74
|
|
|
$
|
882
|
|
|
|
|
|
|
|
|
|
||||||||
Nine Months Ended September 30, 2015
|
$
|
1,352
|
|
|
$
|
785
|
|
|
$
|
127
|
|
|
$
|
2,264
|
|
Changes due to
|
|
|
|
|
|
|
|
|
|
|
|||||
Increase in Sales Volumes
|
176
|
|
|
185
|
|
|
82
|
|
|
443
|
|
||||
Decrease in Sales Prices
|
(237
|
)
|
|
(54
|
)
|
|
(5
|
)
|
|
(296
|
)
|
||||
Nine Months Ended September 30, 2016
|
$
|
1,291
|
|
|
$
|
916
|
|
|
$
|
204
|
|
|
$
|
2,411
|
|
•
|
decreases in average realized prices primarily due to the decline in global commodity prices that began in the second half of 2014; and
|
•
|
natural field decline at Alen and Aseng in offshore Equatorial Guinea;
|
•
|
production from the Big Bend and Dantzler developments (deepwater Gulf of Mexico), which began producing fourth quarter 2015 and contributed 8 MBbl/d and 6 MBbl/d, net, respectively, during the first nine months of 2016;
|
•
|
production from the Gunflint development (deepwater Gulf of Mexico), which began producing in July 2016 and contributed 4 MBbl/d, net, during the current quarter; and
|
•
|
sales volumes contributed by our Eagle Ford Shale and Permian Basin assets acquired third quarter 2015, which contributed 11 MBbl/d and 6 MBbl/d, net, respectively, during the first nine months of 2016.
|
•
|
higher sales volumes from the Tamar field, offshore Israel, in response to the increased use of natural gas over coal to fuel power generation and higher seasonal demand;
|
•
|
higher sales volumes in the Marcellus Shale due to commencement of production on 42 operated and non-operated wells, and the recognition of efficiencies in base production performance; and
|
•
|
sales volumes contributed by our Eagle Ford Shale and Permian Basin assets acquired third quarter 2015, which contributed 135 MMcf/d and 9 MMcf/d, net, respectively, during the first nine months of 2016;
|
•
|
decreases in average realized prices primarily due to the decline in global commodity prices that began in the second half of 2014.
|
•
|
higher sales volumes in the DJ Basin driven by higher NGL yields due to infrastructure operating efficiencies; and
|
•
|
sales volumes contributed by our Eagle Ford Shale and Permian Basin assets acquired third quarter 2015, which contributed 23 MBbl/d and 1 MBbl/d, net, respectively, during the first nine months of 2016;
|
•
|
decreases in average realized prices primarily driven by oversupply.
|
|
|
|
|
|
Increase / (Decrease)
from Prior Year |
|||||
(millions)
|
2016
|
|
2015
|
|
||||||
Three Months Ended September 30,
|
|
|
|
|
|
|||||
Production Expense
|
$
|
274
|
|
|
$
|
247
|
|
|
11
|
%
|
Exploration Expense
|
125
|
|
|
203
|
|
|
(38
|
)%
|
||
Depreciation, Depletion and Amortization
|
621
|
|
|
539
|
|
|
15
|
%
|
||
General and Administrative
|
95
|
|
|
109
|
|
|
(13
|
)%
|
||
Other Operating Expense, Net
|
45
|
|
|
188
|
|
|
(76
|
)%
|
||
Total
|
$
|
1,160
|
|
|
$
|
1,286
|
|
|
(10
|
)%
|
|
|
|
|
|
|
|||||
Nine Months Ended September 30,
|
|
|
|
|
|
|||||
Production Expense
|
$
|
820
|
|
|
$
|
715
|
|
|
15
|
%
|
Exploration Expense
|
376
|
|
|
308
|
|
|
22
|
%
|
||
Depreciation, Depletion and Amortization
|
1,859
|
|
|
1,444
|
|
|
29
|
%
|
||
General and Administrative
|
293
|
|
|
308
|
|
|
(5
|
)%
|
||
Other Operating Expense, Net
|
66
|
|
|
310
|
|
|
(79
|
)%
|
||
Total
|
$
|
3,414
|
|
|
$
|
3,085
|
|
|
11
|
%
|
(millions, except unit rate)
|
Total per BOE
(1)
|
|
Total
|
|
United
States
|
|
Equatorial Guinea
|
|
Israel
|
|
Corporate
|
||||||||||||
Three Months Ended September 30, 2016
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Lease Operating Expense
(2)
|
$
|
3.42
|
|
|
$
|
131
|
|
|
$
|
98
|
|
|
$
|
22
|
|
|
$
|
8
|
|
|
$
|
3
|
|
Production and Ad Valorem Taxes
|
0.78
|
|
|
30
|
|
|
30
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Transportation and Gathering Expense
(3)
|
2.95
|
|
|
113
|
|
|
113
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total Production Expense
|
$
|
7.15
|
|
|
$
|
274
|
|
|
$
|
241
|
|
|
$
|
22
|
|
|
$
|
8
|
|
|
$
|
3
|
|
Total Production Expense per BOE
|
|
|
$
|
7.15
|
|
|
$
|
8.77
|
|
|
$
|
3.67
|
|
|
$
|
1.67
|
|
|
N/M
|
|
|||
Three Months Ended September 30, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Lease Operating Expense
(2)
|
$
|
3.89
|
|
|
$
|
133
|
|
|
$
|
92
|
|
|
$
|
26
|
|
|
$
|
13
|
|
|
$
|
2
|
|
Production and Ad Valorem Taxes
|
0.83
|
|
|
28
|
|
|
28
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Transportation and Gathering Expense
(3)
|
2.51
|
|
|
86
|
|
|
86
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total Production Expense
|
$
|
7.23
|
|
|
$
|
247
|
|
|
$
|
206
|
|
|
$
|
26
|
|
|
$
|
13
|
|
|
$
|
2
|
|
Total Production Expense per BOE
|
|
|
$
|
7.23
|
|
|
$
|
8.77
|
|
|
$
|
4.32
|
|
|
$
|
2.78
|
|
|
N/M
|
|
|||
Nine Months Ended September 30, 2016
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Lease Operating Expense
(2)
|
$
|
3.62
|
|
|
$
|
413
|
|
|
$
|
305
|
|
|
$
|
75
|
|
|
$
|
25
|
|
|
$
|
8
|
|
Production and Ad Valorem Taxes
|
0.64
|
|
|
72
|
|
|
72
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Transportation and Gathering Expense
(3)
|
2.94
|
|
|
335
|
|
|
335
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total Production Expense
|
$
|
7.20
|
|
|
$
|
820
|
|
|
$
|
712
|
|
|
$
|
75
|
|
|
$
|
25
|
|
|
$
|
8
|
|
Total Production Expense per BOE
|
|
|
$
|
7.20
|
|
|
$
|
8.53
|
|
|
$
|
4.30
|
|
|
$
|
1.91
|
|
|
N/M
|
|
|||
Nine Months Ended September 30, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Lease Operating Expense
(2)
|
$
|
4.70
|
|
|
$
|
419
|
|
|
$
|
274
|
|
|
$
|
96
|
|
|
$
|
38
|
|
|
$
|
11
|
|
Production and Ad Valorem Taxes
|
1.00
|
|
|
89
|
|
|
89
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Transportation and Gathering Expense
(3)
|
2.32
|
|
|
207
|
|
|
207
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total Production Expense
|
$
|
8.02
|
|
|
$
|
715
|
|
|
$
|
570
|
|
|
$
|
96
|
|
|
$
|
38
|
|
|
$
|
11
|
|
Total Production Expense per BOE
|
|
|
$
|
8.02
|
|
|
$
|
9.61
|
|
|
$
|
5.32
|
|
|
$
|
3.27
|
|
|
N/M
|
|
(1)
|
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.
|
(2)
|
Lease operating expense includes oil and gas operating costs (labor, fuel, repairs, replacements, saltwater disposal and other related lifting costs) and workover expense.
|
(3)
|
Certain of our revenue received from purchasers was historically presented with deduction for transportation, fractionation or processing costs. Beginning in 2016, we have changed our presentation of revenue to no longer include these expenses as deductions from revenue. These costs are now included within production expense and prior year amounts have been reclassified to conform to the current presentation.
See Results of Operations – Revenues
, above.
|
•
|
an increase in transportation and gathering expense due to higher production, including the addition of onshore US production from our Eagle Ford Shale and Permian Basin assets acquired in third quarter 2015, and from our Big Bend and Dantzler development projects in deepwater Gulf of Mexico, which began producing in fourth quarter 2015, and Gunflint in deepwater Gulf of Mexico, which began producing in July 2016;
|
•
|
a decrease in production and ad valorem taxes resulting from lower revenues and an onshore US severance tax refund, both driven by a decline in US commodity prices.
|
(millions)
|
Total
|
|
United
States
|
|
West
Africa
(1)
|
|
Eastern
Mediter-
ranean
(2)
|
|
Other Int'l,
Corporate
(3)
|
||||||||||
Three Months Ended September 30, 2016
|
|
|
|
|
|
|
|
|
|||||||||||
Leasehold Impairment and Amortization
|
$
|
96
|
|
|
$
|
71
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
25
|
|
Dry Hole Expense
|
5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|||||
Seismic, Geological and Geophysical
|
15
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
15
|
|
|||||
Staff Expense
|
15
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
14
|
|
|||||
Other
(4)
|
(6
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6
|
)
|
|||||
Total Exploration Expense
|
$
|
125
|
|
|
$
|
72
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
53
|
|
Three Months Ended September 30, 2015
|
|
|
|
|
|
|
|
|
|||||||||||
Leasehold Impairment and Amortization
|
$
|
41
|
|
|
$
|
41
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Dry Hole Expense
|
135
|
|
|
—
|
|
|
27
|
|
|
—
|
|
|
108
|
|
|||||
Seismic, Geological and Geophysical
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Staff Expense
|
27
|
|
|
3
|
|
|
—
|
|
|
2
|
|
|
22
|
|
|||||
Other
(4)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Total Exploration Expense
|
$
|
203
|
|
|
$
|
44
|
|
|
$
|
27
|
|
|
$
|
2
|
|
|
$
|
130
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Nine Months Ended September 30, 2016
|
|
|
|
|
|
|
|
|
|||||||||||
Leasehold Impairment and Amortization
|
$
|
127
|
|
|
$
|
102
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
25
|
|
Dry Hole Expense
|
105
|
|
|
79
|
|
|
—
|
|
|
26
|
|
|
—
|
|
|||||
Seismic, Geological and Geophysical
|
47
|
|
|
—
|
|
|
10
|
|
|
—
|
|
|
37
|
|
|||||
Staff Expense
|
53
|
|
|
2
|
|
|
2
|
|
|
—
|
|
|
49
|
|
|||||
Other
(4)
|
44
|
|
|
35
|
|
|
—
|
|
|
7
|
|
|
2
|
|
|||||
Total Exploration Expense
|
$
|
376
|
|
|
$
|
218
|
|
|
$
|
12
|
|
|
$
|
33
|
|
|
$
|
113
|
|
Nine Months Ended September 30, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Leasehold Impairment and Amortization
|
$
|
78
|
|
|
$
|
73
|
|
|
$
|
—
|
|
|
$
|
5
|
|
|
$
|
—
|
|
Dry Hole Expense
|
154
|
|
|
18
|
|
|
27
|
|
|
—
|
|
|
109
|
|
|||||
Seismic, Geological and Geophysical
|
2
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Staff Expense
|
72
|
|
|
2
|
|
|
2
|
|
|
4
|
|
|
64
|
|
|||||
Other
(4)
|
2
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|||||
Total Exploration Expense
|
$
|
308
|
|
|
$
|
95
|
|
|
$
|
29
|
|
|
$
|
11
|
|
|
$
|
173
|
|
(1)
|
West Africa includes Equatorial Guinea, Cameroon, Sierra Leone (which we exited in second quarter 2015), and Gabon.
|
(2)
|
Eastern Mediterranean includes Israel and Cyprus.
|
(3)
|
Other International, Corporate includes the Falkland Islands, other new ventures and corporate expenditures.
|
(4)
|
Includes lease rentals and other exploratory costs.
|
•
|
leasehold impairment expense primarily related to write-off of leases and licenses in the deepwater Gulf of Mexico of $56 million and Falkland Islands of $25 million;
|
•
|
dry hole cost primarily related to the Silvergate exploratory well, deepwater Gulf of Mexico, and the Dolphin 1 natural gas discovery, offshore Israel;
|
•
|
seismic expense related to the acquisition of 3D seismic data in West Africa and other international areas;
|
•
|
other cost for onshore US includes lease rentals primarily related to Permian Basin leases; and
|
•
|
salaries and related expenses for corporate exploration and new ventures personnel.
|
•
|
dry hole cost related to onshore US, offshore Cameroon (Cheetah), and Falkland Islands (Humpback) exploration wells;
|
•
|
leasehold impairment, including a $41 million deepwater Gulf of Mexico lease; and
|
•
|
salaries and related expenses for corporate exploration and new ventures personnel.
|
|
Three Months Ended
September 30, |
|
Nine Months Ended
September 30, |
||||||||||||
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
DD&A Expense (millions)
(1)
|
$
|
621
|
|
|
$
|
539
|
|
|
$
|
1,859
|
|
|
$
|
1,444
|
|
Unit Rate per BOE
(2)
|
$
|
16.23
|
|
|
$
|
15.75
|
|
|
$
|
16.31
|
|
|
$
|
16.21
|
|
(1)
|
For DD&A expense by geographical area, see
Item 1. Financial Statements – Note
13. Segment Information
.
|
(2)
|
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.
|
•
|
the addition of Eagle Ford Shale and Permian Basin production in third quarter 2015, resulting in $144 million and $31 million in DD&A expense, respectively, during the first nine months of 2016;
|
•
|
an increase in sales volumes due to commencement of production from the Big Bend, Dantzler and Gunflint development projects in deepwater Gulf of Mexico, additional wells which came online in the Marcellus Shale and increased demand in Eastern Mediterranean; and
|
•
|
a reduction in proved reserves in fourth quarter 2015 primarily due to downward price revisions in DJ Basin and Marcellus Shale;
|
•
|
an overall lower segment rate for offshore Equatorial Guinea due to the swing in production between higher DD&A rate assets Aseng and Alen and lower DD&A rate asset Alba; and
|
•
|
the impact of lower net book value as a result of a fourth quarter 2015 impairment for offshore Equatorial Guinea properties.
|
|
Three Months Ended
September 30, |
|
Nine Months Ended
September 30, |
||||||||||||
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
G&A Expense (millions)
|
$
|
95
|
|
|
$
|
109
|
|
|
$
|
293
|
|
|
$
|
308
|
|
Unit Rate per BOE
(1)
|
$
|
2.48
|
|
|
$
|
3.19
|
|
|
$
|
2.57
|
|
|
$
|
3.46
|
|
(1)
|
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.
|
|
Three Months Ended
September 30, |
|
Nine Months Ended
September 30, |
||||||||||||
(millions)
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
(Gain) Loss on Asset Due to Terminated Contract
|
$
|
(3
|
)
|
|
$
|
—
|
|
|
$
|
44
|
|
|
$
|
—
|
|
Marketing and Processing Expense, Net
|
20
|
|
|
10
|
|
|
58
|
|
|
25
|
|
||||
Loss on Divestitures
|
—
|
|
|
—
|
|
|
23
|
|
|
—
|
|
||||
Corporate Restructuring Expense
|
—
|
|
|
21
|
|
|
—
|
|
|
39
|
|
||||
Purchase Price Allocation Adjustment
|
—
|
|
|
—
|
|
|
(25
|
)
|
|
—
|
|
||||
Gain on Extinguishment of Debt
|
—
|
|
|
—
|
|
|
(80
|
)
|
|
—
|
|
||||
Asset Impairments
|
—
|
|
|
—
|
|
|
—
|
|
|
43
|
|
||||
Inventory Adjustment
|
14
|
|
|
—
|
|
|
14
|
|
|
—
|
|
||||
Building Exit Cost
|
4
|
|
|
18
|
|
|
8
|
|
|
18
|
|
||||
Rosetta Merger Expenses
|
—
|
|
|
71
|
|
|
—
|
|
|
73
|
|
||||
Pension Plan Expense
|
—
|
|
|
67
|
|
|
—
|
|
|
88
|
|
||||
Stacked Drilling Rig Expense
|
3
|
|
|
13
|
|
|
8
|
|
|
20
|
|
||||
Other, Net
|
7
|
|
|
(12
|
)
|
|
16
|
|
|
4
|
|
||||
Total
|
$
|
45
|
|
|
$
|
188
|
|
|
$
|
66
|
|
|
$
|
310
|
|
|
Three Months Ended
September 30, |
|
Nine Months Ended
September 30, |
||||||||||||
(millions)
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
(Gain) Loss on Commodity Derivative Instruments
|
$
|
(55
|
)
|
|
$
|
(267
|
)
|
|
$
|
53
|
|
|
$
|
(331
|
)
|
Interest, Net of Amount Capitalized
|
86
|
|
|
71
|
|
|
242
|
|
|
183
|
|
||||
Other Non-Operating Expense (Income), Net
|
(1
|
)
|
|
(12
|
)
|
|
3
|
|
|
(20
|
)
|
||||
Total
|
$
|
30
|
|
|
$
|
(208
|
)
|
|
$
|
298
|
|
|
$
|
(168
|
)
|
|
Three Months Ended
September 30, |
|
Nine Months Ended
September 30, |
||||||||||||
(millions, except unit rate)
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Interest Expense, Gross
|
$
|
103
|
|
|
$
|
110
|
|
|
$
|
312
|
|
|
$
|
294
|
|
Capitalized Interest
|
(17
|
)
|
|
(39
|
)
|
|
(70
|
)
|
|
(111
|
)
|
||||
Interest Expense, Net
|
$
|
86
|
|
|
$
|
71
|
|
|
$
|
242
|
|
|
$
|
183
|
|
Unit Rate per BOE
(1)
|
$
|
2.25
|
|
|
$
|
2.08
|
|
|
$
|
2.12
|
|
|
$
|
2.05
|
|
(1)
|
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.
|
|
September 30,
|
|
December 31,
|
||||
(millions, except percentages)
|
2016
|
|
2015
|
||||
Cash and Cash Equivalents
|
$
|
1,772
|
|
|
$
|
1,001
|
|
Amount Available to be Borrowed Under Revolving Credit Facility
(1)
|
4,000
|
|
|
4,000
|
|
||
Total Liquidity
|
$
|
5,772
|
|
|
$
|
5,001
|
|
Total Debt
(2)
|
$
|
7,957
|
|
|
$
|
7,976
|
|
Noble Energy Share of Equity
|
9,545
|
|
|
10,370
|
|
||
Ratio of Debt-to-Book Capital
(3)
|
45
|
%
|
|
43
|
%
|
(1)
|
Does not include $350 million available to be borrowed under Noble Midstream's Revolving Credit Facility, which is not available to Noble Energy. See
Revolving Credit Facilities,
below.
|
(2)
|
Total debt includes capital lease obligations and excludes unamortized debt discount/premium.
|
(3)
|
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.
|
|
Nine Months Ended
September 30, |
||||||
(millions)
|
2016
|
|
2015
|
||||
Total Cash Provided By (Used in)
|
|
|
|
||||
Operating Activities
|
$
|
1,054
|
|
|
$
|
1,486
|
|
Investing Activities
|
(386
|
)
|
|
(2,393
|
)
|
||
Financing Activities
|
123
|
|
|
752
|
|
||
Increase (Decrease) in Cash and Cash Equivalents
|
$
|
791
|
|
|
$
|
(155
|
)
|
|
Three Months Ended
September 30, |
|
Nine Months Ended
September 30, |
||||||||||||
(millions)
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Acquisition, Capital and Exploration Expenditures
|
|
|
|
|
|
|
|
||||||||
Property Acquisition
(1)
|
$
|
21
|
|
|
$
|
21
|
|
|
$
|
60
|
|
|
$
|
86
|
|
Exploration
|
25
|
|
|
117
|
|
|
183
|
|
|
257
|
|
||||
Development
|
202
|
|
|
458
|
|
|
597
|
|
|
1,695
|
|
||||
Midstream
(2)
|
9
|
|
|
26
|
|
|
29
|
|
|
123
|
|
||||
Corporate and Other
|
38
|
|
|
21
|
|
|
58
|
|
|
78
|
|
||||
Total
|
$
|
295
|
|
|
$
|
643
|
|
|
$
|
927
|
|
|
$
|
2,239
|
|
Other
|
|
|
|
|
|
|
|
||||||||
Investment in Equity Method Investee
(3)
|
$
|
2
|
|
|
$
|
21
|
|
|
$
|
8
|
|
|
$
|
86
|
|
Increase in Capital Lease Obligations
|
5
|
|
|
29
|
|
|
5
|
|
|
60
|
|
(1)
|
Property acquisition cost for 2016 includes $28 million in the DJ Basin, $22 million in the Marcellus Shale, $5 million in the Permian Basin and $5 million in the Eagle Ford Shale. Proved property acquisition cost for 2015 includes $37 million in the DJ Basin and $43 million in the Marcellus Shale.
|
(2)
|
Midstream cost for the three and nine months ended September 30, 2016 includes Noble Midstream capital expenditures of $8 million and $13 million, respectively. Midstream costs for the three and nine months ended 2015 includes Noble Midstream capital expenditures of $14 million and $49 million, respectively.
|
(3)
|
Investment in equity method investee represents primarily contributions to CONE Gathering LLC which owns and operates the natural gas gathering infrastructure associated with our Marcellus Shale joint venture.
|
•
|
our growth strategies;
|
•
|
our ability to successfully and economically explore for and develop crude oil and natural gas resources;
|
•
|
anticipated trends in our business;
|
•
|
our future results of operations;
|
•
|
our liquidity and ability to finance our exploration and development activities;
|
•
|
market conditions in the oil and gas industry;
|
•
|
our ability to make and integrate acquisitions;
|
•
|
the impact of governmental fiscal terms and/or regulation, 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
|
|
Approximate Dollar
Value of Shares that
May Yet Be
Purchased Under the
Plans or Programs
|
|||||
|
|
|
|
|
|
|
(in thousands)
|
|||||
7/1/2016 - 7/31/2016
|
1,248
|
|
|
$
|
35.82
|
|
|
—
|
|
|
—
|
|
8/1/2016 - 8/31/2016
|
462
|
|
|
34.91
|
|
|
—
|
|
|
—
|
|
|
9/1/2016 - 9/30/2016
|
577
|
|
|
34.51
|
|
|
—
|
|
|
—
|
|
|
Total
|
2,287
|
|
|
$
|
35.31
|
|
|
—
|
|
|
—
|
|
(1)
|
Stock repurchases during the period related 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.
|
|
|
|
|
NOBLE ENERGY, INC.
|
|
|
|
|
(Registrant)
|
|
|
|
|
|
Date
|
|
November 2, 2016
|
|
/s/ Kenneth M. Fisher
|
|
|
|
|
Kenneth M. Fisher
Executive Vice President, Chief Financial Officer
|
|
||
Exhibit Number
|
|
Exhibit
|
|
|
|
2.1
|
|
Asset Acquisition Agreement, dated August 17, 2011, between CNX Gas Company LLC and Noble Energy, Inc. including Appendix I (Definitions) thereto (filed as Exhibit 2.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2011 and incorporated herein by reference).
|
|
|
|
2.2
|
|
Agreement and Plan of Merger, dated as of May 10, 2015, by and among Noble Energy, Inc., Bluebonnet Merger Sub Inc. and Rosetta Resources Inc. (filed as Exhibit 2.1 of the Registrant’s Current Report on Form 8-K (Date of Report: May 10, 2015) filed on May 11, 2015 and incorporated herein by reference).
|
|
|
|
2.3
|
|
|
|
|
|
3.1
|
|
Restated Certificate of Incorporation of Noble Energy Inc. (filed as Exhibit 3.3 to the Registrant's Current Report on Form 8-K (Date of Report: July 26, 2016) filed on July 28, 2016 and incorporated herein by reference).
|
|
|
|
3.2
|
|
By-Laws of Noble Energy, Inc. (as amended through July 27, 2016) (filed as Exhibit 3.1 to the Registrant's Current Report on Form 8-K (Date of Event: July 27, 2016) filed on July 29, 2016 and incorporated herein by reference).
|
|
|
|
3.3
|
|
Certificate of Elimination of the Series A Junior Participating Preferred Stock of Noble Energy, Inc. (filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K (Date of Report: July 26, 2016) filed on July 28, 2016 and incorporated herein by reference).
|
|
|
|
3.4
|
|
Certificate of Elimination of the Series B Mandatorily Convertible Preferred Stock of Noble Energy, Inc. (filed as Exhibit 3.2 to the Registrant’s Current Report on Form 8-K (Date of Report: July 26, 2016) filed on July 28, 2016 and incorporated herein by reference).
|
|
|
|
12.1
|
|
|
|
|
|
31.1
|
|
|
|
|
|
31.2
|
|
|
|
|
|
32.1
|
|
|
|
|
|
32.2
|
|
|
|
|
|
101.INS
|
|
XBRL Instance Document
|
|
|
|
101.SCH
|
|
XBRL Schema Document
|
|
|
|
101.CAL
|
|
XBRL Calculation Linkbase Document
|
|
|
|
101.LAB
|
|
XBRL Label Linkbase Document
|
|
|
|
101.PRE
|
|
XBRL Presentation Linkbase Document
|
|
|
|
101.DEF
|
|
XBRL Definition Linkbase Document
|
Exhibit A-1
|
― CONSOL Transferred Leases - Part 1 (Limited to Marcellus Formation), Part 2 (Not Limited to Any Formation), Part 3 (Limited to Utica/Point Pleasant Formation) and Part 4 (Limited to Rhinestreet Formation); Allocated Values
|
Exhibit A-2
|
― CONSOL Transferred O/G Wells (WI/NRI), Allocated Values
–
Part 1
,
CONSOL Transferred NON-O/G Wells – Part 2
|
Exhibit A-3
|
― CONSOL Wholly Transferred Rights-Of-Way – Part 1, CONSOL Partially Transferred Rights-Of-Way – Part 2
|
Exhibit A-4
|
― CONSOL Contracts Wholly Assigned – Part 1; CONSOL Split-Up Contracts Assigned in– Part 2
|
Exhibit A-6
|
― Permitted Encumbrances – Certain Assignments
|
Exhibit B-1
|
― Noble Transferred Leases – Part 1 (Limited to Marcellus Formation). Part 2 (Not Limited to Any Formation) and Part 3 (Limited to Rhinestreet Formation)
|
Exhibit B-2
|
― Noble Transferred O/G Wells (WI/NRI), Allocated Values
–
Part 1
,
Noble Transferred NON-O/G Wells – Part 2
|
Exhibit B-3
|
― Noble Wholly Transferred Rights-Of-Way – Part 1, Noble Partially Transferred Rights-Of-Way – Part 2
|
Exhibit B-4
|
― Noble Contracts Wholly Assigned – Part 1; Noble Split-Up Contracts Assigned – Part 2
|
Exhibit B-6
|
― Permitted Encumbrances – Certain Assignments
|
Exhibit E-3
|
― Form of Noble Assignment
|
Exhibit L
|
― Petition for Temporary Waivers of Capacity Release Regulations and Related Pipeline Tariff Provisions
|
Noble Energy, Inc.
|
||||||||||||||||||||
Calculation of Ratio of Earnings to Fixed Charges
|
||||||||||||||||||||
|
|
Nine Months Ended September 30,
|
|
Year Ended December 31,
|
||||||||||||||||
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
(millions)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
(Loss) Income From Continuing Operations Before Income Tax and Income From Equity Investees
|
|
$
|
(1,301
|
)
|
|
$
|
(2,309
|
)
|
|
$
|
1,540
|
|
|
$
|
1,138
|
|
|
$
|
1,170
|
|
Add (Deduct)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed Charges
|
|
331
|
|
|
435
|
|
|
349
|
|
|
296
|
|
|
288
|
|
|||||
Capitalized Interest
|
|
(70
|
)
|
|
(144
|
)
|
|
(116
|
)
|
|
(121
|
)
|
|
(151
|
)
|
|||||
Distributed Income From Equity Investees
|
|
58
|
|
|
77
|
|
|
382
|
|
|
204
|
|
|
204
|
|
|||||
Earnings as Defined
|
|
$
|
(982
|
)
|
|
$
|
(1,941
|
)
|
|
$
|
2,155
|
|
|
$
|
1,517
|
|
|
$
|
1,511
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net Interest Expense
|
|
242
|
|
|
263
|
|
|
210
|
|
|
158
|
|
|
125
|
|
|||||
Capitalized Interest
|
|
70
|
|
|
144
|
|
|
116
|
|
|
121
|
|
|
151
|
|
|||||
Interest Portion of Rental Expense
|
|
19
|
|
|
28
|
|
|
23
|
|
|
17
|
|
|
12
|
|
|||||
Fixed Charges as Defined
|
|
$
|
331
|
|
|
$
|
435
|
|
|
$
|
349
|
|
|
$
|
296
|
|
|
$
|
288
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Ratio of Earnings to Fixed Charges
|
|
—
|
|
|
—
|
|
|
6.2
|
|
|
5.1
|
|
|
5.2
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Amount by Which Earnings Were Insufficient to Cover Fixed Charges
|
|
$
|
1,313
|
|
|
$
|
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:
|
November 2, 2016
|
|
|
|
|
|
|
/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:
|
November 2, 2016
|
|
|
|
|
|
|
/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:
|
November 2, 2016
|
|
/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:
|
November 2, 2016
|
|
/s/ Kenneth M. Fisher
|
|
|
|
Kenneth M. Fisher
|
|
|
|
Chief Financial Officer
|