Delaware
|
|
73-0785597
|
(State or other jurisdiction of incorporation or organization)
|
|
(I.R.S. employer identification number)
|
1001 Noble Energy Way
|
|
|
Houston, Texas
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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
|
|
|
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Part II.
Other Information
|
|
|
|
Item 1.
Legal Proceedings
|
|
|
|
Item 1A.
Risk Factors
|
|
|
|
|
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Item 3.
Defaults Upon Senior Securities
|
|
|
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Item 4.
Mine Safety Disclosures
|
|
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Item 5.
Other Information
|
|
|
|
Item 6.
Exhibits
|
|
|
|
|
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Revenues
|
|
|
|
|
|
|
|
||||||||
Oil, Gas and NGL Sales
|
$
|
823
|
|
|
$
|
732
|
|
|
$
|
1,528
|
|
|
$
|
1,481
|
|
Income from Equity Method Investees
|
24
|
|
|
6
|
|
|
43
|
|
|
24
|
|
||||
Total
|
847
|
|
|
738
|
|
|
1,571
|
|
|
1,505
|
|
||||
Costs and Expenses
|
|
|
|
|
|
|
|
|
|
||||||
Production Expense
|
274
|
|
|
218
|
|
|
546
|
|
|
469
|
|
||||
Exploration Expense
|
89
|
|
|
41
|
|
|
252
|
|
|
106
|
|
||||
Depreciation, Depletion and Amortization
|
622
|
|
|
451
|
|
|
1,239
|
|
|
905
|
|
||||
General and Administrative
|
107
|
|
|
104
|
|
|
198
|
|
|
198
|
|
||||
Other Operating Expense, Net
|
17
|
|
|
85
|
|
|
20
|
|
|
121
|
|
||||
Total
|
1,109
|
|
|
899
|
|
|
2,255
|
|
|
1,799
|
|
||||
Operating Loss
|
(262
|
)
|
|
(161
|
)
|
|
(684
|
)
|
|
(294
|
)
|
||||
Other Expense (Income)
|
|
|
|
|
|
|
|
|
|
||||||
Loss (Gain) on Commodity Derivative Instruments
|
151
|
|
|
87
|
|
|
107
|
|
|
(63
|
)
|
||||
Interest, Net of Amount Capitalized
|
78
|
|
|
54
|
|
|
157
|
|
|
112
|
|
||||
Other Non-Operating Expense (Income), Net
|
7
|
|
|
(9
|
)
|
|
3
|
|
|
(9
|
)
|
||||
Total
|
236
|
|
|
132
|
|
|
267
|
|
|
40
|
|
||||
Loss Before Income Taxes
|
(498
|
)
|
|
(293
|
)
|
|
(951
|
)
|
|
(334
|
)
|
||||
Income Tax Benefit
|
(183
|
)
|
|
(184
|
)
|
|
(349
|
)
|
|
(203
|
)
|
||||
Net Loss
|
$
|
(315
|
)
|
|
$
|
(109
|
)
|
|
$
|
(602
|
)
|
|
$
|
(131
|
)
|
|
|
|
|
|
|
|
|
||||||||
Loss Per Share, Basic
|
$
|
(0.73
|
)
|
|
$
|
(0.28
|
)
|
|
$
|
(1.40
|
)
|
|
$
|
(0.35
|
)
|
Loss Per Share, Diluted
|
$
|
(0.73
|
)
|
|
$
|
(0.28
|
)
|
|
$
|
(1.40
|
)
|
|
$
|
(0.35
|
)
|
|
|
|
|
|
|
|
|
||||||||
Weighted Average Number of Shares Outstanding
|
|
|
|
|
|
|
|
||||||||
Basic
|
430
|
|
|
387
|
|
|
429
|
|
|
378
|
|
||||
Diluted
|
430
|
|
|
387
|
|
|
429
|
|
|
378
|
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Net Loss
|
$
|
(315
|
)
|
|
$
|
(109
|
)
|
|
$
|
(602
|
)
|
|
$
|
(131
|
)
|
Other Items of Comprehensive Loss
|
|
|
|
|
|
|
|
||||||||
Net Change in Mutual Fund Investment
|
—
|
|
|
—
|
|
|
—
|
|
|
(11
|
)
|
||||
Less Tax Expense
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
||||
Net Change in Pension and Other
|
1
|
|
|
24
|
|
|
1
|
|
|
25
|
|
||||
Less Tax Benefit
|
—
|
|
|
(10
|
)
|
|
—
|
|
|
(10
|
)
|
||||
Comprehensive Loss
|
$
|
(314
|
)
|
|
$
|
(95
|
)
|
|
$
|
(601
|
)
|
|
$
|
(124
|
)
|
|
June 30,
2016 |
|
December 31,
2015 |
||||
ASSETS
|
|
|
|
||||
Current Assets
|
|
|
|
||||
Cash and Cash Equivalents
|
$
|
1,300
|
|
|
$
|
1,028
|
|
Accounts Receivable, Net
|
476
|
|
|
450
|
|
||
Commodity Derivative Assets
|
229
|
|
|
582
|
|
||
Other Current Assets
|
184
|
|
|
216
|
|
||
Total Current Assets
|
2,189
|
|
|
2,276
|
|
||
Property, Plant and Equipment
|
|
|
|
|
|
||
Oil and Gas Properties (Successful Efforts Method of Accounting)
|
30,713
|
|
|
31,220
|
|
||
Property, Plant and Equipment, Other
|
877
|
|
|
858
|
|
||
Total Property, Plant and Equipment, Gross
|
31,590
|
|
|
32,078
|
|
||
Accumulated Depreciation, Depletion and Amortization
|
(11,856
|
)
|
|
(10,778
|
)
|
||
Total Property, Plant and Equipment, Net
|
19,734
|
|
|
21,300
|
|
||
Other Noncurrent Assets
|
593
|
|
|
620
|
|
||
Total Assets
|
$
|
22,516
|
|
|
$
|
24,196
|
|
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
|
|
||||
Current Liabilities
|
|
|
|
|
|
||
Accounts Payable - Trade
|
$
|
780
|
|
|
$
|
1,128
|
|
Other Current Liabilities
|
595
|
|
|
677
|
|
||
Total Current Liabilities
|
1,375
|
|
|
1,805
|
|
||
Long-Term Debt
|
7,868
|
|
|
7,976
|
|
||
Deferred Income Taxes
|
2,387
|
|
|
2,826
|
|
||
Other Noncurrent Liabilities
|
1,173
|
|
|
1,219
|
|
||
Total Liabilities
|
12,803
|
|
|
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
|
6,398
|
|
|
6,360
|
|
||
Accumulated Other Comprehensive Loss
|
(32
|
)
|
|
(33
|
)
|
||
Treasury Stock, at Cost; 38 Million Shares
|
(696
|
)
|
|
(688
|
)
|
||
Retained Earnings
|
4,038
|
|
|
4,726
|
|
||
Total Shareholders’ Equity
|
9,713
|
|
|
10,370
|
|
||
Total Liabilities and Shareholders’ Equity
|
$
|
22,516
|
|
|
$
|
24,196
|
|
|
Six Months Ended
June 30, |
||||||
|
2016
|
|
2015
|
||||
Cash Flows From Operating Activities
|
|
|
|
||||
Net Loss
|
$
|
(602
|
)
|
|
$
|
(131
|
)
|
Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities
|
|
|
|
|
|
||
Depreciation, Depletion and Amortization
|
1,239
|
|
|
905
|
|
||
Asset Impairments
|
—
|
|
|
43
|
|
||
Dry Hole Cost
|
114
|
|
|
19
|
|
||
Gain on Extinguishment of Debt
|
(80
|
)
|
|
—
|
|
||
Finalization of Purchase Price Allocation for Rosetta Merger
|
(25
|
)
|
|
—
|
|
||
Loss on Asset Due to Terminated Contract
|
47
|
|
|
—
|
|
||
Deferred Income Tax Benefit
|
(414
|
)
|
|
(312
|
)
|
||
(Income) Loss from Equity Method Investees, Net of Dividends
|
(9
|
)
|
|
4
|
|
||
Loss (Gain) on Commodity Derivative Instruments
|
107
|
|
|
(63
|
)
|
||
Net Cash Received in Settlement of Commodity Derivative Instruments
|
322
|
|
|
397
|
|
||
Loss on Divestitures
|
23
|
|
|
—
|
|
||
Stock Based Compensation
|
40
|
|
|
38
|
|
||
Non-cash Pension Termination Expense
|
—
|
|
|
21
|
|
||
Other Adjustments for Noncash Items Included in Income
|
59
|
|
|
11
|
|
||
Changes in Operating Assets and Liabilities
|
|
|
|
|
|
||
(Increase) Decrease in Accounts Receivable
|
(6
|
)
|
|
304
|
|
||
Decrease in Accounts Payable
|
(232
|
)
|
|
(167
|
)
|
||
Decrease in Current Income Taxes Payable
|
(51
|
)
|
|
(63
|
)
|
||
Other Current Assets and Liabilities, Net
|
(51
|
)
|
|
(45
|
)
|
||
Other Operating Assets and Liabilities, Net
|
(41
|
)
|
|
5
|
|
||
Net Cash Provided by Operating Activities
|
440
|
|
|
966
|
|
||
Cash Flows From Investing Activities
|
|
|
|
|
|
||
Additions to Property, Plant and Equipment
|
(812
|
)
|
|
(1,898
|
)
|
||
Additions to Equity Method Investments
|
(6
|
)
|
|
(65
|
)
|
||
Proceeds from Divestitures and Other
|
767
|
|
|
151
|
|
||
Net Cash Used in Investing Activities
|
(51
|
)
|
|
(1,812
|
)
|
||
Cash Flows From Financing Activities
|
|
|
|
|
|
||
Dividends Paid, Common Stock
|
(86
|
)
|
|
(134
|
)
|
||
Proceeds from Issuance of Shares of Common Stock to Public, Net of Offering Costs
|
—
|
|
|
1,112
|
|
||
Proceeds from Term Loan Facility
|
1,400
|
|
|
—
|
|
||
Repayment of Senior Notes
|
(1,383
|
)
|
|
—
|
|
||
Repayment of Capital Lease Obligation
|
(27
|
)
|
|
(29
|
)
|
||
Other
|
(21
|
)
|
|
(8
|
)
|
||
Net Cash (Used in) Provided by Financing Activities
|
(117
|
)
|
|
941
|
|
||
Increase in Cash and Cash Equivalents
|
272
|
|
|
95
|
|
||
Cash and Cash Equivalents at Beginning of Period
|
1,028
|
|
|
1,183
|
|
||
Cash and Cash Equivalents at End of Period
|
$
|
1,300
|
|
|
$
|
1,278
|
|
|
Common
Stock
|
|
Additional
Paid in
Capital
|
|
Accumulated Other
Comprehensive
Loss
|
|
Treasury
Stock at
Cost
|
|
Retained
Earnings
|
|
Total
Shareholders'
Equity
|
|||||||||||||
December 31, 2015
|
$
|
5
|
|
|
$
|
6,360
|
|
|
$
|
(33
|
)
|
|
$
|
(688
|
)
|
|
$
|
4,726
|
|
|
$
|
10,370
|
|
|
Net Loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(602
|
)
|
|
(602
|
)
|
|||||||
Stock-based Compensation
|
—
|
|
|
36
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
36
|
|
|||||||
Dividends (20 cents per share)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(86
|
)
|
|
(86
|
)
|
|||||||
Other
|
—
|
|
|
2
|
|
|
1
|
|
|
(8
|
)
|
|
—
|
|
|
(5
|
)
|
|||||||
June 30, 2016
|
$
|
5
|
|
|
$
|
6,398
|
|
|
$
|
(32
|
)
|
|
$
|
(696
|
)
|
|
$
|
4,038
|
|
|
$
|
9,713
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
December 31, 2014
|
$
|
4
|
|
|
$
|
3,624
|
|
|
$
|
(90
|
)
|
|
$
|
(671
|
)
|
|
$
|
7,458
|
|
|
$
|
10,325
|
|
|
Net Loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(131
|
)
|
|
(131
|
)
|
|||||||
Stock-based Compensation
|
—
|
|
|
38
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
38
|
|
|||||||
Dividends (36 cents per share)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(134
|
)
|
|
(134
|
)
|
|||||||
Issuance of Shares of Common Stock to Public, Net of Offering Costs
|
—
|
|
|
1,112
|
|
|
—
|
|
|
—
|
|
—
|
|
—
|
|
|
1,112
|
|
||||||
Other
|
—
|
|
|
4
|
|
|
7
|
|
|
(12
|
)
|
|
—
|
|
|
(1
|
)
|
|||||||
June 30, 2015
|
$
|
4
|
|
|
$
|
4,778
|
|
|
$
|
(83
|
)
|
|
$
|
(683
|
)
|
|
$
|
7,193
|
|
|
$
|
11,209
|
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
(millions)
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Production Expense
|
|
|
|
|
|
|
|
|
|
||||||
Lease Operating Expense
|
$
|
119
|
|
|
$
|
129
|
|
|
$
|
281
|
|
|
$
|
286
|
|
Production and Ad Valorem Taxes
|
40
|
|
|
28
|
|
|
43
|
|
|
61
|
|
||||
Transportation and Gathering Expense
(1)
|
115
|
|
|
61
|
|
|
222
|
|
|
122
|
|
||||
Total
|
$
|
274
|
|
|
$
|
218
|
|
|
$
|
546
|
|
|
$
|
469
|
|
Other Operating (Income) Expense, Net
|
|
|
|
|
|
|
|
|
|
||||||
Loss on Asset Due to Terminated Contract
(2)
|
$
|
5
|
|
|
$
|
—
|
|
|
$
|
47
|
|
|
$
|
—
|
|
Marketing and Processing Expense, Net
(3)
|
15
|
|
|
12
|
|
|
37
|
|
|
22
|
|
||||
Loss (Gain) on Divestitures
|
23
|
|
|
(1
|
)
|
|
23
|
|
|
—
|
|
||||
Corporate Restructuring Expense
|
—
|
|
|
18
|
|
|
1
|
|
|
18
|
|
||||
Purchase Price Allocation Adjustment
(4)
|
(25
|
)
|
|
—
|
|
|
(25
|
)
|
|
—
|
|
||||
Gain on Extinguishment of Debt
(5)
|
—
|
|
|
—
|
|
|
(80
|
)
|
|
—
|
|
||||
Asset Impairments
|
—
|
|
|
15
|
|
|
—
|
|
|
43
|
|
||||
Pension Plan Expense
|
—
|
|
|
21
|
|
|
—
|
|
|
21
|
|
||||
Stacked Drilling Rig Expense
|
3
|
|
|
7
|
|
|
5
|
|
|
7
|
|
||||
Other, Net
|
(4
|
)
|
|
13
|
|
|
12
|
|
|
10
|
|
||||
Total
|
$
|
17
|
|
|
$
|
85
|
|
|
$
|
20
|
|
|
$
|
121
|
|
Other Non-Operating Expense (Income), Net
|
|
|
|
|
|
|
|
|
|
||||||
Deferred Compensation Expense (Income)
(6)
|
$
|
5
|
|
|
$
|
(7
|
)
|
|
$
|
5
|
|
|
$
|
(5
|
)
|
Other Expense (Income), Net
|
2
|
|
|
(2
|
)
|
|
(2
|
)
|
|
(4
|
)
|
||||
Total
|
$
|
7
|
|
|
$
|
(9
|
)
|
|
$
|
3
|
|
|
$
|
(9
|
)
|
(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 and prior year amounts of
$10 million
and
$19 million
for the three and six months ended June 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
8. Capitalized Exploratory Well Costs and Undeveloped Leasehold
and
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Executive Overview - Exploration Program Update
.
|
(3)
|
For the three months and six months ended June 30, 2016, amount includes
$7 million
and
$23 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
3. Rosetta Merger
.
|
(5)
|
Amount relates to the tendering of senior notes assumed in the Rosetta Merger.
See Note
6. Debt
.
|
(6)
|
Amounts represent decreases (increases) in the fair value of shares of our common stock held in a rabbi trust.
|
(millions)
|
June 30,
2016 |
|
December 31,
2015 |
||||
Accounts Receivable, Net
|
|
|
|
||||
Commodity Sales
|
$
|
338
|
|
|
$
|
298
|
|
Joint Interest Billings
|
19
|
|
|
20
|
|
||
Proceeds Receivable
(1)
|
40
|
|
|
—
|
|
||
Severance Tax Refund
(2)
|
28
|
|
|
—
|
|
||
Other
|
75
|
|
|
151
|
|
||
Allowance for Doubtful Accounts
|
(24
|
)
|
|
(19
|
)
|
||
Total
|
$
|
476
|
|
|
$
|
450
|
|
Other Current Assets
|
|
|
|
|
|
||
Inventories, Materials and Supplies
|
$
|
93
|
|
|
$
|
92
|
|
Inventories, Crude Oil
|
25
|
|
|
23
|
|
||
Assets Held for Sale
(3)
|
18
|
|
|
67
|
|
||
Prepaid Expenses and Other Current Assets
|
48
|
|
|
34
|
|
||
Total
|
$
|
184
|
|
|
$
|
216
|
|
Other Noncurrent Assets
|
|
|
|
|
|
||
Investments in Unconsolidated Subsidiaries
|
$
|
467
|
|
|
$
|
453
|
|
Mutual Fund Investments
|
79
|
|
|
90
|
|
||
Commodity Derivative Assets
|
—
|
|
|
10
|
|
||
Other Assets
|
47
|
|
|
67
|
|
||
Total
|
$
|
593
|
|
|
$
|
620
|
|
Other Current Liabilities
|
|
|
|
|
|
||
Production and Ad Valorem Taxes
|
$
|
142
|
|
|
$
|
166
|
|
Commodity Derivative Liabilities
|
35
|
|
|
—
|
|
||
Income Taxes Payable
|
35
|
|
|
86
|
|
||
Asset Retirement Obligations
|
128
|
|
|
128
|
|
||
Interest Payable
|
75
|
|
|
83
|
|
||
Current Portion of Capital Lease Obligations
|
56
|
|
|
53
|
|
||
Other
|
124
|
|
|
161
|
|
||
Total
|
$
|
595
|
|
|
$
|
677
|
|
Other Noncurrent Liabilities
|
|
|
|
|
|
||
Deferred Compensation Liabilities
|
$
|
225
|
|
|
$
|
217
|
|
Asset Retirement Obligations
|
855
|
|
|
861
|
|
||
Production and Ad Valorem Taxes
|
21
|
|
|
68
|
|
||
Commodity Derivative Liabilities
|
31
|
|
|
—
|
|
||
Other
|
41
|
|
|
73
|
|
||
Total
|
$
|
1,173
|
|
|
$
|
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)
|
Amount relates to the accrual of a
$28 million
onshore US severance tax receivable.
|
(3)
|
Assets held for sale at June 30, 2016 include certain producing and undeveloped crude oil and natural gas interests in the DJ Basin, while assets held for sale at December 31, 2015 include the Karish and Tanin natural gas discoveries, offshore Israel.
See Note
4. Divestitures
.
|
|
(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
June 30, |
Six Months Ended
June 30, |
||||||||||
(in millions, except per share amounts)
|
2016
(1)
|
2015
|
2016
(1)
|
2015
|
||||||||
Revenues
|
$
|
847
|
|
$
|
881
|
|
$
|
1,571
|
|
$
|
1,773
|
|
Net Loss
|
$
|
(315
|
)
|
$
|
(125
|
)
|
$
|
(602
|
)
|
$
|
(145
|
)
|
|
|
|
|
|
||||||||
Loss per share
|
|
|
|
|
||||||||
Basic
|
$
|
(0.73
|
)
|
$
|
(0.29
|
)
|
$
|
(1.40
|
)
|
$
|
(0.35
|
)
|
Diluted
|
$
|
(0.73
|
)
|
$
|
(0.29
|
)
|
$
|
(1.40
|
)
|
$
|
(0.35
|
)
|
(1)
|
No pro forma adjustments were made for the period as the acquisition is included in the Company's historical results.
|
•
|
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;
|
•
|
sold other certain onshore US crude oil and natural gas properties, generating net proceeds of
$20 million
. Proceeds were primarily applied to the DJ Basin depletable field, with no recognition of gain or loss;
|
•
|
entered into a purchase and sale agreement for the divestiture of certain producing and undeveloped crude oil and natural gas interests covering approximately
33,100
producing and undeveloped net acres in the DJ Basin for
$505 million
, subject to customary closing adjustments. We received proceeds of
$486 million
and expect to receive the remaining consideration, subject to post-close adjustments, around year-end 2016. Proceeds were primarily applied to the DJ Basin depletable field, with no recognition of gain or loss; and
|
•
|
executed an acreage exchange agreement to receive approximately
11,700
net acres within our Wells Ranch development area in exchange for approximately
13,500
net acres primarily from our Bronco area, located southwest of Wells Ranch. No gain or loss was recognized for the transaction.
|
|
|
|
|
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 2016 and 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
|
Swaptions
(3)
|
NYMEX HH
|
60,000
|
—
|
|
|
—
|
|
—
|
|
3.14
|
|
|
2017
|
Three-Way Collars
|
NYMEX HH
|
100,000
|
—
|
|
|
2.50
|
|
2.87
|
|
3.48
|
|
|
2017
|
Two-Way Collars
|
NYMEX HH
|
20,000
|
—
|
|
|
—
|
|
2.75
|
|
3.02
|
|
|
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
|
||||||||||||||||||||
|
June 30,
2016 |
|
December 31,
2015 |
|
June 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
|
|
$
|
229
|
|
|
Current Assets
|
|
$
|
582
|
|
|
Current Liabilities
|
|
$
|
35
|
|
|
Current Liabilities
|
|
$
|
—
|
|
|
Noncurrent Assets
|
|
—
|
|
|
Noncurrent Assets
|
|
10
|
|
|
Noncurrent Liabilities
|
|
31
|
|
|
Noncurrent Liabilities
|
|
—
|
|
||||
Total
|
|
|
$
|
229
|
|
|
|
|
$
|
592
|
|
|
|
|
$
|
66
|
|
|
|
|
$
|
—
|
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
(millions)
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Cash Received in Settlement of Commodity Derivative Instruments
|
|
|
|
|
|
|
|
||||||||
Crude Oil
|
$
|
(120
|
)
|
|
$
|
(157
|
)
|
|
$
|
(276
|
)
|
|
$
|
(342
|
)
|
Natural Gas
|
(24
|
)
|
|
(30
|
)
|
|
(46
|
)
|
|
(55
|
)
|
||||
Total Cash Received in Settlement of Commodity Derivative Instruments
|
(144
|
)
|
|
(187
|
)
|
|
(322
|
)
|
|
(397
|
)
|
||||
Non-cash Portion of Loss on Commodity Derivative Instruments
|
|
|
|
|
|
|
|
||||||||
Crude Oil
|
233
|
|
|
242
|
|
|
360
|
|
|
297
|
|
||||
Natural Gas
|
62
|
|
|
32
|
|
|
69
|
|
|
37
|
|
||||
Total Non-cash Portion of Loss on Commodity Derivative Instruments
|
295
|
|
|
274
|
|
|
429
|
|
|
334
|
|
||||
Loss (Gain) on Commodity Derivative Instruments
|
|
|
|
|
|
|
|
||||||||
Crude Oil
|
113
|
|
|
85
|
|
|
84
|
|
|
(45
|
)
|
||||
Natural Gas
|
38
|
|
|
2
|
|
|
23
|
|
|
(18
|
)
|
||||
Total Loss (Gain) on Commodity Derivative Instruments
|
$
|
151
|
|
|
$
|
87
|
|
|
$
|
107
|
|
|
$
|
(63
|
)
|
|
June 30,
2016 |
|
December 31,
2015 |
||||||||||
(millions, except percentages)
|
Debt
|
|
Interest Rate
|
|
Debt
|
|
Interest Rate
|
||||||
Revolving Credit Facility, due August 27, 2020
|
$
|
—
|
|
|
—
|
%
|
|
$
|
—
|
|
|
—
|
%
|
Capital Lease and Other Obligations
|
377
|
|
|
—
|
%
|
|
403
|
|
|
—
|
%
|
||
Term Loan Facility, due January 6, 2019
|
1,400
|
|
|
1.71
|
%
|
|
—
|
|
|
—
|
%
|
||
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
|
7,966
|
|
|
|
|
7,976
|
|
|
|
|
|||
Unamortized Discount
|
(23
|
)
|
|
|
|
|
(24
|
)
|
|
|
|
||
Unamortized Premium
|
18
|
|
|
|
|
113
|
|
|
|
||||
Unamortized Debt Issuance Costs
|
(37
|
)
|
|
|
|
(36
|
)
|
|
|
||||
Total Debt, Net of Unamortized Discount, Premium and Debt Issuance Costs
|
7,924
|
|
|
|
|
|
8,029
|
|
|
|
|
||
Less Amounts Due Within One Year
|
|
|
|
|
|
|
|
|
|
|
|
||
Capital Lease Obligations
|
(56
|
)
|
|
|
|
|
(53
|
)
|
|
|
|
||
Long-Term Debt Due After One Year
|
$
|
7,868
|
|
|
|
|
|
$
|
7,976
|
|
|
|
|
|
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)
|
|
|
|
|
|
|
|
|
|
||||||||||
June 30, 2016
|
|
|
|
|
|
|
|
|
|
||||||||||
Financial Assets
|
|
|
|
|
|
|
|
|
|
||||||||||
Mutual Fund Investments
|
$
|
79
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
79
|
|
Commodity Derivative Instruments
|
—
|
|
|
237
|
|
|
—
|
|
|
(8
|
)
|
|
229
|
|
|||||
Financial Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Commodity Derivative Instruments
|
—
|
|
|
(74
|
)
|
|
—
|
|
|
8
|
|
|
(66
|
)
|
|||||
Portion of Deferred Compensation Liability Measured at Fair Value
|
(102
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(102
|
)
|
|||||
Portion of Stock Based Compensation Liability Measured at Fair Value
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
|||||
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)
|
|
|
|
|
|
|
|
|
|
||||||||||
Three Months Ended June 30, 2016
|
|
|
|
|
|
|
|
|
|||||||||||
Impaired Oil and Gas Properties
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Three Months Ended June 30, 2015
|
|
|
|
|
|
|
|
|
|||||||||||
Impaired Oil and Gas Properties
|
—
|
|
|
—
|
|
|
—
|
|
|
15
|
|
|
15
|
|
|||||
Six Months Ended June 30, 2016
|
|
|
|
|
|
|
|
|
|||||||||||
Impaired Oil and Gas Properties
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Six Months Ended June 30, 2015
|
|
|
|
|
|
|
|
|
|||||||||||
Impaired Oil and Gas Properties
|
—
|
|
|
—
|
|
|
—
|
|
|
43
|
|
|
43
|
|
(1)
|
Amount represents net book value at the date of assessment.
|
|
June 30,
2016 |
|
December 31,
2015 |
||||||||||||
(millions)
|
Carrying Amount
|
|
Fair Value
|
|
Carrying Amount
|
|
Fair Value
|
||||||||
Long-Term Debt, Net
(1)
|
$
|
7,547
|
|
|
$
|
7,936
|
|
|
$
|
7,626
|
|
|
$
|
7,105
|
|
(1)
|
Net of unamortized discount, premium and debt issuance costs and excludes capital lease and other obligations.
|
(millions)
|
Six Months Ended June 30, 2016
|
||
Capitalized Exploratory Well Costs, Beginning of Period
|
$
|
1,353
|
|
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves
|
68
|
|
|
Divestitures
(1)
|
(143
|
)
|
|
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves
|
(4
|
)
|
|
Capitalized Exploratory Well Costs Charged to Expense
(2)
|
(82
|
)
|
|
Capitalized Exploratory Well Costs, End of Period
|
$
|
1,192
|
|
(1)
|
Represents our farm-out 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)
|
June 30,
2016 |
|
December 31,
2015 |
||||
Exploratory Well Costs Capitalized for a Period of One Year or Less
|
$
|
86
|
|
|
$
|
95
|
|
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling
|
1,106
|
|
|
1,258
|
|
||
Balance at End of Period
|
$
|
1,192
|
|
|
$
|
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
|
$
|
51
|
|
|
Evaluating development scenarios for this 2013 natural gas discovery including subsea tieback to existing infrastructure.
|
Katmai
|
95
|
|
|
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 39, were temporarily abandoned as a result of encountering high pressure in the untested fault block. Plans to complete appraisal of the discovery at a future date are being developed.
|
|
Offshore Equatorial Guinea (Blocks I and O)
|
|
|
|
|
|
Diega (Block I) and Carmen (Block O)
|
237
|
|
|
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 are interpreting and evaluating the acquired seismic data.
|
|
Carla (Block O)
|
182
|
|
|
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 are interpreting and evaluating the acquired seismic data.
|
|
Yolanda/Felicita
|
66
|
|
|
Evaluating regional development plans for these 2007/2008 condensate and natural gas discoveries. A natural gas development team is working with the governments of Equatorial Guinea and Cameroon to evaluate natural gas monetization options and finalize a data exchange agreement between the two countries.
|
|
Offshore Cameroon
|
|
|
|
|
|
YoYo
|
52
|
|
|
Evaluating regional development plans for this 2007 condensate and natural gas discovery. A natural gas development team is working with the governments of Cameroon and Equatorial Guinea to evaluate natural gas monetization options and finalize a data exchange agreement between the two countries. Our 50% working interest partner has given notice to us and the Cameroon government of their intention to exit this acreage position. Once the assignment process is finalized, we will hold 100% operating working interest. We are marketing this additional 50% working interest.
|
|
Offshore Israel
|
|
|
|
|
|
Leviathan
|
194
|
|
|
Our development plan was approved by the Government and we are engaged in natural gas marketing activities to meet both Israeli domestic and regional export demands.
|
|
Leviathan-1 Deep
|
83
|
|
|
The well did not reach the target interval. 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
|
87
|
|
|
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
|
28
|
|
|
Continuing to assess and evaluate wells.
|
|
Total
|
$
|
1,106
|
|
|
|
|
Six Months Ended
June 30, |
||||||
(millions)
|
2016
|
|
2015
|
||||
Asset Retirement Obligations, Beginning Balance
|
$
|
989
|
|
|
$
|
751
|
|
Liabilities Incurred
|
3
|
|
|
16
|
|
||
Liabilities Settled
|
(38
|
)
|
|
(15
|
)
|
||
Revision of Estimate
|
4
|
|
|
79
|
|
||
Accretion Expense
(1)
|
25
|
|
|
21
|
|
||
Asset Retirement Obligations, Ending Balance
|
$
|
983
|
|
|
$
|
852
|
|
(1)
|
Accretion expense is included in Depreciation, Depletion and Amortization (DD&A)
expense in the consolidated statements of
operations.
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
(millions, except per share amounts)
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Net Loss
|
$
|
(315
|
)
|
|
$
|
(109
|
)
|
|
$
|
(602
|
)
|
|
$
|
(131
|
)
|
|
|
|
|
|
|
|
|
||||||||
Weighted Average Number of Shares Outstanding, Basic
(1)
|
430
|
|
|
387
|
|
|
429
|
|
|
378
|
|
||||
Weighted Average Number of Shares Outstanding, Diluted
(2)
|
430
|
|
|
387
|
|
|
429
|
|
|
378
|
|
||||
Loss Per Share, Basic
|
$
|
(0.73
|
)
|
|
$
|
(0.28
|
)
|
|
$
|
(1.40
|
)
|
|
$
|
(0.35
|
)
|
Loss Per Share, Diluted
|
(0.73
|
)
|
|
(0.28
|
)
|
|
(1.40
|
)
|
|
(0.35
|
)
|
||||
Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above
|
15
|
|
|
10
|
|
|
15
|
|
|
9
|
|
(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
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
(millions)
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Current
|
$
|
45
|
|
|
$
|
99
|
|
|
$
|
65
|
|
|
$
|
109
|
|
Deferred
|
(228
|
)
|
|
(283
|
)
|
|
(414
|
)
|
|
(312
|
)
|
||||
Total Income Tax Benefit
|
$
|
(183
|
)
|
|
$
|
(184
|
)
|
|
$
|
(349
|
)
|
|
$
|
(203
|
)
|
Effective Tax Rate
|
36.7
|
%
|
|
62.8
|
%
|
|
36.7
|
%
|
|
60.8
|
%
|
(millions)
|
Consolidated
|
|
United
States
|
|
West
Africa
|
|
Eastern
Mediterranean
|
|
Other Int'l &
Corporate
|
||||||||||
Three Months Ended June 30, 2016
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues from Third Parties
|
$
|
823
|
|
|
$
|
576
|
|
|
$
|
116
|
|
|
$
|
131
|
|
|
$
|
—
|
|
Income from Equity Method Investees
|
24
|
|
|
15
|
|
|
9
|
|
|
—
|
|
|
—
|
|
|||||
Total Revenues
|
847
|
|
|
591
|
|
|
125
|
|
|
131
|
|
|
—
|
|
|||||
DD&A
|
622
|
|
|
544
|
|
|
49
|
|
|
19
|
|
|
10
|
|
|||||
Loss on Divestitures
|
23
|
|
|
23
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Loss on Commodity Derivative Instruments
|
151
|
|
|
129
|
|
|
22
|
|
|
—
|
|
|
—
|
|
|||||
(Loss) Income Before Income Taxes
|
(498
|
)
|
|
(183
|
)
|
|
18
|
|
|
71
|
|
|
(404
|
)
|
|||||
Three Months Ended June 30, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Revenues from Third Parties
|
$
|
732
|
|
|
$
|
451
|
|
|
$
|
174
|
|
|
$
|
106
|
|
|
$
|
1
|
|
Income (Loss) from Equity Method Investees
|
6
|
|
|
8
|
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
|||||
Total Revenues
|
738
|
|
|
459
|
|
|
172
|
|
|
106
|
|
|
1
|
|
|||||
DD&A
|
451
|
|
|
344
|
|
|
79
|
|
|
15
|
|
|
13
|
|
|||||
Gain on Divestitures
|
(1
|
)
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Asset Impairments
|
15
|
|
|
8
|
|
|
—
|
|
|
7
|
|
|
—
|
|
|||||
Loss on Commodity Derivative Instruments
|
87
|
|
|
62
|
|
|
25
|
|
|
—
|
|
|
—
|
|
|||||
(Loss) Income Before Income Taxes
|
(293
|
)
|
|
(163
|
)
|
|
23
|
|
|
69
|
|
|
(222
|
)
|
|||||
Six Months Ended June 30, 2016
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues from Third Parties
|
$
|
1,528
|
|
|
$
|
1,065
|
|
|
$
|
206
|
|
|
$
|
257
|
|
|
$
|
—
|
|
Income from Equity Method Investees
|
43
|
|
|
31
|
|
|
12
|
|
|
—
|
|
|
—
|
|
|||||
Total Revenues
|
1,571
|
|
|
1,096
|
|
|
218
|
|
|
257
|
|
|
—
|
|
|||||
DD&A
|
1,239
|
|
|
1,074
|
|
|
104
|
|
|
39
|
|
|
22
|
|
|||||
Loss on Divestitures
|
23
|
|
|
23
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Loss on Commodity Derivative Instruments
|
107
|
|
|
92
|
|
|
15
|
|
|
—
|
|
|
—
|
|
|||||
(Loss) Income Before Income Taxes
|
(951
|
)
|
|
(475
|
)
|
|
27
|
|
|
155
|
|
|
(658
|
)
|
|||||
Six Months Ended June 30, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Revenues from Third Parties
|
$
|
1,481
|
|
|
$
|
938
|
|
|
$
|
312
|
|
|
$
|
226
|
|
|
$
|
5
|
|
Income from Equity Method Investees
|
24
|
|
|
19
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|||||
Total Revenues
|
1,505
|
|
|
957
|
|
|
317
|
|
|
226
|
|
|
5
|
|
|||||
DD&A
|
905
|
|
|
701
|
|
|
156
|
|
|
30
|
|
|
18
|
|
|||||
Gain on Divestitures
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Asset Impairments
|
43
|
|
|
11
|
|
|
—
|
|
|
32
|
|
|
—
|
|
|||||
Gain on Commodity Derivative Instruments
|
(63
|
)
|
|
(43
|
)
|
|
(20
|
)
|
|
—
|
|
|
—
|
|
|||||
(Loss) Income Before Income Taxes
|
(334
|
)
|
|
(164
|
)
|
|
97
|
|
|
120
|
|
|
(387
|
)
|
|||||
June 30, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Total Assets
|
$
|
22,516
|
|
|
$
|
17,742
|
|
|
$
|
2,087
|
|
|
$
|
2,424
|
|
|
$
|
263
|
|
December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Total Assets
|
24,196
|
|
|
18,831
|
|
|
2,299
|
|
|
2,677
|
|
|
389
|
|
•
|
•
|
•
|
Results of Operations
; and
|
•
|
•
|
continued 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 record quarterly total sales volumes of
427
MBoe/d, net, including a record 282 MBoe/d, net, from onshore US assets;
|
•
|
set a second quarter net sales volume record of
276
MMcf/d in Israel, primarily reflecting seasonal demand and increased use of natural gas over coal to fuel power generation;
|
•
|
received approval of our Leviathan development plan and a new economic stability provision as part of the Natural Gas Framework (Framework) was adopted. We continue to work towards a final investment decision to develop the infrastructure needed to supply domestic and regional demand;
|
•
|
recorded expense of $27 million related to our Dolphin 1 natural gas discovery offshore Israel lease expiry resulting from the fact the Petroleum Commissioner of Israel deemed the discovery to be non-commercial;
|
•
|
continued to enhance well completion designs across our onshore US assets leading to capital efficiencies;
|
•
|
suspended drilling operations temporarily at the Katmai 2 appraisal well, deepwater Gulf of Mexico;
|
•
|
completed hook-up and commissioning activities at the Alba B3 compression project, offshore Equatorial Guinea, and commenced production in July 2016;
|
•
|
entered into an agreement to divest certain producing and undeveloped crude oil and natural gas interests in Colorado for
$505 million
and executed an exchange acreage to further enhance our Wells Ranch position in Colorado;
|
•
|
entered into an agreement on July 4, 2016, subsequent to quarter-end, for the divestiture of 3% working interest in the Tamar field for $369 million.
See Item 1. Financial Statements – Note
4. Divestitures
; and
|
•
|
commenced production from our Gunflint field, deepwater Gulf of Mexico, in July 2016.
|
•
|
net loss of
$315 million
, as compared with net loss of
$109 million
for
second
quarter
2015
;
|
•
|
net loss on commodity derivative instruments of
$151 million
as compared with net loss on commodity derivative instruments of
$87 million
for
second
quarter
2015
;
|
•
|
reduced unit costs by 35% in lease operating expense and 28% in general and administrative expense as compared to second quarter 2015 driven by continued cost reduction initiatives and increased sales volumes;
|
•
|
other income of
$25 million
related to the finalization of purchase price accounting for the Rosetta Merger;
|
•
|
diluted loss per share of
$0.73
, as compared with diluted loss per share of
$0.28
for
second
quarter
2015
;
|
•
|
cash flow provided by operating activities of
$189 million
, as compared with
$425 million
for
second
quarter
2015
;
|
•
|
cash proceeds from divestitures of
$529 million
, as compared with
$32 million
for
second
quarter 2015; and
|
•
|
capital expenditures of
$262 million
, as compared with
$799 million
for
second
quarter
2015
.
|
•
|
ending cash balance of
$1.3 billion
, as compared with
$1.0 billion
at
December 31, 2015
;
|
•
|
total liquidity of approximately
$5.3 billion
at
June 30, 2016
, as compared with
$5.0 billion
at
December 31, 2015
; and
|
•
|
ratio of debt-to-book capital of
45%
at
June 30, 2016
, as compared with
43%
at
December 31, 2015
.
|
•
|
we have a high-quality, globally diversified portfolio of assets, the majority of which are held by production and provide investment flexibility;
|
•
|
we have achieved substantial cost reductions impacting both operating expenses and capital expenditures, including a significantly reduced capital investment program which allows us to respond to changing commodity price conditions in 2016, thereby positively impacting operating cash flows;
|
•
|
we have hedged a portion of our domestic natural gas and global liquids sales volumes and are partially hedged for 2017;
|
•
|
we have a strong balance sheet with a ratio of debt-to-book capital of
45%
at
June 30, 2016
; and
|
•
|
we have robust liquidity of approximately
$5.3 billion
at
June 30, 2016
and ability to access capital markets.
|
•
|
entered into an agreement to divest certain producing and undeveloped crude oil and natural gas interests in the DJ Basin for
$505 million
, receiving partial proceeds of
$486 million
;
|
•
|
executed an acreage exchange to further enhance our Wells Ranch position in the DJ Basin;
|
•
|
entered into an agreement on July 4, 2016 for the divestiture of 3% working interest in the Tamar field for $369 million, partially fulfilling our commitment required by the Framework; Under the terms of the agreement, the purchaser has the option to elect, before closing, to purchase an additional
1%
working interest at the same valuation;
|
•
|
closed the sale of certain smaller onshore US property packages resulting in net proceeds of
$63 million
;
|
•
|
closed the divestiture of our interest in the Karish and Tanin fields for
$73 million
in first quarter 2016; and
|
•
|
closed our farm-out of 35% interest in the Aphrodite field having received partial payment of
$131 million
in first quarter 2016.
|
•
|
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 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, 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;
|
•
|
potential shut-in of US producing properties if storage capacity becomes unavailable;
|
•
|
potential drilling and/or completion permit delays due to future regulatory changes; and
|
•
|
potential purchases of producing properties or divestments of operating assets.
|
|
|
|
|
|
(Decrease) / Increase
from Prior Year |
|||||
(millions)
|
2016
|
|
2015
|
|
||||||
Three Months Ended June 30,
|
|
|
|
|
|
|||||
Oil, Gas and NGL Sales
|
$
|
823
|
|
|
$
|
732
|
|
|
12
|
%
|
Income from Equity Method Investees
|
24
|
|
|
6
|
|
|
300
|
%
|
||
Total
|
$
|
847
|
|
|
$
|
738
|
|
|
15
|
%
|
|
|
|
|
|
|
|||||
Six Months Ended June 30,
|
|
|
|
|
|
|||||
Oil, Gas and NGL Sales
|
$
|
1,528
|
|
|
$
|
1,481
|
|
|
3
|
%
|
Income from Equity Method Investees
|
43
|
|
|
24
|
|
|
79
|
%
|
||
Total
|
$
|
1,571
|
|
|
$
|
1,505
|
|
|
4
|
%
|
|
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 June 30, 2016
|
|||||||||||||||||||||||
United States
|
96
|
|
|
924
|
|
|
59
|
|
|
309
|
|
|
$
|
40.64
|
|
|
$
|
1.75
|
|
|
$
|
14.10
|
|
Equatorial Guinea
(2)
|
27
|
|
|
233
|
|
|
—
|
|
|
66
|
|
|
44.55
|
|
|
0.27
|
|
|
—
|
|
|||
Israel
|
—
|
|
|
276
|
|
|
—
|
|
|
46
|
|
|
—
|
|
|
5.15
|
|
|
—
|
|
|||
Total Consolidated Operations
|
123
|
|
|
1,433
|
|
|
59
|
|
|
421
|
|
|
41.51
|
|
|
2.16
|
|
|
14.10
|
|
|||
Equity Investees
(3)
|
1
|
|
|
—
|
|
|
5
|
|
|
6
|
|
|
49.94
|
|
|
—
|
|
|
27.64
|
|
|||
Total
|
124
|
|
|
1,433
|
|
|
64
|
|
|
427
|
|
|
$
|
41.61
|
|
|
$
|
2.16
|
|
|
$
|
15.07
|
|
Three Months Ended June 30, 2015
|
|||||||||||||||||||||||
United States
|
65
|
|
|
613
|
|
|
27
|
|
|
194
|
|
|
$
|
52.44
|
|
|
$
|
1.90
|
|
|
$
|
13.71
|
|
Equatorial Guinea
(2)
|
31
|
|
|
202
|
|
|
—
|
|
|
65
|
|
|
60.02
|
|
|
0.27
|
|
|
—
|
|
|||
Israel
|
—
|
|
|
215
|
|
|
—
|
|
|
36
|
|
|
—
|
|
|
5.34
|
|
|
—
|
|
|||
Total Consolidated Operations
|
96
|
|
|
1,030
|
|
|
27
|
|
|
295
|
|
|
54.91
|
|
|
2.30
|
|
|
13.71
|
|
|||
Equity Investees
(3)
|
1
|
|
|
—
|
|
|
3
|
|
|
4
|
|
|
60.34
|
|
|
—
|
|
|
33.34
|
|
|||
Total
|
97
|
|
|
1,030
|
|
|
30
|
|
|
299
|
|
|
$
|
54.95
|
|
|
$
|
2.30
|
|
|
$
|
15.70
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Six Months Ended June 30, 2016
|
|||||||||||||||||||||||
United States
|
99
|
|
|
917
|
|
|
56
|
|
|
308
|
|
|
$
|
35.22
|
|
|
$
|
1.82
|
|
|
$
|
12.73
|
|
Equatorial Guinea
(2)
|
27
|
|
|
214
|
|
|
—
|
|
|
63
|
|
|
39.53
|
|
|
0.27
|
|
|
—
|
|
|||
Israel
|
—
|
|
|
271
|
|
|
—
|
|
|
45
|
|
|
—
|
|
|
5.17
|
|
|
—
|
|
|||
Total Consolidated Operations
|
126
|
|
|
1,402
|
|
|
56
|
|
|
416
|
|
|
36.14
|
|
|
2.23
|
|
|
12.73
|
|
|||
Equity Investees
(3)
|
1
|
|
|
—
|
|
|
4
|
|
|
6
|
|
|
42.34
|
|
|
—
|
|
|
25.02
|
|
|||
Total
|
127
|
|
|
1,402
|
|
|
60
|
|
|
422
|
|
|
$
|
36.20
|
|
|
$
|
2.23
|
|
|
$
|
13.63
|
|
Six Months Ended June 30, 2015
|
|||||||||||||||||||||||
United States
|
69
|
|
|
616
|
|
|
26
|
|
|
198
|
|
|
$
|
48.20
|
|
|
$
|
2.31
|
|
|
$
|
16.11
|
|
Equatorial Guinea
(2)
|
30
|
|
|
216
|
|
|
—
|
|
|
66
|
|
|
54.97
|
|
|
0.27
|
|
|
—
|
|
|||
Israel
|
—
|
|
|
229
|
|
|
—
|
|
|
38
|
|
|
—
|
|
|
5.40
|
|
|
—
|
|
|||
Other International
(4)
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
55.52
|
|
|
—
|
|
|
—
|
|
|||
Total Consolidated Operations
|
100
|
|
|
1,061
|
|
|
26
|
|
|
303
|
|
|
50.29
|
|
|
2.56
|
|
|
16.11
|
|
|||
Equity Investees
(3)
|
1
|
|
|
—
|
|
|
4
|
|
|
6
|
|
|
51.86
|
|
|
—
|
|
|
31.27
|
|
|||
Total
|
101
|
|
|
1,061
|
|
|
30
|
|
|
309
|
|
|
$
|
50.31
|
|
|
$
|
2.56
|
|
|
$
|
18.33
|
|
(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.
|
(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 June 30, 2015
|
$
|
483
|
|
|
$
|
215
|
|
|
$
|
34
|
|
|
$
|
732
|
|
Changes due to
|
|
|
|
|
|
|
|
|
|
|
|
||||
Increase in Sales Volumes
|
90
|
|
|
81
|
|
|
40
|
|
|
211
|
|
||||
(Decrease) Increase in Sales Prices
|
(108
|
)
|
|
(14
|
)
|
|
2
|
|
|
(120
|
)
|
||||
Three Months Ended June 30, 2016
|
$
|
465
|
|
|
$
|
282
|
|
|
$
|
76
|
|
|
$
|
823
|
|
|
|
|
|
|
|
|
|
||||||||
Six Months Ended June 30, 2015
|
$
|
914
|
|
|
$
|
492
|
|
|
$
|
75
|
|
|
$
|
1,481
|
|
Changes due to
|
|
|
|
|
|
|
|
|
|
|
|||||
Increase in Sales Volumes
|
141
|
|
|
155
|
|
|
75
|
|
|
371
|
|
||||
Decrease in Sales Prices
|
(226
|
)
|
|
(78
|
)
|
|
(20
|
)
|
|
(324
|
)
|
||||
Six Months Ended June 30, 2016
|
$
|
829
|
|
|
$
|
569
|
|
|
$
|
130
|
|
|
$
|
1,528
|
|
•
|
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 deepwater Gulf of Mexico due to production from the Big Bend and Dantzler development projects, which began producing in fourth quarter 2015, which contributed 8 MBbl/d and 7 MBbl/d, net, respectively, during the first six months of 2016; and
|
•
|
sales volumes contributed by our Eagle Ford Shale and Permian Basin assets acquired in third quarter 2015, which contributed 12 MBbl/d and 6 MBbl/d, net, respectively, during the first six months of 2016.
|
•
|
quarterly sales volumes from the Tamar field, offshore Israel, which contributed
276
MMcf/d, net, in response to seasonal demand and the increased use of natural gas over coal to fuel power generation;
|
•
|
higher sales volumes in the Marcellus Shale due to commencing production on eight operated wells, our joint venture partner commencing production on 34 wells, and the recognition of efficiencies in base production performance; and
|
•
|
sales volumes contributed by our Eagle Ford Shale and Permian Basin assets acquired in third quarter 2015, which contributed 142 MMcf/d and 8 MMcf/d, net, respectively, during the first six 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 due to increased activity in East Pony and Wells Ranch; and
|
•
|
sales volumes contributed by our Eagle Ford Shale and Permian Basin assets acquired in third quarter 2015, which contributed 23 MBbl/d and 1 MBbl/d, net, respectively, during the first six months of 2016;
|
•
|
decreases in average realized prices primarily driven by oversupply.
|
|
|
|
|
|
Increase / (Decrease)
from Prior Year |
|||||
(millions)
|
2016
|
|
2015
|
|
||||||
Three Months Ended June 30,
|
|
|
|
|
|
|||||
Production Expense
|
$
|
274
|
|
|
$
|
218
|
|
|
26
|
%
|
Exploration Expense
|
89
|
|
|
41
|
|
|
117
|
%
|
||
Depreciation, Depletion and Amortization
|
622
|
|
|
451
|
|
|
38
|
%
|
||
General and Administrative
|
107
|
|
|
104
|
|
|
3
|
%
|
||
Other Operating (Income) Expense, Net
|
17
|
|
|
85
|
|
|
(80
|
)%
|
||
Total
|
$
|
1,109
|
|
|
$
|
899
|
|
|
23
|
%
|
|
|
|
|
|
|
|||||
Six Months Ended June 30,
|
|
|
|
|
|
|||||
Production Expense
|
$
|
546
|
|
|
$
|
469
|
|
|
16
|
%
|
Exploration Expense
|
252
|
|
|
106
|
|
|
138
|
%
|
||
Depreciation, Depletion and Amortization
|
1,239
|
|
|
905
|
|
|
37
|
%
|
||
General and Administrative
|
198
|
|
|
198
|
|
|
—
|
%
|
||
Other Operating Expense, Net
|
20
|
|
|
121
|
|
|
(83
|
)%
|
||
Total
|
$
|
2,255
|
|
|
$
|
1,799
|
|
|
25
|
%
|
(millions, except unit rate)
|
Total per BOE
(1)
|
|
Total
|
|
United
States
|
|
Equatorial Guinea
|
|
Israel
|
|
Corporate
|
||||||||||||
Three Months Ended June 30, 2016
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Lease Operating Expense
(2)
|
$
|
3.11
|
|
|
$
|
119
|
|
|
$
|
86
|
|
|
$
|
24
|
|
|
$
|
7
|
|
|
$
|
2
|
|
Production and Ad Valorem Taxes
|
1.04
|
|
|
40
|
|
|
40
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Transportation and Gathering Expense
(3)
|
3.00
|
|
|
115
|
|
|
115
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total Production Expense
|
$
|
7.15
|
|
|
$
|
274
|
|
|
$
|
241
|
|
|
$
|
24
|
|
|
$
|
7
|
|
|
$
|
2
|
|
Total Production Expense per BOE
|
|
|
$
|
7.15
|
|
|
$
|
8.58
|
|
|
$
|
3.99
|
|
|
$
|
1.66
|
|
|
N/M
|
|
|||
Three Months Ended June 30, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Lease Operating Expense
(2)
|
$
|
4.80
|
|
|
$
|
129
|
|
|
$
|
80
|
|
|
$
|
36
|
|
|
$
|
12
|
|
|
$
|
1
|
|
Production and Ad Valorem Taxes
|
1.05
|
|
|
28
|
|
|
28
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Transportation and Gathering Expense
(3)
|
2.27
|
|
|
61
|
|
|
61
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total Production Expense
|
$
|
8.12
|
|
|
$
|
218
|
|
|
$
|
169
|
|
|
$
|
36
|
|
|
$
|
12
|
|
|
$
|
1
|
|
Total Production Expense per BOE
|
|
|
$
|
8.12
|
|
|
$
|
9.55
|
|
|
$
|
6.15
|
|
|
$
|
3.65
|
|
|
N/M
|
|
|||
Six Months Ended June 30, 2016
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Lease Operating Expense
(2)
|
$
|
3.71
|
|
|
$
|
281
|
|
|
$
|
207
|
|
|
$
|
53
|
|
|
$
|
17
|
|
|
$
|
4
|
|
Production and Ad Valorem Taxes
|
0.57
|
|
|
43
|
|
|
43
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Transportation and Gathering Expense
(3)
|
2.93
|
|
|
222
|
|
|
222
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total Production Expense
|
$
|
7.21
|
|
|
$
|
546
|
|
|
$
|
472
|
|
|
$
|
53
|
|
|
$
|
17
|
|
|
$
|
4
|
|
Total Production Expense per BOE
|
|
|
$
|
7.21
|
|
|
$
|
8.43
|
|
|
$
|
4.63
|
|
|
$
|
2.05
|
|
|
N/M
|
|
|||
Six Months Ended June 30, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Lease Operating Expense
(2)
|
$
|
5.21
|
|
|
$
|
286
|
|
|
$
|
182
|
|
|
$
|
70
|
|
|
$
|
25
|
|
|
$
|
9
|
|
Production and Ad Valorem Taxes
|
1.11
|
|
|
61
|
|
|
61
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Transportation and Gathering Expense
(3)
|
2.22
|
|
|
122
|
|
|
122
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total Production Expense
|
$
|
8.54
|
|
|
$
|
469
|
|
|
$
|
365
|
|
|
$
|
70
|
|
|
$
|
25
|
|
|
$
|
9
|
|
Total Production Expense per BOE
|
|
|
$
|
8.54
|
|
|
$
|
10.20
|
|
|
$
|
5.83
|
|
|
$
|
3.59
|
|
|
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 lease operating and 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, deepwater Gulf of Mexico, which began producing in fourth quarter 2015;
|
•
|
a decrease in lease operating expense due to continued focus on cost reduction and efficiency initiatives; and
|
•
|
a decrease in production and ad valorem taxes resulting from lower revenues and an onshore US severance tax receivable, 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 June 30, 2016
|
|
|
|
|
|
|
|
|
|||||||||||
Leasehold Impairment and Amortization
|
$
|
16
|
|
|
$
|
16
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Dry Hole Expense
|
27
|
|
|
—
|
|
|
—
|
|
|
27
|
|
|
—
|
|
|||||
Seismic, Geological and Geophysical
|
23
|
|
|
—
|
|
|
10
|
|
|
—
|
|
|
13
|
|
|||||
Staff Expense
|
21
|
|
|
20
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|||||
Other
(4)
|
2
|
|
|
6
|
|
|
(1
|
)
|
|
—
|
|
|
(3
|
)
|
|||||
Total Exploration Expense
|
$
|
89
|
|
|
$
|
42
|
|
|
$
|
10
|
|
|
$
|
27
|
|
|
$
|
10
|
|
Three Months Ended June 30, 2015
|
|
|
|
|
|
|
|
|
|||||||||||
Leasehold Impairment and Amortization
|
$
|
14
|
|
|
$
|
14
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Staff Expense
|
18
|
|
|
3
|
|
|
2
|
|
|
1
|
|
|
12
|
|
|||||
Other
(4)
|
9
|
|
|
—
|
|
|
3
|
|
|
1
|
|
|
5
|
|
|||||
Total Exploration Expense
|
$
|
41
|
|
|
$
|
17
|
|
|
$
|
5
|
|
|
$
|
2
|
|
|
$
|
17
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Six Months Ended June 30, 2016
|
|
|
|
|
|
|
|
|
|||||||||||
Leasehold Impairment and Amortization
|
$
|
31
|
|
|
$
|
31
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Dry Hole Expense
|
114
|
|
|
91
|
|
|
(1
|
)
|
|
27
|
|
|
(3
|
)
|
|||||
Seismic, Geological and Geophysical
|
32
|
|
|
—
|
|
|
10
|
|
|
—
|
|
|
22
|
|
|||||
Staff Expense
|
39
|
|
|
21
|
|
|
2
|
|
|
1
|
|
|
15
|
|
|||||
Other
(4)
|
36
|
|
|
23
|
|
|
—
|
|
|
7
|
|
|
6
|
|
|||||
Total Exploration Expense
|
$
|
252
|
|
|
$
|
166
|
|
|
$
|
11
|
|
|
$
|
35
|
|
|
$
|
40
|
|
Six Months Ended June 30, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Leasehold Impairment and Amortization
|
$
|
26
|
|
|
$
|
21
|
|
|
$
|
—
|
|
|
$
|
5
|
|
|
$
|
—
|
|
Dry Hole Expense
|
19
|
|
|
18
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|||||
Seismic, Geological and Geophysical
|
2
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Staff Expense
|
50
|
|
|
10
|
|
|
2
|
|
|
3
|
|
|
35
|
|
|||||
Other
(4)
|
9
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
8
|
|
|||||
Total Exploration Expense
|
$
|
106
|
|
|
$
|
51
|
|
|
$
|
3
|
|
|
$
|
9
|
|
|
$
|
43
|
|
(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.
|
•
|
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 the deepwater Gulf of Mexico, West Africa, and other international areas;
|
•
|
Other cost for 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 primarily to onshore US exploratory wells; and
|
•
|
salaries and related expenses for corporate exploration and new ventures personnel.
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
DD&A Expense (millions)
(1)
|
$
|
622
|
|
|
$
|
451
|
|
|
$
|
1,239
|
|
|
$
|
905
|
|
Unit Rate per BOE
(2)
|
$
|
16.23
|
|
|
$
|
16.77
|
|
|
$
|
16.37
|
|
|
$
|
16.50
|
|
(1)
|
For DD&A expense by geographical area, see
Item 1. Financial Statements – Note
12. 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 $98 million and $18 million in DD&A expense respectively, during the first six months of 2016;
|
•
|
an increase in the Marcellus Shale, Eastern Mediterranean and deepwater Gulf of Mexico due to higher sales volumes;
|
•
|
a reduction in proved reserves in fourth quarter 2015 primarily due to downward price revisions in DJ Basin and Marcellus Shale;
|
•
|
a decrease in sales volumes offshore Equatorial Guinea due to downtime installing the B3 compression platform and scheduled maintenance in the Alba field; 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
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
G&A Expense (millions)
|
$
|
107
|
|
|
$
|
104
|
|
|
$
|
198
|
|
|
$
|
198
|
|
Unit Rate per BOE
(1)
|
$
|
2.79
|
|
|
$
|
3.87
|
|
|
$
|
2.62
|
|
|
$
|
3.61
|
|
(1)
|
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
(millions)
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Loss on Asset Due to Terminated Contract
|
$
|
5
|
|
|
$
|
—
|
|
|
$
|
47
|
|
|
$
|
—
|
|
Marketing and Processing Expense, Net
|
15
|
|
|
12
|
|
|
37
|
|
|
22
|
|
||||
Loss (Gain) on Divestitures
|
23
|
|
|
(1
|
)
|
|
23
|
|
|
—
|
|
||||
Corporate Restructuring Expense
|
—
|
|
|
18
|
|
|
1
|
|
|
18
|
|
||||
Purchase Price Allocation Adjustment
|
(25
|
)
|
|
—
|
|
|
(25
|
)
|
|
—
|
|
||||
Gain on Extinguishment of Debt
|
—
|
|
|
—
|
|
|
(80
|
)
|
|
—
|
|
||||
Asset Impairments
|
—
|
|
|
15
|
|
|
—
|
|
|
43
|
|
||||
Pension Plan Expense
|
—
|
|
|
21
|
|
|
—
|
|
|
21
|
|
||||
Stacked Drilling Rig Expense
|
3
|
|
|
7
|
|
|
5
|
|
|
7
|
|
||||
Other, Net
|
(4
|
)
|
|
13
|
|
|
12
|
|
|
10
|
|
||||
Total
|
$
|
17
|
|
|
$
|
85
|
|
|
$
|
20
|
|
|
$
|
121
|
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
(millions)
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Loss (Gain) on Commodity Derivative Instruments
|
$
|
151
|
|
|
$
|
87
|
|
|
$
|
107
|
|
|
$
|
(63
|
)
|
Interest, Net of Amount Capitalized
|
78
|
|
|
54
|
|
|
157
|
|
|
112
|
|
||||
Other Non-Operating Expense (Income), Net
|
7
|
|
|
(9
|
)
|
|
3
|
|
|
(9
|
)
|
||||
Total
|
$
|
236
|
|
|
$
|
132
|
|
|
$
|
267
|
|
|
$
|
40
|
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
(millions, except unit rate)
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Interest Expense, Gross
|
$
|
102
|
|
|
$
|
92
|
|
|
$
|
209
|
|
|
$
|
185
|
|
Capitalized Interest
|
(24
|
)
|
|
(38
|
)
|
|
(52
|
)
|
|
(73
|
)
|
||||
Interest Expense, Net
|
$
|
78
|
|
|
$
|
54
|
|
|
$
|
157
|
|
|
$
|
112
|
|
Unit Rate per BOE
(1)
|
$
|
2.04
|
|
|
$
|
2.01
|
|
|
$
|
2.07
|
|
|
$
|
2.04
|
|
(1)
|
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees.
|
|
June 30,
|
|
December 31,
|
||||
(millions, except percentages)
|
2016
|
|
2015
|
||||
Cash and Cash Equivalents
|
$
|
1,300
|
|
|
$
|
1,028
|
|
Amount Available to be Borrowed Under Revolving Credit Facility
(1)
|
4,000
|
|
|
4,000
|
|
||
Total Liquidity
|
$
|
5,300
|
|
|
$
|
5,028
|
|
Total Debt
(2)
|
$
|
7,966
|
|
|
$
|
7,976
|
|
Total Shareholders' Equity
|
9,713
|
|
|
10,370
|
|
||
Ratio of Debt-to-Book Capital
(3)
|
45
|
%
|
|
43
|
%
|
(1)
|
See
Revolving Credit Facility,
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 shareholders’ equity.
|
|
Six Months Ended
June 30, |
||||||
(millions)
|
2016
|
|
2015
|
||||
Total Cash Provided By (Used in)
|
|
|
|
||||
Operating Activities
|
$
|
440
|
|
|
$
|
966
|
|
Investing Activities
|
(51
|
)
|
|
(1,812
|
)
|
||
Financing Activities
|
(117
|
)
|
|
941
|
|
||
Increase in Cash and Cash Equivalents
|
$
|
272
|
|
|
$
|
95
|
|
|
Three Months Ended
June 30, |
|
Six Months Ended
June 30, |
||||||||||||
(millions)
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Acquisition, Capital and Exploration Expenditures
|
|
|
|
|
|
|
|
||||||||
Property Acquisition
(1)
|
$
|
23
|
|
|
$
|
39
|
|
|
$
|
42
|
|
|
$
|
65
|
|
Exploration
|
58
|
|
|
71
|
|
|
156
|
|
|
140
|
|
||||
Development
|
166
|
|
|
593
|
|
|
394
|
|
|
1,237
|
|
||||
Midstream
|
5
|
|
|
39
|
|
|
20
|
|
|
97
|
|
||||
Corporate and Other
|
10
|
|
|
36
|
|
|
20
|
|
|
59
|
|
||||
Total
|
$
|
262
|
|
|
$
|
778
|
|
|
$
|
632
|
|
|
$
|
1,598
|
|
Other
|
|
|
|
|
|
|
|
||||||||
Investment in Equity Method Investee
(2)
|
$
|
—
|
|
|
$
|
21
|
|
|
$
|
6
|
|
|
$
|
65
|
|
Increase in Capital Lease Obligations
|
$
|
—
|
|
|
$
|
8
|
|
|
$
|
—
|
|
|
$
|
31
|
|
(1)
|
Property acquisition cost for 2016 includes $17 million in the DJ Basin, $16 million in the Marcellus Shale, $4 million in the Permian Basin and $3 million in the Eagle Ford Shale. Proved property acquisition cost for 2015 includes $26 million in the DJ Basin and $39 million in the Marcellus Shale.
|
(2)
|
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)
|
|||||
4/1/2016 - 4/30/2016
|
2,456
|
|
|
$
|
33.97
|
|
|
—
|
|
|
—
|
|
5/1/2016 - 5/31/2016
|
879
|
|
|
35.50
|
|
|
—
|
|
|
—
|
|
|
6/1/2016 - 6/30/2016
|
618
|
|
|
35.12
|
|
|
—
|
|
|
—
|
|
|
Total
|
3,953
|
|
|
$
|
34.49
|
|
|
—
|
|
|
—
|
|
(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
|
|
August 3, 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).
|
|
|
|
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).
|
|
|
|
10.1*
|
|
|
|
|
|
10.2*
|
|
|
|
|
|
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
|
**
|
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.
|
||||||||||||||||||||
Calculation of Ratio of Earnings to Fixed Charges
|
||||||||||||||||||||
|
|
Six Months Ended June 30,
|
|
Year Ended December 31,
|
||||||||||||||||
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
(millions)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
(Loss) Income From Continuing Operations Before Income Tax and Income From Equity Investees
|
|
$
|
(994
|
)
|
|
$
|
(2,309
|
)
|
|
$
|
1,540
|
|
|
$
|
1,138
|
|
|
$
|
1,170
|
|
Add (Deduct)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed Charges
|
|
222
|
|
|
435
|
|
|
349
|
|
|
296
|
|
|
288
|
|
|||||
Capitalized Interest
|
|
(52
|
)
|
|
(144
|
)
|
|
(116
|
)
|
|
(121
|
)
|
|
(151
|
)
|
|||||
Distributed Income From Equity Investees
|
|
33
|
|
|
77
|
|
|
382
|
|
|
204
|
|
|
204
|
|
|||||
Earnings as Defined
|
|
$
|
(791
|
)
|
|
$
|
(1,941
|
)
|
|
$
|
2,155
|
|
|
$
|
1,517
|
|
|
$
|
1,511
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net Interest Expense
|
|
157
|
|
|
263
|
|
|
210
|
|
|
158
|
|
|
125
|
|
|||||
Capitalized Interest
|
|
52
|
|
|
144
|
|
|
116
|
|
|
121
|
|
|
151
|
|
|||||
Interest Portion of Rental Expense
|
|
13
|
|
|
28
|
|
|
23
|
|
|
17
|
|
|
12
|
|
|||||
Fixed Charges as Defined
|
|
$
|
222
|
|
|
$
|
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
|
|
$
|
1,013
|
|
|
$
|
2,376
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
1.
|
I have reviewed this quarterly report on Form 10-Q of Noble Energy, Inc.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
Date:
|
August 3, 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:
|
August 3, 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:
|
August 3, 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:
|
August 3, 2016
|
|
/s/ Kenneth M. Fisher
|
|
|
|
Kenneth M. Fisher
|
|
|
|
Chief Financial Officer
|