Item 1. Financial Statements
Noble Energy, Inc.
Consolidated Statements of Operations and Comprehensive Income (Loss)
(millions, except per share amounts)
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
Revenues
|
|
|
|
|
|
|
|
|
Oil, NGL and Gas Sales
|
$
|
1,003
|
|
|
$
|
1,136
|
|
|
$
|
2,894
|
|
|
$
|
3,409
|
|
|
Sales of Purchased Oil and Gas
|
87
|
|
|
72
|
|
|
264
|
|
|
191
|
|
|
Other Revenue
|
29
|
|
|
65
|
|
|
106
|
|
|
189
|
|
|
Total
|
1,119
|
|
|
1,273
|
|
|
3,264
|
|
|
3,789
|
|
|
Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
Production Expense
|
297
|
|
|
273
|
|
|
862
|
|
|
886
|
|
|
Depreciation, Depletion and Amortization
|
583
|
|
|
485
|
|
|
1,619
|
|
|
1,418
|
|
|
General and Administrative
|
91
|
|
|
107
|
|
|
298
|
|
|
316
|
|
|
Cost of Purchased Oil and Gas
|
96
|
|
|
76
|
|
|
296
|
|
|
204
|
|
|
Other Operating Expense, Net
|
61
|
|
|
27
|
|
|
257
|
|
|
107
|
|
|
Gain on Divestitures, Net
|
—
|
|
|
(193
|
)
|
|
—
|
|
|
(859
|
)
|
|
Asset Impairments
|
—
|
|
|
—
|
|
|
—
|
|
|
168
|
|
|
Total
|
1,128
|
|
|
775
|
|
|
3,332
|
|
|
2,240
|
|
|
Operating (Loss) Income
|
(9
|
)
|
|
498
|
|
|
(68
|
)
|
|
1,549
|
|
|
Other (Income) Expense
|
|
|
|
|
|
|
|
|
|
|
(Gain) Loss on Commodity Derivative Instruments
|
(129
|
)
|
|
155
|
|
|
23
|
|
|
483
|
|
|
Interest, Net of Amount Capitalized
|
67
|
|
|
70
|
|
|
196
|
|
|
216
|
|
|
Other Non-Operating Expense (Income), Net
|
2
|
|
|
(34
|
)
|
|
7
|
|
|
(10
|
)
|
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Total
|
(60
|
)
|
|
191
|
|
|
226
|
|
|
689
|
|
|
Income (Loss) Before Income Taxes
|
51
|
|
|
307
|
|
|
(294
|
)
|
|
860
|
|
|
Income Tax Expense (Benefit)
|
15
|
|
|
59
|
|
|
(49
|
)
|
|
44
|
|
|
Net Income (Loss) and Comprehensive Income (Loss) Including Noncontrolling Interests
|
36
|
|
|
248
|
|
|
(245
|
)
|
|
816
|
|
|
Less: Net Income and Comprehensive Income Attributable to Noncontrolling Interests
|
19
|
|
|
21
|
|
|
61
|
|
|
58
|
|
|
Net Income (Loss) and Comprehensive Income (Loss) Attributable to Noble Energy
|
$
|
17
|
|
|
$
|
227
|
|
|
$
|
(306
|
)
|
|
$
|
758
|
|
|
|
|
|
|
|
|
|
|
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|
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Net Income (Loss) Attributable to Noble Energy Common Shareholders per Share
|
|
|
|
|
|
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Basic
|
$
|
0.04
|
|
|
$
|
0.47
|
|
|
$
|
(0.64
|
)
|
|
$
|
1.57
|
|
|
Diluted
|
$
|
0.04
|
|
|
$
|
0.47
|
|
|
$
|
(0.64
|
)
|
|
$
|
1.56
|
|
|
Weighted Average Number of Common Shares Outstanding
|
|
|
|
|
|
|
|
|
Basic
|
478
|
|
|
482
|
|
|
478
|
|
|
484
|
|
|
Diluted
|
480
|
|
|
484
|
|
|
478
|
|
|
486
|
|
The accompanying notes are an integral part of these consolidated financial statements.
Noble Energy, Inc.
Consolidated Balance Sheets
(millions)
(unaudited)
|
|
|
|
|
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|
|
|
|
|
|
|
September 30, 2019
|
|
December 31, 2018
|
|
ASSETS
|
|
|
|
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Current Assets
|
|
|
|
|
Cash and Cash Equivalents
|
$
|
473
|
|
|
$
|
716
|
|
|
Accounts Receivable, Net
|
677
|
|
|
616
|
|
|
Other Current Assets
|
277
|
|
|
418
|
|
|
Total Current Assets
|
1,427
|
|
|
1,750
|
|
|
Property, Plant and Equipment
|
|
|
|
|
|
|
Oil and Gas Properties (Successful Efforts Method of Accounting)
|
30,445
|
|
|
29,002
|
|
|
Property, Plant and Equipment, Other
|
1,045
|
|
|
891
|
|
|
Total Property, Plant and Equipment, Gross
|
31,490
|
|
|
29,893
|
|
|
Accumulated Depreciation, Depletion and Amortization
|
(12,693
|
)
|
|
(11,474
|
)
|
|
Total Property, Plant and Equipment, Net
|
18,797
|
|
|
18,419
|
|
|
Other Noncurrent Assets
|
1,780
|
|
|
841
|
|
|
Total Assets
|
$
|
22,004
|
|
|
$
|
21,010
|
|
|
LIABILITIES, MEZZANINE EQUITY AND SHAREHOLDERS' EQUITY
|
|
|
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|
Current Liabilities
|
|
|
|
|
|
Accounts Payable – Trade
|
$
|
1,395
|
|
|
$
|
1,207
|
|
|
Other Current Liabilities
|
1,190
|
|
|
519
|
|
|
Total Current Liabilities
|
2,585
|
|
|
1,726
|
|
|
Long-Term Debt
|
6,941
|
|
|
6,574
|
|
|
Deferred Income Taxes
|
954
|
|
|
1,061
|
|
|
Other Noncurrent Liabilities
|
1,338
|
|
|
1,165
|
|
|
Total Liabilities
|
11,818
|
|
|
10,526
|
|
|
Commitments and Contingencies
|
|
|
|
|
|
Mezzanine Equity
|
|
|
|
|
Redeemable Noncontrolling Interest, Net
|
103
|
|
|
—
|
|
|
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; 522 Million and 520 Million Shares Issued, respectively
|
5
|
|
|
5
|
|
|
Additional Paid in Capital
|
8,258
|
|
|
8,203
|
|
|
Accumulated Other Comprehensive Loss
|
(30
|
)
|
|
(32
|
)
|
|
Treasury Stock, at Cost; 39 Million Shares
|
(735
|
)
|
|
(730
|
)
|
|
Retained Earnings
|
1,506
|
|
|
1,980
|
|
|
Noble Energy Share of Equity
|
9,004
|
|
|
9,426
|
|
|
Noncontrolling Interests
|
1,079
|
|
|
1,058
|
|
|
Total Shareholders' Equity
|
10,083
|
|
|
10,484
|
|
|
Total Liabilities, Mezzanine Equity and Shareholders' Equity
|
$
|
22,004
|
|
|
$
|
21,010
|
|
The accompanying notes are an integral part of these consolidated financial statements.
Noble Energy, Inc.
Consolidated Statements of Cash Flows
(millions)
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
|
2019
|
|
2018
|
|
Cash Flows From Operating Activities
|
|
|
|
|
Net (Loss) Income Including Noncontrolling Interests
|
$
|
(245
|
)
|
|
$
|
816
|
|
|
Adjustments to Reconcile Net (Loss) Income to Net Cash Provided by Operating Activities
|
|
|
|
|
Depreciation, Depletion and Amortization
|
1,619
|
|
|
1,418
|
|
|
Deferred Income Tax Benefit
|
(110
|
)
|
|
(150
|
)
|
|
Loss on Commodity Derivative Instruments
|
23
|
|
|
483
|
|
|
Net Cash Received (Paid) in Settlement of Commodity Derivative Instruments
|
28
|
|
|
(160
|
)
|
|
Other Adjustments for Noncash Items Included in Income
|
115
|
|
|
45
|
|
|
Gain on Divestitures, Net
|
—
|
|
|
(859
|
)
|
|
Asset Impairments
|
—
|
|
|
168
|
|
|
Firm Transportation Exit Cost
|
92
|
|
|
—
|
|
|
Changes in Operating Assets and Liabilities
|
|
|
|
|
(Increase) Decrease in Accounts Receivable
|
(13
|
)
|
|
114
|
|
|
Increase (Decrease) in Accounts Payable
|
142
|
|
|
(91
|
)
|
|
Other Current Assets and Liabilities, Net
|
(76
|
)
|
|
73
|
|
|
Other Operating Assets and Liabilities, Net
|
(46
|
)
|
|
(81
|
)
|
|
Net Cash Provided by Operating Activities
|
1,529
|
|
|
1,776
|
|
|
Cash Flows From Investing Activities
|
|
|
|
|
Additions to Property, Plant and Equipment
|
(1,998
|
)
|
|
(2,589
|
)
|
|
Acquisitions, Net of Cash Received
|
—
|
|
|
(653
|
)
|
|
Additions to Equity Method Investments
|
(686
|
)
|
|
—
|
|
|
Proceeds from Divestitures, Net
|
131
|
|
|
1,740
|
|
|
Other
|
25
|
|
|
—
|
|
|
Net Cash Used in Investing Activities
|
(2,528
|
)
|
|
(1,502
|
)
|
|
Cash Flows From Financing Activities
|
|
|
|
|
Proceeds from Revolving Credit Facility
|
50
|
|
|
1,450
|
|
|
Repayment of Revolving Credit Facility
|
(50
|
)
|
|
(1,680
|
)
|
|
Proceeds from Noble Midstream Services Revolving Credit Facility
|
655
|
|
|
690
|
|
|
Repayment of Noble Midstream Services Revolving Credit Facility
|
(665
|
)
|
|
(725
|
)
|
|
Proceeds from Noble Midstream Services Term Loan Credit Facilities
|
400
|
|
|
500
|
|
|
Proceeds from Commercial Paper Borrowings, Net
|
511
|
|
|
—
|
|
|
Dividends Paid, Common Stock
|
(168
|
)
|
|
(156
|
)
|
|
Purchase and Retirement of Common Stock
|
—
|
|
|
(223
|
)
|
|
Contributions from Noncontrolling Interest Owners
|
27
|
|
|
348
|
|
|
Proceeds from Issuance of Mezzanine Equity, Net of Offering Costs
|
97
|
|
|
—
|
|
|
Repayment of Senior Notes
|
(9
|
)
|
|
(384
|
)
|
|
Other
|
(95
|
)
|
|
(86
|
)
|
|
Net Cash Provided by (Used in) Financing Activities
|
753
|
|
|
(266
|
)
|
|
(Decrease) Increase in Cash, Cash Equivalents, and Restricted Cash
|
(246
|
)
|
|
8
|
|
|
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period
|
719
|
|
|
713
|
|
|
Cash, Cash Equivalents, and Restricted Cash at End of Period
|
$
|
473
|
|
|
$
|
721
|
|
The accompanying notes are an integral part of these consolidated financial statements.
Noble Energy, Inc.
Consolidated Statements of Shareholders' Equity
(millions)
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2018
|
$
|
5
|
|
|
$
|
8,203
|
|
|
$
|
(32
|
)
|
|
$
|
(730
|
)
|
|
$
|
1,980
|
|
|
$
|
1,058
|
|
|
$
|
10,484
|
|
|
Net (Loss) Income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(313
|
)
|
|
24
|
|
|
(289
|
)
|
|
Stock-based Compensation
|
—
|
|
|
14
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
14
|
|
|
Dividends (11 cents per share)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(53
|
)
|
|
—
|
|
|
(53
|
)
|
|
Distributions to Noncontrolling Interest Owners
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(17
|
)
|
|
(17
|
)
|
|
Contributions from Noncontrolling Interest Owners
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10
|
|
|
10
|
|
|
Other
|
—
|
|
|
2
|
|
|
—
|
|
|
(5
|
)
|
|
—
|
|
|
(3
|
)
|
|
(6
|
)
|
|
March 31, 2019
|
$
|
5
|
|
|
$
|
8,219
|
|
|
$
|
(32
|
)
|
|
$
|
(735
|
)
|
|
$
|
1,614
|
|
|
$
|
1,072
|
|
|
$
|
10,143
|
|
|
Net (Loss) Income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(10
|
)
|
|
18
|
|
|
8
|
|
|
Stock-based Compensation
|
—
|
|
|
21
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
21
|
|
|
Dividends (12 cents per share)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(58
|
)
|
|
—
|
|
|
(58
|
)
|
|
Distributions to Noncontrolling Interest Owners
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(19
|
)
|
|
(19
|
)
|
|
Contributions from Noncontrolling Interest Owners
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11
|
|
|
11
|
|
|
Other
|
—
|
|
|
4
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
(7
|
)
|
|
(2
|
)
|
|
June 30, 2019
|
5
|
|
|
8,244
|
|
|
(31
|
)
|
|
(735
|
)
|
|
1,546
|
|
|
1,075
|
|
|
10,104
|
|
|
Net Income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
17
|
|
|
19
|
|
|
36
|
|
|
Stock-based Compensation
|
—
|
|
|
16
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
16
|
|
|
Dividends (12 cents per share)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(57
|
)
|
|
—
|
|
|
(57
|
)
|
|
Distributions to Noncontrolling Interest Owners
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(19
|
)
|
|
(19
|
)
|
|
Contributions from Noncontrolling Interest Owners
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6
|
|
|
6
|
|
|
Other
|
—
|
|
|
(2
|
)
|
|
1
|
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
(3
|
)
|
|
September 30, 2019
|
$
|
5
|
|
|
$
|
8,258
|
|
|
$
|
(30
|
)
|
|
$
|
(735
|
)
|
|
$
|
1,506
|
|
|
$
|
1,079
|
|
|
$
|
10,083
|
|
The accompanying notes are an integral part of these consolidated financial statements.
Noble Energy, Inc.
Consolidated Statements of Shareholders' Equity
(millions)
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Attributable to Noble Energy
|
|
|
|
|
|
|
Common Stock
|
|
Additional Paid in Capital
|
|
Accumulated Other Comprehensive Loss
|
|
Treasury Stock at Cost
|
|
Retained Earnings
|
|
Non-controlling Interests
|
|
Total Equity
|
|
December 31, 2017
|
$
|
5
|
|
|
$
|
8,438
|
|
|
$
|
(30
|
)
|
|
$
|
(725
|
)
|
|
$
|
2,248
|
|
|
$
|
683
|
|
|
$
|
10,619
|
|
|
Net Income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
554
|
|
|
20
|
|
|
574
|
|
|
Stock-based Compensation
|
—
|
|
|
17
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
17
|
|
|
Dividends (10 cents per share)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(48
|
)
|
|
—
|
|
|
(48
|
)
|
|
Purchase and Retirement of Common Stock
|
—
|
|
|
(67
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(67
|
)
|
|
Clayton Williams Energy Acquisition
|
—
|
|
|
(25
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(25
|
)
|
|
Distributions to Noncontrolling Interest Owners
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(11
|
)
|
|
(11
|
)
|
|
Contributions from Noncontrolling Interest Owners
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
331
|
|
|
331
|
|
|
Other
|
—
|
|
|
—
|
|
|
1
|
|
|
(6
|
)
|
|
—
|
|
|
2
|
|
|
(3
|
)
|
|
March 31, 2018
|
$
|
5
|
|
|
$
|
8,363
|
|
|
$
|
(29
|
)
|
|
$
|
(731
|
)
|
|
$
|
2,754
|
|
|
$
|
1,025
|
|
|
$
|
11,387
|
|
|
Net (Loss) Income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(23
|
)
|
|
17
|
|
|
(6
|
)
|
|
Stock-based Compensation
|
—
|
|
|
29
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
29
|
|
|
Dividends (11 cents per share)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(54
|
)
|
|
—
|
|
|
(54
|
)
|
|
Purchase and Retirement of Common Stock
|
—
|
|
|
(63
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(63
|
)
|
|
Distributions to Noncontrolling Interest Owners
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(11
|
)
|
|
(11
|
)
|
|
Contributions from Noncontrolling Interest Owners
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Other
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
(1
|
)
|
|
June 30, 2018
|
$
|
5
|
|
|
$
|
8,329
|
|
|
$
|
(28
|
)
|
|
$
|
(731
|
)
|
|
$
|
2,677
|
|
|
$
|
1,029
|
|
|
$
|
11,281
|
|
|
Net Income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
227
|
|
|
21
|
|
|
248
|
|
|
Stock-based Compensation
|
—
|
|
|
17
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
17
|
|
|
Dividends (11 cents per share)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(54
|
)
|
|
—
|
|
|
(54
|
)
|
|
Purchase and Retirement of Common Stock
|
—
|
|
|
(103
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(103
|
)
|
|
Distributions to Noncontrolling Interest Owners
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(13
|
)
|
|
(13
|
)
|
|
Contributions from Noncontrolling Interest Owners
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
17
|
|
|
17
|
|
|
Other
|
—
|
|
|
6
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
(6
|
)
|
|
1
|
|
|
September 30, 2018
|
$
|
5
|
|
|
$
|
8,249
|
|
|
$
|
(27
|
)
|
|
$
|
(731
|
)
|
|
$
|
2,850
|
|
|
$
|
1,048
|
|
|
$
|
11,394
|
|
The accompanying notes are an integral part of these consolidated financial statements.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
Note 1. Organization and Nature of Operations
Noble Energy, Inc. (Noble Energy, we or us) is a leading independent energy company engaged in worldwide crude oil and natural gas exploration and production. Our historical operating areas include: US onshore, primarily the Denver-Julesburg (DJ) Basin, Delaware Basin and Eagle Ford Shale; US offshore Gulf of Mexico (until April 2018); Eastern Mediterranean; and West Africa. Our Midstream segment develops, owns and operates domestic midstream infrastructure assets, as well as invests in other midstream projects, with current focus areas being the DJ and Delaware Basins.
Note 2. Basis of Presentation
Presentation The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the US (US GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and notes required by US GAAP for complete financial statements. The accompanying consolidated financial statements at September 30, 2019 and December 31, 2018 and for the three and nine months ended September 30, 2019 and 2018 contain all normally recurring adjustments considered necessary for a fair presentation of our financial position, results of operations, cash flows and equity for such periods. Certain prior-period amounts have been reclassified to conform to the current period presentation. For the periods presented, net income or loss is materially consistent with comprehensive income or loss.
Operating results for the three and nine months ended September 30, 2019 are not necessarily indicative of the results that may be expected for the year ending December 31, 2019.
These consolidated financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in our Annual Report on Form 10-K for the year ended December 31, 2018.
Consolidation Our consolidated financial statements include our accounts, the accounts of subsidiaries which Noble Energy wholly owns, and the accounts of Noble Midstream Partners LP (Noble Midstream Partners), which is considered a variable interest entity (VIE) for which Noble Energy is the primary beneficiary. In addition, we use the equity method of accounting for investments in entities that we do not control, but over which we exert significant influence. All significant intercompany balances and transactions have been eliminated upon consolidation.
Estimates The preparation of consolidated financial statements in conformity with US GAAP requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ significantly from those estimates. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment.
Leases We determine whether an arrangement contains a lease based on the conveyed rights and obligations at the inception date. If an agreement contains an operating or financing lease, at the commencement date, we record a right-of-use (ROU) asset and a corresponding lease liability based on the present value of the minimum lease payments.
As most of our leases do not provide an implicit borrowing rate, to determine the present value of lease payments, we use our hypothetical secured borrowing rate based on information available at lease commencement. Further, we make certain estimates and judgments regarding the lease term and lease payments, noted below.
Lease Term Leases with an initial term of 12 months or less are not recorded on the balance sheet and we recognize lease expense for these leases on a straight-line basis over the lease term. Most leases include one or more options to renew, with renewal terms that can extend the lease term from one month to one year or more. Additionally, some of our leases include an option for early termination. We include renewal periods and exclude termination periods from our lease term if, at commencement, it is reasonably likely that we will exercise the option.
Lease Payments Certain of our lease agreements include rental payments that are adjusted periodically for inflation or passage of time. These step payments are included within our present value calculation as they are known adjustments at commencement. Some of our lease agreements include variable payments that are excluded from our present value calculation. For example, drilling rig ROU assets and lease liabilities are recorded using the contractual standby rate, which is the fixed, minimum monthly payment, as opposed to the operating rate, which varies depending on the asset's use.
Additionally, we have lease agreements that include lease and non-lease components, such as equipment maintenance, which are generally accounted for as a single lease component. For these leases, lease payments include all fixed payments stated within the contract. For other leases, such as office space, lease and non-lease components are accounted for separately. Our lease agreements do not contain any material residual value guarantees that would impact our lease payments.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
Revenue Recognition We recognize revenue at an amount that reflects the consideration we expect to be entitled to in exchange for transferring goods or services to a customer, using a five-step process, in accordance with ASC 606 – Revenue from Contracts with Customers (ASC 606).
Under ASC 606, remaining performance obligations represent the transaction price of firm sales arrangements for which volumes have not been delivered. In Israel, certain of our Tamar natural gas contracts have fixed annual sales volumes and fixed base pricing with annual index escalations. The following table includes estimated revenues, as of September 30, 2019, for those agreements. Our actual future sales volumes may exceed future minimum volume commitments.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(millions)
|
Remainder of 2019
|
|
2020
|
|
Total
|
|
Natural Gas Revenues (1)
|
$
|
36
|
|
|
$
|
199
|
|
|
$
|
235
|
|
|
|
|
|
(1)
|
The remaining performance obligations are estimated using the contractual base or floor price provision in effect. Future revenues under these contracts will vary from the amounts above due to components of variable consideration exceeding the contractual base or floor price provision.
|
Redeemable Noncontrolling Interest In March 2019, Noble Midstream Partners secured a $200 million equity commitment (preferred equity) from GIP CAPS Dos Rios Holding Partnership, L.P. (GIP) to fund capital contributions in connection with Noble Midstream Partners’ 30% equity investment in EPIC Crude Holdings, LP (EPIC Crude Holdings). GIP funded $100 million of the commitment, with associated offering costs of $3 million, and the remaining $100 million is available for a one year period, subject to certain conditions precedent. The preferred equity is perpetual and has a 6.5% annual dividend rate, payable quarterly in cash, with the ability to defer payment during the first two years following the closing. Noble Midstream Partners can redeem the preferred equity in whole or in part at any time for cash at a predetermined redemption price. GIP can request redemption of the preferred equity following the later of the sixth anniversary of the preferred equity closing or the fifth anniversary of the EPIC crude oil pipeline completion date at a pre-determined base return.
As GIP’s redemption right is outside of Noble Midstream Partners’ control, the preferred equity is not considered to be a component of equity on the consolidated balance sheet and, therefore, is reported as mezzanine equity. In addition, because the preferred equity was issued by a subsidiary of Noble Midstream Partners and is held by a third party, it is considered a redeemable noncontrolling interest. Subsequent to issuance, we accrete changes in the redemption value of the preferred equity from the date of issuance to the earliest redemption date of the preferred equity. The accretion is offset against additional paid in capital. See Note 4. Acquisitions and Divestitures and Note 13. Fair Value Measurements and Disclosures.
Recently Issued Accounting Standards
Financial Instruments: Credit Losses In June 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2016-13 (ASU 2016-13): Financial Instruments – Credit Losses, which replaces the incurred loss impairment methodology with a methodology that reflects current expected credit losses. The standard applies to a broad scope of financial instruments, including financial assets measured at amortized cost and off-balance sheet credit exposures not accounted for as insurance, such as financial guarantees and other unfunded loan commitments. ASU 2016-13 is effective for fiscal years beginning after December 15, 2019, with early adoption permitted.
We are executing an implementation plan, which includes data collection, contract review and assessment, and determination of necessary systems, processes and internal controls. Although we continue to evaluate ASU 2016-03, based on our current credit portfolio, we do not believe adoption of the standard will have a material impact on our financial statements.
Recently Adopted Accounting Standards
Leases In February 2016, the FASB issued Accounting Standards Update No. 2016-02 (ASU 2016-02), which created Topic 842 – Leases (ASC 842). The standard requires lessees to recognize a ROU asset and lease liability on the balance sheet for the rights and obligations created by leases. ASC 842 also requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. This standard does not apply to leases to explore for or use minerals, oil, natural gas or similar nonregenerative resources, including the intangible right to explore for those resources and rights to use the land in which those natural resources are contained.
The new standard provided a number of optional practical expedients. We elected:
|
|
|
|
•
|
the package of transition “practical expedients”, permitting us not to reassess our prior conclusions about lease identification, lease classification and initial direct costs;
|
|
|
|
|
•
|
the practical expedient pertaining to land easements, allowing us to account for existing land easements under previous accounting policy; and
|
|
|
|
|
•
|
the practical expedient to not separate lease and non-lease components for the majority of our leases (elected by asset class).
|
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
We adopted ASC 842 on January 1, 2019 using the modified retrospective method and recorded ROU assets and lease liabilities of $282 million and $287 million, respectively, primarily related to operating leases. The $5 million difference between these amounts was recorded as other operating expense. Our accounting for finance leases remains substantially unchanged. Adoption did not materially impact our consolidated statement of operations and comprehensive income and had no impact on our consolidated statement of cash flows. See Note 8. Leases.
Derivatives and Hedging – Targeted Improvements to Accounting for Hedging Activities In August 2017, the FASB issued Accounting Standards Update No. 2017-12 (ASU 2017-12): Derivatives and Hedging – Targeted Improvements to Accounting for Hedging Activities. The update is intended to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements and makes certain targeted improvements to simplify application of hedge accounting guidance in US GAAP. Adoption of this ASU on January 1, 2019 did not have an impact on our financial statements.
Intangibles—Goodwill and Other—Internal-Use Software In August 2018, the FASB issued Accounting Standards Update No. 2018-15 (ASU 2018-15): Intangibles—Goodwill and Other—Internal-Use Software to align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The amended standard is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. We used the prospective method to early adopt this ASU in second quarter 2019, which did not have a material impact on our financial statements.
Statements of Operations Information Other statements of operations information is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
(millions)
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
Other Revenue
|
|
|
|
|
|
|
|
|
|
|
Income from Equity Method Investments and Other
|
$
|
10
|
|
|
$
|
44
|
|
|
$
|
43
|
|
|
$
|
140
|
|
|
Midstream Services Revenues – Third Party
|
19
|
|
|
21
|
|
|
63
|
|
|
49
|
|
|
Total
|
$
|
29
|
|
|
$
|
65
|
|
|
$
|
106
|
|
|
$
|
189
|
|
|
Production Expense
|
|
|
|
|
|
|
|
|
|
|
Lease Operating Expense
|
$
|
132
|
|
|
$
|
124
|
|
|
$
|
405
|
|
|
$
|
411
|
|
|
Production and Ad Valorem Taxes
|
52
|
|
|
47
|
|
|
142
|
|
|
151
|
|
|
Gathering, Transportation and Processing Expense
|
108
|
|
|
97
|
|
|
306
|
|
|
292
|
|
|
Other Royalty Expense
|
5
|
|
|
5
|
|
|
9
|
|
|
32
|
|
|
Total
|
$
|
297
|
|
|
$
|
273
|
|
|
$
|
862
|
|
|
$
|
886
|
|
|
Other Operating Expense, Net
|
|
|
|
|
|
|
|
|
Exploration Expense
|
$
|
25
|
|
|
$
|
25
|
|
|
$
|
82
|
|
|
$
|
89
|
|
|
Marketing Expense
|
7
|
|
|
11
|
|
|
26
|
|
|
21
|
|
|
Firm Transportation Exit Cost
|
—
|
|
|
—
|
|
|
92
|
|
|
—
|
|
|
Other, Net
|
29
|
|
|
(9
|
)
|
|
57
|
|
|
(3
|
)
|
|
Total
|
$
|
61
|
|
|
$
|
27
|
|
|
$
|
257
|
|
|
$
|
107
|
|
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
Balance Sheet Information Other balance sheet information is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
(millions)
|
September 30,
2019
|
|
December 31,
2018
|
|
Accounts Receivable, Net
|
|
|
|
|
Commodity Sales
|
$
|
405
|
|
|
$
|
383
|
|
|
Joint Interest Billings
|
177
|
|
|
137
|
|
|
Other
|
103
|
|
|
111
|
|
|
Allowance for Doubtful Accounts
|
(8
|
)
|
|
(15
|
)
|
|
Total
|
$
|
677
|
|
|
$
|
616
|
|
|
Other Current Assets
|
|
|
|
|
|
|
Commodity Derivative Assets
|
$
|
90
|
|
|
$
|
180
|
|
|
Inventories, Materials and Supplies
|
74
|
|
|
55
|
|
|
Assets Held for Sale (1)
|
—
|
|
|
133
|
|
|
Prepaid Expenses and Other Current Assets
|
113
|
|
|
50
|
|
|
Total
|
$
|
277
|
|
|
$
|
418
|
|
|
Other Noncurrent Assets
|
|
|
|
|
|
|
Equity Method Investments (2)
|
$
|
959
|
|
|
$
|
286
|
|
|
Operating Lease Right-of-Use Assets (3)
|
275
|
|
|
—
|
|
|
Customer-Related Intangible Assets, Net (4)
|
286
|
|
|
310
|
|
|
Goodwill (4)
|
110
|
|
|
110
|
|
|
Other Assets, Noncurrent
|
150
|
|
|
135
|
|
|
Total
|
$
|
1,780
|
|
|
$
|
841
|
|
|
Other Current Liabilities
|
|
|
|
|
|
|
Production and Ad Valorem Taxes
|
$
|
147
|
|
|
$
|
103
|
|
|
Asset Retirement Obligations
|
89
|
|
|
118
|
|
|
Interest Payable
|
87
|
|
|
66
|
|
|
Operating Lease Liabilities (3)
|
97
|
|
|
—
|
|
|
Commercial Paper Borrowings
|
511
|
|
|
—
|
|
|
Other Liabilities, Current
|
259
|
|
|
232
|
|
|
Total
|
$
|
1,190
|
|
|
$
|
519
|
|
|
Other Noncurrent Liabilities
|
|
|
|
|
|
|
Deferred Compensation Liabilities
|
$
|
148
|
|
|
$
|
147
|
|
|
Asset Retirement Obligations
|
699
|
|
|
762
|
|
|
Operating Lease Liabilities (3)
|
209
|
|
|
—
|
|
|
Firm Transportation Exit Cost Accrual (5)
|
133
|
|
|
67
|
|
|
Other Liabilities, Noncurrent
|
149
|
|
|
189
|
|
|
Total
|
$
|
1,338
|
|
|
$
|
1,165
|
|
|
|
|
|
(1)
|
Assets held for sale at December 31, 2018 related to the first quarter 2019 divestiture of non-core acreage in Reeves County, Texas. See Note 4. Acquisitions and Divestitures.
|
|
|
|
|
(2)
|
See Note 4. Acquisitions and Divestitures.
|
|
|
|
|
(3)
|
Amounts relate to assets and liabilities recorded as a result of ASC 842 adoption in first quarter 2019. See Note 8. Leases.
|
|
|
|
|
(4)
|
Amounts relate to assets acquired in the first quarter 2018 Saddle Butte acquisition. Intangible asset balances at September 30, 2019 and December 31, 2018 are net of accumulated amortization of $54 million and $30 million, respectively. See Note 4. Acquisitions and Divestitures.
|
|
|
|
|
(5)
|
See Note 9. Exit Cost – Transportation Commitments.
|
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
Reconciliation of Total Cash We define total cash as cash, cash equivalents and restricted cash. The following table provides a reconciliation of total cash:
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
(millions)
|
2019
|
|
2018
|
|
Cash and Cash Equivalents at Beginning of Period
|
$
|
716
|
|
|
$
|
675
|
|
|
Restricted Cash at Beginning of Period
|
3
|
|
|
38
|
|
|
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period
|
$
|
719
|
|
|
$
|
713
|
|
|
Cash and Cash Equivalents at End of Period
|
$
|
473
|
|
|
$
|
720
|
|
|
Restricted Cash at End of Period
|
—
|
|
|
1
|
|
|
Cash, Cash Equivalents, and Restricted Cash at End of Period
|
$
|
473
|
|
|
$
|
721
|
|
Note 3. Segment Information
We have the following reportable segments: United States (US onshore and Gulf of Mexico (until April 2018)); Eastern Mediterranean (Israel and Cyprus); West Africa (Equatorial Guinea, Cameroon and Gabon); Other International (Canada, New Ventures and Colombia); and Midstream. The Midstream segment includes the consolidated accounts of Noble Midstream Partners and other US onshore midstream assets.
The geographical reportable segments are in the business of crude oil and natural gas acquisition and exploration, development, and production (Oil and Gas Exploration and Production). The Midstream reportable segment develops, owns, and operates domestic midstream infrastructure assets, as well as invests in other midstream projects. The chief operating decision maker analyzes income before income taxes to assess the performance of Noble Energy's reportable segments as management believes this measure provides useful information in assessing our operating and financial performance across periods.
Expenses related to debt, such as interest and other debt-related costs, headquarters depreciation, corporate general and administrative expenses, exit costs and certain costs associated with mitigating the effects of our retained Marcellus Shale transportation agreements, are recorded at the Corporate level.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Exploration and Production
|
|
Midstream
|
|
|
|
(millions)
|
Consolidated
|
|
United States
|
|
Eastern Mediter-ranean
|
|
West Africa
|
|
Other Int'l
|
|
United States
|
|
Intersegment Eliminations and Other(1)
|
|
Corporate
|
|
Three Months Ended September 30, 2019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Sales
|
$
|
724
|
|
|
$
|
645
|
|
|
$
|
1
|
|
|
$
|
78
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
NGL Sales
|
78
|
|
|
78
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Natural Gas Sales
|
201
|
|
|
79
|
|
|
118
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total Crude Oil, NGL and Natural Gas Sales
|
1,003
|
|
|
802
|
|
|
119
|
|
|
82
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Sales of Purchased Oil and Gas
|
87
|
|
|
22
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
47
|
|
|
—
|
|
|
18
|
|
|
Income (Loss) from Equity Method Investments and Other
|
10
|
|
|
1
|
|
|
—
|
|
|
14
|
|
|
—
|
|
|
(5
|
)
|
|
—
|
|
|
—
|
|
|
Midstream Services Revenues – Third Party
|
19
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
19
|
|
|
—
|
|
|
—
|
|
|
Intersegment Revenues
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
125
|
|
|
(125
|
)
|
|
—
|
|
|
Total Revenues
|
1,119
|
|
|
825
|
|
|
119
|
|
|
96
|
|
|
—
|
|
|
186
|
|
|
(125
|
)
|
|
18
|
|
|
Lease Operating Expense
|
132
|
|
|
111
|
|
|
7
|
|
|
22
|
|
|
—
|
|
|
1
|
|
|
(9
|
)
|
|
—
|
|
|
Production and Ad Valorem Taxes
|
52
|
|
|
51
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
Gathering, Transportation and Processing Expense
|
108
|
|
|
173
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|
(71
|
)
|
|
—
|
|
|
Other Royalty Expense
|
5
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total Production Expense
|
297
|
|
|
340
|
|
|
8
|
|
|
22
|
|
|
—
|
|
|
7
|
|
|
(80
|
)
|
|
—
|
|
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Exploration and Production
|
|
Midstream
|
|
|
|
(millions)
|
Consolidated
|
|
United States
|
|
Eastern Mediter-ranean
|
|
West Africa
|
|
Other Int'l
|
|
United States
|
|
Intersegment Eliminations and Other(1)
|
|
Corporate
|
|
Depreciation, Depletion and Amortization
|
583
|
|
|
505
|
|
|
17
|
|
|
21
|
|
|
1
|
|
|
26
|
|
|
(8
|
)
|
|
21
|
|
|
Cost of Purchased Oil and Gas
|
96
|
|
|
17
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
46
|
|
|
—
|
|
|
33
|
|
|
Gain on Commodity Derivative Instruments
|
(129
|
)
|
|
(123
|
)
|
|
—
|
|
|
(6
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Income (Loss) Before Income Taxes
|
51
|
|
|
92
|
|
|
74
|
|
|
56
|
|
|
(17
|
)
|
|
83
|
|
|
(23
|
)
|
|
(214
|
)
|
|
Additions to Long-Lived Assets, Excluding Acquisitions
|
595
|
|
|
377
|
|
|
129
|
|
|
46
|
|
|
2
|
|
|
56
|
|
|
(26
|
)
|
|
11
|
|
|
Additions to Equity Method Investments
|
271
|
|
|
—
|
|
|
185
|
|
|
—
|
|
|
—
|
|
|
86
|
|
|
—
|
|
|
—
|
|
|
Three Months Ended September 30, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Sales
|
$
|
744
|
|
|
$
|
655
|
|
|
$
|
2
|
|
|
$
|
87
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
NGL Sales
|
166
|
|
|
166
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Natural Gas Sales
|
226
|
|
|
98
|
|
|
122
|
|
|
6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total Crude Oil, NGL and Natural Gas Sales
|
1,136
|
|
|
919
|
|
|
124
|
|
|
93
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Sales of Purchased Oil and Gas
|
72
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
46
|
|
|
—
|
|
|
26
|
|
|
Income from Equity Method Investments and Other
|
44
|
|
|
—
|
|
|
—
|
|
|
34
|
|
|
—
|
|
|
10
|
|
|
—
|
|
|
—
|
|
|
Midstream Services Revenues – Third Party
|
21
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
21
|
|
|
—
|
|
|
—
|
|
|
Intersegment Revenues
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
91
|
|
|
(91
|
)
|
|
—
|
|
|
Total Revenues
|
1,273
|
|
|
919
|
|
|
124
|
|
|
127
|
|
|
—
|
|
|
168
|
|
|
(91
|
)
|
|
26
|
|
|
Lease Operating Expense
|
124
|
|
|
114
|
|
|
7
|
|
|
15
|
|
|
—
|
|
|
—
|
|
|
(12
|
)
|
|
—
|
|
|
Production and Ad Valorem Taxes
|
47
|
|
|
46
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
Gathering, Transportation and Processing Expense
|
97
|
|
|
129
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
28
|
|
|
(60
|
)
|
|
—
|
|
|
Other Royalty Expense
|
5
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total Production Expense
|
273
|
|
|
294
|
|
|
7
|
|
|
15
|
|
|
—
|
|
|
29
|
|
|
(72
|
)
|
|
—
|
|
|
Depreciation, Depletion and Amortization
|
485
|
|
|
414
|
|
|
16
|
|
|
25
|
|
|
1
|
|
|
24
|
|
|
(5
|
)
|
|
10
|
|
|
(Gain) Loss on Divestitures, Net
|
(193
|
)
|
|
5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(198
|
)
|
|
—
|
|
|
—
|
|
|
Cost of Purchased Oil and Gas
|
76
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
44
|
|
|
—
|
|
|
32
|
|
|
Loss on Commodity Derivative Instruments
|
155
|
|
|
140
|
|
|
—
|
|
|
15
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Income (Loss) Before Income Taxes
|
307
|
|
|
31
|
|
|
143
|
|
|
68
|
|
|
(17
|
)
|
|
268
|
|
|
(16
|
)
|
|
(170
|
)
|
|
Additions to Long-Lived Assets, Excluding Acquisitions
|
768
|
|
|
535
|
|
|
170
|
|
|
4
|
|
|
1
|
|
|
82
|
|
|
(22
|
)
|
|
(2
|
)
|
|
Nine Months Ended September 30, 2019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Sales
|
$
|
2,024
|
|
|
$
|
1,807
|
|
|
$
|
4
|
|
|
$
|
213
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
NGL Sales
|
258
|
|
|
258
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Natural Gas Sales
|
612
|
|
|
259
|
|
|
340
|
|
|
13
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total Crude Oil, NGL and Natural Gas Sales
|
2,894
|
|
|
2,324
|
|
|
344
|
|
|
226
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Exploration and Production
|
|
Midstream
|
|
|
|
(millions)
|
Consolidated
|
|
United States
|
|
Eastern Mediter-ranean
|
|
West Africa
|
|
Other Int'l
|
|
United States
|
|
Intersegment Eliminations and Other(1)
|
|
Corporate
|
|
Sales of Purchased Oil and Gas
|
264
|
|
|
64
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
132
|
|
|
—
|
|
|
68
|
|
|
Income (Loss) from Equity Method Investments and Other
|
43
|
|
|
2
|
|
|
—
|
|
|
46
|
|
|
—
|
|
|
(5
|
)
|
|
—
|
|
|
—
|
|
|
Midstream Services Revenues – Third Party
|
63
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
63
|
|
|
—
|
|
|
—
|
|
|
Intersegment Revenues
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
322
|
|
|
(322
|
)
|
|
—
|
|
|
Total Revenues
|
3,264
|
|
|
2,390
|
|
|
344
|
|
|
272
|
|
|
—
|
|
|
512
|
|
|
(322
|
)
|
|
68
|
|
|
Lease Operating Expense
|
405
|
|
|
350
|
|
|
26
|
|
|
56
|
|
|
—
|
|
|
3
|
|
|
(30
|
)
|
|
—
|
|
|
Production and Ad Valorem Taxes
|
142
|
|
|
138
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
Gathering, Transportation and Processing Expense
|
306
|
|
|
439
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
65
|
|
|
(199
|
)
|
|
—
|
|
|
Other Royalty Expense
|
9
|
|
|
9
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total Production Expense
|
862
|
|
|
936
|
|
|
27
|
|
|
56
|
|
|
—
|
|
|
72
|
|
|
(229
|
)
|
|
—
|
|
|
Depreciation, Depletion and Amortization
|
1,619
|
|
|
1,401
|
|
|
50
|
|
|
60
|
|
|
1
|
|
|
77
|
|
|
(21
|
)
|
|
51
|
|
|
Cost of Purchased Oil and Gas
|
296
|
|
|
59
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
125
|
|
|
—
|
|
|
112
|
|
|
Firm Transportation Exit Cost
|
92
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
92
|
|
|
Loss on Commodity Derivative Instruments
|
23
|
|
|
7
|
|
|
—
|
|
|
16
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(Loss) Income Before Income Taxes
|
(294
|
)
|
|
(85
|
)
|
|
223
|
|
|
126
|
|
|
(48
|
)
|
|
202
|
|
|
(52
|
)
|
|
(660
|
)
|
|
Additions to Long-Lived Assets, Excluding Acquisitions
|
1,954
|
|
|
1,367
|
|
|
380
|
|
|
64
|
|
|
14
|
|
|
174
|
|
|
(74
|
)
|
|
29
|
|
|
Additions to Equity Method Investments
|
686
|
|
|
—
|
|
|
185
|
|
|
—
|
|
|
—
|
|
|
501
|
|
|
—
|
|
|
—
|
|
|
Nine Months Ended September 30, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Sales
|
$
|
2,266
|
|
|
$
|
1,972
|
|
|
$
|
6
|
|
|
$
|
288
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
NGL Sales
|
449
|
|
|
449
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Natural Gas Sales
|
694
|
|
|
316
|
|
|
362
|
|
|
16
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total Crude Oil, NGL and Natural Gas Sales
|
3,409
|
|
|
2,737
|
|
|
368
|
|
|
304
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Sales of Purchased Oil and Gas
|
191
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
110
|
|
|
—
|
|
|
81
|
|
|
Income from Equity Method Investments and Other
|
140
|
|
|
—
|
|
|
—
|
|
|
105
|
|
|
—
|
|
|
35
|
|
|
—
|
|
|
—
|
|
|
Midstream Services Revenues – Third Party
|
49
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
49
|
|
|
—
|
|
|
—
|
|
|
Intersegment Revenues
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
257
|
|
|
(257
|
)
|
|
—
|
|
|
Total Revenues
|
3,789
|
|
|
2,737
|
|
|
368
|
|
|
409
|
|
|
—
|
|
|
451
|
|
|
(257
|
)
|
|
81
|
|
|
Lease Operating Expense
|
411
|
|
|
354
|
|
|
19
|
|
|
56
|
|
|
—
|
|
|
—
|
|
|
(18
|
)
|
|
—
|
|
|
Production and Ad Valorem Taxes
|
151
|
|
|
147
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
Gathering, Transportation and Processing Expense
|
292
|
|
|
389
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
71
|
|
|
(168
|
)
|
|
—
|
|
|
Other Royalty Expense
|
32
|
|
|
32
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total Production Expense
|
886
|
|
|
922
|
|
|
19
|
|
|
56
|
|
|
—
|
|
|
75
|
|
|
(186
|
)
|
|
—
|
|
|
Depreciation, Depletion and Amortization
|
1,418
|
|
|
1,214
|
|
|
44
|
|
|
77
|
|
|
1
|
|
|
62
|
|
|
(13
|
)
|
|
33
|
|
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Exploration and Production
|
|
Midstream
|
|
|
|
(millions)
|
Consolidated
|
|
United States
|
|
Eastern Mediter-ranean
|
|
West Africa
|
|
Other Int'l
|
|
United States
|
|
Intersegment Eliminations and Other(1)
|
|
Corporate
|
|
(Gain) Loss on Divestitures, Net
|
(859
|
)
|
|
20
|
|
|
(376
|
)
|
|
—
|
|
|
—
|
|
|
(503
|
)
|
|
—
|
|
|
—
|
|
|
Asset Impairments
|
168
|
|
|
168
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Cost of Purchased Oil and Gas
|
204
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
106
|
|
|
—
|
|
|
98
|
|
|
Loss on Commodity Derivative Instruments
|
483
|
|
|
400
|
|
|
—
|
|
|
83
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Income (Loss) Before Income Taxes
|
860
|
|
|
(94
|
)
|
|
678
|
|
|
180
|
|
|
(44
|
)
|
|
690
|
|
|
(52
|
)
|
|
(498
|
)
|
|
Additions to Long-Lived Assets, Excluding Acquisitions
|
2,608
|
|
|
1,630
|
|
|
533
|
|
|
9
|
|
|
3
|
|
|
479
|
|
|
(72
|
)
|
|
26
|
|
|
September 30, 2019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, Plant and Equipment, Net
|
$
|
18,797
|
|
|
$
|
13,170
|
|
|
$
|
3,001
|
|
|
$
|
801
|
|
|
$
|
39
|
|
|
$
|
1,682
|
|
|
$
|
(198
|
)
|
|
$
|
302
|
|
|
December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, Plant and Equipment, Net
|
$
|
18,419
|
|
|
$
|
13,044
|
|
|
$
|
2,630
|
|
|
$
|
805
|
|
|
$
|
37
|
|
|
$
|
1,742
|
|
|
$
|
(145
|
)
|
|
$
|
306
|
|
|
|
|
|
(1)
|
The intersegment eliminations related to income (loss) before income taxes are the result of midstream expenditures. These costs are presented as property, plant and equipment within the E&P business on an unconsolidated basis, in accordance with the successful efforts method of accounting, and are eliminated upon consolidation.
|
Note 4. Acquisitions and Divestitures
We maintain an ongoing portfolio management program and have engaged in various transactions over recent years.
2019 Asset Transactions
Eastern Mediterranean Investment During third quarter 2019, we invested $185 million for a 25% equity interest in Eastern Mediterranean Pipeline B.V. (EMED Pipeline B.V.) in support of its planned acquisition of an approximate 39% equity interest in East Mediterranean Gas Company S.A.E. (EMG), which owns the EMG Pipeline. Upon closing of EMED Pipeline B.V.'s planned equity acquisition of EMG, which is anticipated in fourth quarter 2019, we will own an effective, indirect interest of approximately 10%, net, in EMG. The EMG Pipeline is expected to provide future connection from the Israel pipeline network to Egyptian customers and support delivery of natural gas from our producing fields offshore Israel into Egypt.
Divestiture of Reeves County Assets In February 2019, we closed the sale of certain proved and unproved non-core acreage in the Delaware Basin totaling approximately 13,000 net acres in Reeves County, Texas. We received cash consideration of approximately $131 million, recognizing no gain or loss on the sale.
EPIC Pipeline Investments In first quarter 2019, Noble Midstream Partners exercised and closed options with EPIC Midstream Holdings, LP (EPIC) to acquire a 15% equity interest in EPIC Y-Grade, LP (EPIC Y-Grade), which is constructing the EPIC Y-Grade pipeline, and a 30% equity interest in EPIC Crude Holdings, which is constructing the EPIC crude oil pipeline. Both pipelines will transport production from the Delaware Basin to Corpus Christi, Texas. Cash consideration totaled $227 million and Noble Midstream Partners has since made additional capital contributions of $46 million and $168 million to EPIC Y-Grade and EPIC Crude Holdings, respectively, to fund its share of pipeline construction costs. These investments are accounted for using the equity method.
Delaware Crossing Joint Venture In February 2019, Noble Midstream Partners executed definitive agreements with Salt Creek Midstream LLC to form a 50/50 joint venture, Delaware Crossing LLC (Delaware Crossing), to construct a 160 MBbl/d day crude oil pipeline system in the Delaware Basin. For the first nine months of 2019, Noble Midstream Partners has made capital contributions of $53 million for construction of the pipeline. This investment is accounted for using the equity method.
2018 Asset Transactions
Divestiture of Gulf of Mexico Assets In February 2018, we announced plans to sell our Gulf of Mexico assets for cash consideration of $480 million, along with the assumption, by the purchaser, of all abandonment obligations associated with the properties. As of March 31, 2018, we reduced the net book value of the Gulf of Mexico assets to $480 million. In addition, we retained certain transaction related obligations approximating $92 million which were subsequently settled upon closing.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
During first quarter 2018, we recorded impairment expense of $168 million associated with these assets held for sale. The transaction closed in second quarter 2018. We received net proceeds of $383 million and recorded a loss of $24 million.
Divestiture of 7.5% Interest in Tamar Field In March 2018, we closed the sale of a 7.5% working interest in the Tamar field to Tamar Petroleum Ltd., a publicly traded entity on the Tel Aviv Stock Exchange (Tamar Petroleum, TASE: TMRP). Total consideration included cash of $484 million and 38.5 million shares of Tamar Petroleum that had a publicly traded value of $224 million. Total consideration received from the sale was applied to the field's basis and resulted in the recognition of a pre-tax gain of $376 million and tax expense of $86 million.
In October 2018, we sold our shares in Tamar Petroleum for pre-tax proceeds of $163 million, net of transaction expenses. The sale was in accordance with the Israel Natural Gas Framework and completed our obligation to reduce ownership interest in the Tamar field from 32.5% to 25% by year end-2021.
Divestiture of Southwest Royalties In January 2018, we closed the sale of our investment in Southwest Royalties, Inc. We received proceeds of $60 million, recognizing no gain or loss on the sale.
Divestiture of Marcellus Shale CONE Gathering In January 2018, we closed the sale of our 50% interest in CONE Gathering LLC (CONE Gathering) to CNX Resources Corporation. CONE Gathering owns the general partner of CNX Midstream Partners LP (CNX Midstream Partners, NYSE: CNXM). We received proceeds of $308 million in cash and recognized a pre-tax gain of $196 million.
After the sale, we held 21.7 million common units, representing a 34.1% limited partner interest in CNX Midstream Partners. During second quarter 2018, we sold 7.5 million common units, receiving net proceeds of $135 million, net of underwriting fees, and recognized a gain of $109 million. During third quarter 2018, we sold the remaining 14.2 million common units, representing a 22.3% limited partner interest, in CNX Midstream Partners, receiving proceeds net of underwriting fees of approximately $248 million, and recognized a gain of $198 million.
Divestiture of Greeley Crescent Assets In September 2018, we closed the sale of assets in the Greeley Crescent area of the DJ Basin, receiving proceeds of $64 million, resulting in no gain or loss on the sale.
Noble Midstream Partners Saddle Butte Acquisition In January 2018, Noble Midstream Partners acquired a 54.4% interest in Black Diamond Gathering LLC (Black Diamond), an entity formed by Black Diamond Gathering Holdings LLC, a wholly-owned subsidiary of Noble Midstream Partners, and Greenfield Midstream, LLC (Greenfield), which completed the acquisition of Saddle Butte Rockies Midstream, LLC and affiliates (collectively, Saddle Butte) from Saddle Butte Pipeline II, LLC. Saddle Butte owns a large-scale integrated gathering system, located in the DJ Basin, which we subsequently renamed the Black Diamond gathering system. Consideration totaled $681 million and Black Diamond is consolidated as a VIE.
We accounted for the transaction as a business combination using the acquisition method. The total purchase price was allocated to assets acquired and liabilities assumed based on acquisition date fair values, and we recognized goodwill for the amount of the purchase price exceeding the fair values of the identifiable net assets acquired. The final purchase price allocation included: $206 million to property, plant and equipment; $340 million to customer-related intangible assets (acquired customer contracts); and $110 million to implied goodwill.
Note 5. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs
Capitalized Exploratory Well Costs There were no significant changes to our capitalized exploratory well costs during the period. The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced:
|
|
|
|
|
|
|
|
|
|
|
|
(millions, except number of projects)
|
September 30,
2019
|
|
December 31,
2018
|
|
Exploratory Well Costs Capitalized for a Period of One Year or Less
|
$
|
15
|
|
|
$
|
6
|
|
|
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling
|
354
|
|
|
348
|
|
|
Capitalized Exploratory Well Costs, End of Period
|
$
|
369
|
|
|
$
|
354
|
|
|
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling
|
7
|
|
|
7
|
|
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
Undeveloped Leasehold Costs Changes in undeveloped leasehold costs are as follows:
|
|
|
|
|
|
|
|
(millions)
|
Nine Months Ended September 30, 2019
|
|
Undeveloped Leasehold Costs, Beginning of Period
|
$
|
2,306
|
|
|
Additions to Undeveloped Leasehold Costs
|
63
|
|
|
Transfers to Proved Properties
|
(20
|
)
|
|
Undeveloped Leasehold Costs, End of Period
|
$
|
2,349
|
|
As of September 30, 2019, undeveloped leasehold costs included $2.1 billion, $100 million, $76 million, and $59 million attributable to the Delaware Basin, Eagle Ford Shale, other US onshore properties, and international properties, respectively. Certain of these costs pertain to acquired leases or licenses that are subject to expiration over the next several years unless production is established on the acreage. Other costs pertain to acreage that is being held by production.
Note 6. Asset Retirement Obligations
Asset retirement obligations (ARO) consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. Changes in ARO are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
(millions)
|
2019
|
|
2018
|
|
Asset Retirement Obligations, Beginning Balance
|
$
|
880
|
|
|
$
|
875
|
|
|
Liabilities Incurred
|
17
|
|
|
16
|
|
|
Liabilities Settled
|
(82
|
)
|
|
(309
|
)
|
|
Revisions of Estimates
|
(60
|
)
|
|
67
|
|
|
Accretion Expense
|
33
|
|
|
25
|
|
|
Asset Retirement Obligations, Ending Balance
|
$
|
788
|
|
|
$
|
674
|
|
Nine Months Ended September 30, 2019 Liabilities settled relate primarily to abandonment of US onshore properties, principally in the DJ Basin where we have engaged in a program to plug and abandon older vertical wells. Costs associated with these abandonment activities will be incurred over several years. Revisions of estimates relate primarily to a decrease of $73 million in the DJ Basin as a result of improved cycle times and cost reductions for vertical wells, partially offset by acceleration of timing estimates of $13 million for wells offshore Israel.
Nine Months Ended September 30, 2018 Liabilities settled include $216 million and $24 million of liabilities assumed by the purchasers of the Gulf of Mexico properties and Greeley Crescent assets, respectively, and $69 million related to abandonment of US onshore properties, primarily in the DJ Basin. Revisions of estimates relate primarily to increases in cost and timing of estimates of $84 million for US onshore, primarily in the DJ Basin, partially offset by decreases in cost and timing estimates of $11 million associated with the North Sea abandonment project and $6 million for Eastern Mediterranean.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
Note 7. Debt
Debt consists of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2019
|
|
December 31, 2018
|
|
(millions, except percentages)
|
Debt
|
|
Interest Rate
|
|
|
Debt
|
|
Interest Rate
|
|
Noble Energy, Excluding Noble Midstream Partners
|
|
|
|
|
|
|
|
|
Revolving Credit Facility, due March 9, 2023
|
$
|
—
|
|
|
—
|
%
|
|
$
|
—
|
|
|
—
|
%
|
|
Commercial Paper Borrowings
|
511
|
|
|
(1
|
)
|
|
—
|
|
|
—
|
%
|
|
Senior Notes and Debentures
|
5,884
|
|
|
(2
|
)
|
|
5,892
|
|
|
(2
|
)
|
|
Finance Lease Obligations
|
206
|
|
|
—
|
%
|
|
223
|
|
|
—
|
%
|
|
Total Noble Energy Debt, Excluding Noble Midstream Partners Debt
|
6,601
|
|
|
|
|
6,115
|
|
|
|
|
Noble Midstream Partners
|
|
|
|
|
|
|
|
|
Noble Midstream Services Revolving Credit Facility, due March 9, 2023 (3)
|
50
|
|
|
3.45
|
%
|
|
60
|
|
|
3.67
|
%
|
|
Noble Midstream Services Term Loan Credit Facility, due July 31, 2021
|
500
|
|
|
3.17
|
%
|
|
500
|
|
|
3.42
|
%
|
|
Noble Midstream Services Term Loan Credit Facility, due August 23, 2022
|
400
|
|
|
3.05
|
%
|
|
—
|
|
|
—
|
%
|
|
Total Noble Midstream Partners Debt
|
950
|
|
|
|
|
560
|
|
|
|
|
Total Debt
|
7,551
|
|
|
|
|
6,675
|
|
|
|
|
Net Unamortized Discounts and Debt Issuance Costs
|
(57
|
)
|
|
|
|
(60
|
)
|
|
|
|
Total Debt, Net of Unamortized Discounts and Debt Issuance Costs
|
7,494
|
|
|
|
|
6,615
|
|
|
|
|
Less Amounts Due Within One Year
|
|
|
|
|
|
|
|
|
Commercial Paper Borrowings
|
(511
|
)
|
|
|
|
—
|
|
|
|
|
Finance Lease Obligations
|
(42
|
)
|
|
|
|
(41
|
)
|
|
|
|
Long-Term Debt Due After One Year
|
$
|
6,941
|
|
|
|
|
$
|
6,574
|
|
|
|
|
|
|
|
(1)
|
As of September 30, 2019, the weighted average interest rate for outstanding commercial paper was 2.63%.
|
|
|
|
|
(2)
|
As of September 30, 2019 and December 31, 2018, the senior notes and debentures had weighted average interest rates of 5.00% and 5.01%, respectively.
|
|
|
|
|
(3)
|
As of September 30, 2019 and December 31, 2018, the Noble Midstream Services Revolving Credit Facility had $800 million of capacity, of which $750 million and $740 million were available for borrowing, respectively.
|
Commercial Paper Program In first quarter 2019, we established a commercial paper program to provide for short-term funding needs. The program allows for a maximum of $4.0 billion of unsecured commercial paper notes and is supported by Noble Energy’s $4.0 billion Revolving Credit Facility. Our commercial paper notes, which generally have a maturity of less than 30 days, are sold under customary terms in the commercial paper market and are either issued at a discounted price relative to the principal face value or bear interest at varying interest rates on a fixed or floating basis. Such discount prices or interest rates are dependent on market conditions and ratings assigned to the commercial paper program by credit agencies at the time of commercial paper issuance. At September 30, 2019, outstanding commercial paper borrowings totaled $511 million, leaving approximately $3.5 billion available for borrowing under our $4.0 billion Revolving Credit Facility.
Noble Midstream Services 2019 Term Loan Credit Facility On August 23, 2019, Noble Midstream Services LLC (Noble Midstream Services), a subsidiary of Noble Midstream Partners, entered into a term loan agreement, which provides for a three-year senior unsecured term loan credit facility, due August 23, 2022 (2019 Term Loan Credit Facility), that permits aggregate borrowings of up to $400 million. Proceeds from the term loan were primarily used to repay a portion of the outstanding borrowings under the Noble Midstream Services Revolving Credit Facility.
Subsequent Event On October 1, 2019, we issued $500 million of 3.25% notes due October 15, 2029 and $500 million of 4.20% notes due October 15, 2049. Interest on the notes is payable semi-annually beginning April 15, 2020. We may redeem some or all of the notes at any time at the applicable redemption price, plus accrued interest, if any. Proceeds from the issuance of the notes were used to fund the tender offer and redemption of our $1.0 billion 4.15% notes due December 15, 2021. In connection with the tender and redemption, in fourth quarter 2019, we will record early debt extinguishment fees of approximately $44 million in our consolidated statements of operations.
Fair Value of Debt See Note 13. Fair Value Measurements and Disclosures.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
Note 8. Leases
In the normal course of business, we enter into operating and finance lease agreements to support our operations. Operating leases primarily include office space for our corporate and field locations, US onshore compressors and drilling rigs, vessels and helicopters for offshore operations, storage facilities, and other miscellaneous assets. Finance leases include corporate office space, a trunkline in the DJ Basin, a floating production, storage and offloading vessel (FPSO) in West Africa, and vehicles. Our leasing activity is recorded and presented on a gross basis, with the exception of the FPSO which is recorded net to our interest.
Balance Sheet Information ROU assets and lease liabilities are as follows:
|
|
|
|
|
|
|
|
|
(millions)
|
Balance Sheet Location
|
September 30, 2019
|
|
ROU Assets
|
|
|
|
Operating Leases (1)
|
Other Noncurrent Assets
|
$
|
275
|
|
|
Finance Leases (2)
|
Total Property, Plant and Equipment, Net
|
172
|
|
|
Total ROU Assets
|
|
$
|
447
|
|
|
Lease Liabilities
|
|
|
|
Current Liabilities
|
|
|
|
Operating Leases
|
Other Current Liabilities
|
$
|
97
|
|
|
Finance Leases
|
Other Current Liabilities
|
42
|
|
|
Noncurrent Liabilities
|
|
|
|
Operating Leases
|
Other Noncurrent Liabilities
|
209
|
|
|
Finance Leases
|
Long-Term Debt
|
164
|
|
|
Total Lease Liabilities
|
|
$
|
512
|
|
|
|
|
|
(1)
|
Operating lease ROU assets primarily include office space of $117 million, compressors of $93 million, and drilling rigs of $29 million.
|
|
|
|
|
(2)
|
Finance lease ROU assets primarily include office space of $92 million and a trunkline of $32 million, both net of accumulated amortization.
|
Statement of Operations Information The components of lease cost are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
(millions)
|
Statement of Operations Location
|
Three Months Ended September 30, 2019
|
|
Nine Months Ended September 30, 2019
|
|
Operating Lease Cost
|
(1)
|
$
|
30
|
|
|
$
|
81
|
|
|
Finance Lease Cost
|
|
|
|
|
|
Amortization Expense
|
Depreciation, Depletion and Amortization
|
10
|
|
|
27
|
|
|
Interest Expense
|
Interest, Net of Amount Capitalized
|
3
|
|
|
10
|
|
|
Short-term Lease Cost (2)
|
(1)
|
88
|
|
|
357
|
|
|
Sublease Income
|
General and Administrative
|
(1
|
)
|
|
(3
|
)
|
|
Total Lease Cost
|
|
$
|
130
|
|
|
$
|
472
|
|
|
|
|
|
(1)
|
Cost classifications vary depending on the leased asset. Costs are primarily included within production expense and general and administrative expense. In addition, in accordance with the successful efforts method of accounting, certain lease costs may be capitalized when incurred and, therefore, are included as part of oil and gas properties on our consolidated balance sheets.
|
|
|
|
|
(2)
|
Short-term lease costs relate primarily to hydraulic fracturing services, well-to-well drilling rig contracts and other miscellaneous lease agreements. Amount excludes costs for leases with an initial term of one month or less.
|
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
Cash Flow Information Supplemental cash flow information is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2019
|
|
(millions)
|
Operating Leases
|
|
Finance Leases
|
|
Cash Paid for Amounts Included in the Measurement of Lease Liabilities
|
|
|
|
|
Operating Cash Flows
|
$
|
50
|
|
|
$
|
9
|
|
|
Investing Cash Flows
|
27
|
|
|
—
|
|
|
Financing Cash Flows
|
—
|
|
|
31
|
|
|
Non-Cash Activities
|
|
|
|
|
ROU Assets Obtained in Exchange for Lease Liabilities (1)
|
93
|
|
|
15
|
|
|
|
|
|
(1)
|
Amounts exclude the impact of adopting ASC 842 on January 1, 2019. See Note 2. Basis of Presentation.
|
Maturity of Lease Liabilities Maturities of lease liabilities as of September 30, 2019 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(millions)
|
Operating Leases
|
|
Finance Leases
|
|
Total
|
|
Remainder of 2019
|
$
|
28
|
|
|
$
|
13
|
|
|
$
|
41
|
|
|
2020
|
100
|
|
|
49
|
|
|
149
|
|
|
2021
|
61
|
|
|
35
|
|
|
96
|
|
|
2022
|
44
|
|
|
25
|
|
|
69
|
|
|
2023
|
29
|
|
|
22
|
|
|
51
|
|
|
2024 and Thereafter
|
85
|
|
|
106
|
|
|
191
|
|
|
Total Lease Liabilities, Undiscounted
|
347
|
|
|
250
|
|
|
597
|
|
|
Less: Imputed Interest
|
41
|
|
|
44
|
|
|
85
|
|
|
Total Lease Liabilities (1)
|
$
|
306
|
|
|
$
|
206
|
|
|
$
|
512
|
|
|
|
|
|
(1)
|
Includes the current portions of $97 million and $42 million for operating and finance leases, respectively.
|
Lease commitments as of December 31, 2018 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(millions)
|
Operating Leases
|
|
Finance Leases
|
|
Total
|
|
2019
|
$
|
91
|
|
|
$
|
52
|
|
|
$
|
143
|
|
|
2020
|
74
|
|
|
46
|
|
|
120
|
|
|
2021
|
59
|
|
|
31
|
|
|
90
|
|
|
2022
|
62
|
|
|
22
|
|
|
84
|
|
|
2023
|
50
|
|
|
20
|
|
|
70
|
|
|
2024 and Thereafter
|
176
|
|
|
104
|
|
|
280
|
|
|
Total Lease Liabilities, Undiscounted
|
$
|
512
|
|
|
$
|
275
|
|
|
$
|
787
|
|
Other Information Other information related to our leases as of September 30, 2019 is as follows:
|
|
|
|
|
|
|
|
|
|
|
Operating Leases
|
|
Finance Leases
|
|
Weighted-Average Remaining Lease Term
|
5.7 years
|
|
|
7.7 years
|
|
|
Weighted-Average Discount Rate
|
4.40
|
%
|
|
5.02
|
%
|
Note 9. Exit Cost – Transportation Commitments
In connection with the divestiture of Marcellus Shale upstream assets in 2017, we retained certain long-term financial commitments to pay transportation fees on certain pipelines in the Marcellus Basin. As of September 30, 2019, our undiscounted financial commitment for the remaining obligations under these agreements was approximately $1.0 billion, which excludes the impact of future mitigation activities. Our efforts to mitigate and thereby reduce these obligations primarily include permanent assignment of capacity, negotiation of capacity releases and utilization of capacity through purchase and
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
transport of third-party natural gas. Revenues and expenses associated with mitigation activities are recorded in sales of purchased oil and gas and cost of purchased oil and gas, respectively, in our consolidated statements of operations.
Leach Xpress and Rayne Xpress Permanent Assignment In January 2019, we executed agreements on the Leach Xpress and Rayne Xpress pipelines to permanently assign remaining capacity to a third-party effective January 1, 2021, extending through the end of the contract. The permanent assignment reduced our total financial commitment by approximately $350 million, undiscounted. As a result of the assignment, we recorded firm transportation exit cost of $92 million, discounted, related to future commitments to the third party. We will continue efforts to mitigate the remaining component of these transportation agreements through 2020.
Exit Costs Reconciliation of accrued costs at September 30, 2019 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
(millions)
|
2019
|
|
2018
|
|
Balance at Beginning of Period (1)
|
$
|
80
|
|
|
$
|
90
|
|
|
Firm Transportation Exit Cost Accrual
|
92
|
|
|
—
|
|
|
Payments, Net of Accretion
|
(6
|
)
|
|
(9
|
)
|
|
Balance at End of Period
|
166
|
|
|
81
|
|
|
Less: Current Portion Included in Other Current Liabilities
|
33
|
|
|
12
|
|
|
Long-term Portion Included in Other Noncurrent Liabilities
|
$
|
133
|
|
|
$
|
69
|
|
|
|
|
|
(1)
|
Amounts include the current portion of $13 million which is included in other current liabilities in our consolidated balance sheets.
|
Note 10. Commitments and Contingencies
Legal Proceedings We are involved in various legal proceedings in the ordinary course of business. These proceedings are subject to the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters, and we believe that the ultimate disposition of such proceedings will not have a material adverse effect on our financial position, results of operations or cash flows.
Colorado Clean Water Act Referral Notice In September 2018, we received a letter from the Department of Justice (DOJ) requesting an opportunity to discuss settlement of alleged Clean Water Act violations at an upstream production facility and a midstream gathering facility in Weld County, Colorado. In April 2019, we met with the DOJ and Environmental Protection Agency enforcement personnel to discuss potential settlement of the alleged violations. Given the ongoing status of settlement discussions, we are currently unable to predict the ultimate outcome of this action, but believe the resolution will not have a material adverse effect on our financial position, results of operations or cash flows.
Note 11. Income Taxes
Income tax expense (benefit) consists of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
(millions, except percentages)
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
Current
|
$
|
24
|
|
|
$
|
45
|
|
|
$
|
61
|
|
|
$
|
194
|
|
|
Deferred
|
(9
|
)
|
|
14
|
|
|
(110
|
)
|
|
(150
|
)
|
|
Total Income Tax Expense (Benefit)
|
$
|
15
|
|
|
$
|
59
|
|
|
$
|
(49
|
)
|
|
$
|
44
|
|
|
Effective Tax Rate
|
29.4
|
%
|
|
19.2
|
%
|
|
16.7
|
%
|
|
5.1
|
%
|
Effective Tax Rate (ETR) At the end of each interim period, we apply a forecasted annualized ETR to current period earnings or loss before tax, which can produce interim ETR fluctuations. The ETR for the nine months ended September 30, 2019 varied as compared with 2018, primarily due to a $145 million discrete tax benefit recorded in 2018 as a result of the intent of the US Department of the Treasury and Internal Revenue Service to issue additional regulatory guidance associated with the Tax Cuts and Jobs Act and the transition tax. In addition, current tax expense for the nine months ended September 30, 2018 includes foreign taxes related to a gain on the 2018 divestiture of a 7.5% interest in the Tamar field.
In our major tax jurisdictions, the earliest years remaining open to examination are as follows: US – 2014, Israel – 2015 (2013 with respect to Israel Oil Profits Tax) and Equatorial Guinea – 2013.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
Note 12. Derivative Instruments and Hedging Activities
Objective and Strategies for Using Derivative Instruments We enter into crude oil and natural gas price hedging arrangements to mitigate effects of commodity price volatility and enhance the predictability of cash flows for a portion of our crude oil and natural gas production. While these instruments mitigate the cash flow risk of future decreases in commodity prices, they may also curtail benefits from future increases in commodity prices.
Unsettled Commodity Derivative Instruments As of September 30, 2019, the following crude oil derivative contracts were outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swaps
|
|
Collars
|
|
Settlement Period
|
Type of Contract
|
Index
|
Bbls Per Day
|
Weighted Average Differential
|
Weighted Average Fixed Price
|
|
Weighted Average Short Put Price
|
Weighted Average Floor Price
|
Weighted Average Ceiling Price
|
|
2019
|
Swaps
|
NYMEX WTI
|
35,000
|
$
|
—
|
|
$
|
59.04
|
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
|
2019
|
Three-Way Collars
|
NYMEX WTI
|
33,000
|
—
|
|
—
|
|
|
49.35
|
|
59.35
|
|
72.25
|
|
|
2019
|
Sold Calls (1)
|
NYMEX WTI
|
4,000
|
—
|
|
60.00
|
|
|
—
|
|
—
|
|
—
|
|
|
2019
|
Swaps
|
ICE Brent
|
5,000
|
—
|
|
57.00
|
|
|
—
|
|
—
|
|
—
|
|
|
2019
|
Three-Way Collars
|
ICE Brent
|
3,000
|
—
|
|
—
|
|
|
43.00
|
|
50.00
|
|
64.07
|
|
|
2019
|
Basis Swaps
|
(2)
|
27,000
|
(3.23
|
)
|
—
|
|
|
—
|
|
—
|
|
—
|
|
|
2020
|
Swaption
|
NYMEX WTI
|
12,000
|
—
|
|
59.73
|
|
|
—
|
|
—
|
|
—
|
|
|
2020
|
Sold Calls (1)
|
NYMEX WTI
|
8,000
|
—
|
|
65.59
|
|
|
—
|
|
—
|
|
—
|
|
|
2020
|
Swaps
|
NYMEX WTI
|
28,000
|
—
|
|
58.09
|
|
|
—
|
|
—
|
|
—
|
|
|
2020
|
Three-Way Collars
|
NYMEX WTI
|
30,000
|
—
|
|
—
|
|
|
48.33
|
|
57.87
|
|
64.27
|
|
|
2020
|
Basis Swaps
|
(2)
|
15,000
|
(5.01
|
)
|
—
|
|
|
—
|
|
—
|
|
—
|
|
|
|
|
|
(1)
|
We entered into crude oil contracts receiving premiums for establishing a maximum price that would be settled for the notional volumes covered by the respective contracts.
|
|
|
|
|
(2)
|
We entered into crude oil basis swap contracts to establish a fixed amount for the differential between pricing in Midland, Texas, and Cushing, Oklahoma. The weighted average differential represents the amount of reduction to Cushing, Oklahoma prices for the notional volumes covered by the basis swap contracts.
|
As of September 30, 2019, the following natural gas derivative contracts were outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swaps
|
|
Collars
|
|
Settlement Period
|
Type of Contract
|
Index
|
MMBtu Per Day
|
Weighted Average Differential
|
Weighted Average Fixed Price
|
|
Weighted Average Short Put Price
|
Weighted Average Floor Price
|
Weighted Average Ceiling Price
|
|
2019
|
Three-Way Collars
|
NYMEX HH
|
104,000
|
|
$
|
—
|
|
$
|
—
|
|
|
$
|
2.25
|
|
$
|
2.65
|
|
$
|
2.95
|
|
|
2019
|
Swaps
|
NYMEX HH
|
46,000
|
|
—
|
|
3.00
|
|
|
—
|
|
—
|
|
—
|
|
|
2019
|
Basis Swaps
|
CIG (1)
|
123,500
|
|
(0.64
|
)
|
—
|
|
|
—
|
|
—
|
|
—
|
|
|
2019
|
Basis Swaps
|
WAHA (1)
|
47,500
|
|
(1.28
|
)
|
—
|
|
|
—
|
|
—
|
|
—
|
|
|
2020
|
Swaps
|
NYMEX HH
|
90,000
|
|
—
|
|
2.60
|
|
|
—
|
|
—
|
|
—
|
|
|
2020
|
Sold Puts (2)
|
NYMEX HH
|
90,000
|
|
—
|
|
—
|
|
|
2.15
|
|
—
|
|
—
|
|
|
2020
|
Swaption
|
NYMEX HH
|
90,000
|
|
—
|
|
2.60
|
|
|
—
|
|
—
|
|
—
|
|
|
2020
|
Basis Swaps
|
CIG (1)
|
54,000
|
|
(0.61
|
)
|
—
|
|
|
—
|
|
—
|
|
—
|
|
|
2020
|
Basis Swaps
|
WAHA (1)
|
49,500
|
|
(1.05
|
)
|
—
|
|
|
—
|
|
—
|
|
—
|
|
|
2021
|
Basis Swaps
|
WAHA (1)
|
14,000
|
|
(0.60
|
)
|
—
|
|
|
—
|
|
—
|
|
—
|
|
|
|
|
|
(1)
|
We entered into natural gas basis swap contracts to establish a fixed amount for the differential between the noted index pricing and NYMEX Henry Hub. The weighted average differential represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes covered by the basis swap contracts.
|
|
|
|
|
(2)
|
We entered into natural gas contracts receiving premiums for establishing a minimum price that would be settled for the notional volumes covered by the respective contracts.
|
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
Fair Value Amounts The fair values of commodity derivative instruments in our consolidated balance sheets were as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Derivative Instruments
|
|
Liability Derivative Instruments
|
|
Balance Sheet Location
|
September 30, 2019
|
|
December 31, 2018
|
|
Balance Sheet Location
|
September 30, 2019
|
|
December 31, 2018
|
|
Other Current Assets
|
$
|
90
|
|
|
$
|
180
|
|
|
Other Current Liabilities
|
$
|
10
|
|
|
$
|
1
|
|
|
Other Noncurrent Assets
|
25
|
|
|
—
|
|
|
Other Noncurrent Liabilities
|
3
|
|
|
26
|
|
|
Total
|
$
|
115
|
|
|
$
|
180
|
|
|
|
$
|
13
|
|
|
$
|
27
|
|
See Note 13. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of our derivative instruments.
Gains and Losses on Commodity Derivative Instruments The effect of commodity derivative instruments on our consolidated statements of operations and comprehensive income (loss) was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
(millions)
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
Cash (Received) Paid in Settlement of Commodity Derivative Instruments
|
|
|
|
|
|
|
|
|
Crude Oil
|
$
|
(6
|
)
|
|
$
|
68
|
|
|
$
|
(8
|
)
|
|
$
|
164
|
|
|
Natural Gas
|
(7
|
)
|
|
(1
|
)
|
|
(20
|
)
|
|
(4
|
)
|
|
Total Cash (Received) Paid in Settlement of Commodity Derivative Instruments
|
(13
|
)
|
|
67
|
|
|
(28
|
)
|
|
160
|
|
|
Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments
|
|
|
|
|
|
|
|
|
Crude Oil
|
(115
|
)
|
|
85
|
|
|
54
|
|
|
316
|
|
|
Natural Gas
|
(1
|
)
|
|
3
|
|
|
(3
|
)
|
|
7
|
|
|
Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments
|
(116
|
)
|
|
88
|
|
|
51
|
|
|
323
|
|
|
(Gain) Loss on Commodity Derivative Instruments
|
|
|
|
|
|
|
|
|
Crude Oil
|
(121
|
)
|
|
153
|
|
|
46
|
|
|
480
|
|
|
Natural Gas
|
(8
|
)
|
|
2
|
|
|
(23
|
)
|
|
3
|
|
|
Total (Gain) Loss on Commodity Derivative Instruments
|
$
|
(129
|
)
|
|
$
|
155
|
|
|
$
|
23
|
|
|
$
|
483
|
|
Note 13. Fair Value Measurements and Disclosures
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Cash and Cash Equivalents, Accounts Receivable and Accounts Payable The carrying amounts approximate fair value due to the short-term nature or maturity of the instruments.
Mutual Fund Investments Our mutual fund investments consist of various publicly-traded mutual funds that include investments ranging from equities to money market instruments. Fair values are based on quoted market prices for identical assets.
Commodity Derivative Instruments We estimate the fair values of our derivative instruments using published forward commodity price curves as of the date of the estimate. The discount rate used in the cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates. In addition, for collars, we estimate the values of put options sold and contract floors and ceilings using an option pricing model which considers market volatility, market prices and contract terms. See Note 12. Derivative Instruments and Hedging Activities.
Deferred Compensation Liability Fair value is dependent upon the fair values of mutual fund investments and shares of our common stock held in a rabbi trust. See Mutual Fund Investments, above.
Stock-Based Compensation Liability A portion of the value of the liability associated with our phantom unit plan is dependent upon the fair value of Noble Energy common stock at the end of each reporting period.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
Measurement information for assets and liabilities measured at fair value on a recurring basis is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using
|
|
|
|
|
|
(millions)
|
Quoted Prices in Active Markets
(Level 1)
|
|
Significant Other Observable Inputs
(Level 2)
|
|
Significant Unobservable Inputs
(Level 3)
|
|
Adjustment (1)
|
|
Fair Value Measurement
|
|
September 30, 2019
|
|
|
|
|
|
|
|
|
|
|
Financial Assets:
|
|
|
|
|
|
|
|
|
|
|
Mutual Fund Investments
|
$
|
42
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
42
|
|
|
Commodity Derivative Instruments
|
—
|
|
|
155
|
|
|
—
|
|
|
(40
|
)
|
|
115
|
|
|
Financial Liabilities:
|
|
|
|
|
|
|
|
|
|
|
Commodity Derivative Instruments
|
—
|
|
|
(53
|
)
|
|
—
|
|
|
40
|
|
|
(13
|
)
|
|
Portion of Deferred Compensation Liability Measured at Fair Value
|
(48
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(48
|
)
|
|
Stock Based Compensation Liability Measured at Fair Value
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3
|
)
|
|
December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
Financial Assets:
|
|
|
|
|
|
|
|
|
|
|
Mutual Fund Investments
|
$
|
38
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
38
|
|
|
Commodity Derivative Instruments
|
—
|
|
|
187
|
|
|
—
|
|
|
(7
|
)
|
|
180
|
|
|
Financial Liabilities:
|
|
|
|
|
|
|
|
|
|
|
Commodity Derivative Instruments
|
—
|
|
|
(34
|
)
|
|
—
|
|
|
7
|
|
|
(27
|
)
|
|
Portion of Deferred Compensation Liability Measured at Fair Value
|
(43
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(43
|
)
|
|
Stock Based Compensation Liability Measured at Fair Value
|
(8
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(8
|
)
|
|
|
|
|
(1)
|
Amount represents the impact of netting provisions within our master agreements allowing us to net cash settle asset and liability positions with the same counterparty.
|
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Firm Transportation Exit Cost Accrual In January 2019, we recorded a firm transportation exit cost liability at fair value of $92 million, representing the discounted present value of our remaining obligation under a permanent pipeline capacity assignment in the Marcellus Shale. See Note 9. Exit Cost – Transportation Commitments.
Redeemable Noncontrolling Interest In March 2019, we recorded redeemable noncontrolling interest associated with the issuance to GIP of preferred equity in Noble Midstream Partners at fair value of $97 million, including issuance date proceeds of $100 million netted with associated issuance costs of $3 million. See Note 2. Basis of Presentation.
Additional Fair Value Disclosures
Debt The fair value of fixed-rate, public debt is estimated based on published market prices. As such, we consider the fair value of this debt to be a Level 1 measurement on the fair value hierarchy.
Our non-public debt, including our Revolving Credit Facility, commercial paper borrowings, Noble Midstream Services Revolving Credit Facility and Noble Midstream Services term loans are subject to variable interest rates. The fair value is estimated based on significant other observable inputs; thus, we consider the fair values to be Level 2 measurements on the fair value hierarchy. See Note 7. Debt.
Fair value information regarding our debt is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2019
|
|
December 31, 2018
|
|
(millions)
|
Carrying Amount
|
|
Fair Value (1)
|
|
Carrying Amount
|
|
Fair Value
|
|
Debt (2)
|
$
|
7,345
|
|
|
$
|
7,963
|
|
|
$
|
6,452
|
|
|
$
|
6,121
|
|
|
|
|
|
(1)
|
As of September 30, 2019, the difference between the carrying amount and the fair value is primarily due to low US treasury rates.
|
|
|
|
|
(2)
|
Represents total debt excluding finance lease obligations. See Note 7. Debt.
|
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
Note 14. Net Income (Loss) Per Share Attributable to Noble Energy Common Shareholders
Noble Energy's basic income (loss) per share of common stock is computed by dividing net income (loss) attributable to Noble Energy by the weighted average number of shares of Noble Energy common stock outstanding during each period. The following table summarizes the calculation of basic and diluted income (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
(millions, except per share amounts)
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
Net Income (Loss) and Comprehensive Income (Loss) Attributable to Noble Energy
|
$
|
17
|
|
|
$
|
227
|
|
|
$
|
(306
|
)
|
|
$
|
758
|
|
|
Weighted Average Number of Shares Outstanding, Basic (1)
|
478
|
|
|
482
|
|
|
478
|
|
|
484
|
|
|
Incremental Shares from Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust
|
2
|
|
|
2
|
|
|
—
|
|
|
2
|
|
|
Weighted Average Number of Shares Outstanding, Diluted
|
480
|
|
|
484
|
|
|
478
|
|
|
486
|
|
|
Income (Loss) Per Share, Basic
|
$
|
0.04
|
|
|
$
|
0.47
|
|
|
$
|
(0.64
|
)
|
|
$
|
1.57
|
|
|
Income (Loss) Per Share, Diluted
|
$
|
0.04
|
|
|
$
|
0.47
|
|
|
$
|
(0.64
|
)
|
|
$
|
1.56
|
|
|
Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above
|
14
|
|
|
13
|
|
|
15
|
|
|
14
|
|
|
|
|
|
(1)
|
Decrease in weighted average number of shares outstanding reflects the impact of Noble Energy common stock repurchased in 2018 pursuant to our $750 million share repurchase program.
|
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide a narrative about our business from the perspective of management. We use common industry terms, such as thousand barrels of oil equivalent per day (MBoe/d) and million cubic feet equivalent per day (MMcfe/d), to discuss production and sales volumes. Our MD&A is presented in the following major sections:
The preceding consolidated financial statements, including the notes thereto, contain detailed information that should be read in conjunction with our MD&A.
EXECUTIVE OVERVIEW
The following discussion highlights significant operating and financial results for third quarter 2019. This discussion should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2018, which includes disclosures regarding our critical accounting policies as part of “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Operational Environment Update
Recent Activities During third quarter 2019, we progressed our US onshore drilling and completions activities, advanced our Eastern Mediterranean and West Africa regional natural gas developments and continued advancement of our US onshore and international exploration opportunities. We continue to execute capital and operating cost reduction efforts and reduce cycle times through operational improvements. During the quarter, we delivered consolidated sales volumes of 379 MBoe/d and achieved quarterly sales volumes records in both the DJ and Delaware Basins. This increased production was achieved with reduced capital investment. We continue to focus on progressing the Leviathan natural gas project, which was over 90% complete at quarter-end. Our focus on cost and capital efficiency and the startup of the Leviathan natural gas project should provide sustainable cash flows beginning in 2020.
Commodity Prices Crude oil prices remained volatile during third quarter 2019, with Brent and WTI averaging approximately $61 and $56 per barrel, respectively. The outlook for fourth quarter 2019 will depend on competing factors for supply and demand. Production cuts by the Organization of Petroleum Exporting Countries and geopolitical factors in critical oil producing regions remain constructive for global oil prices. However, a weakening of crude oil demand amid signs of a potential softening
in the global economy could result in lower prices. In addition, US and China trade tensions threaten further damage to global trade and economic growth and, consequently, crude oil demand. In the Delaware Basin, new pipeline startups, including interim crude oil service on the EPIC Y-Grade pipeline, have begun to improve basis differentials, while planned expansion of export infrastructure should help alleviate a portion of the discount of WTI to Brent going forward.
The US natural gas market continues to see depressed levels as supply outpaced demand over the past year. Despite record domestic liquefied natural gas (LNG) exports and high natural gas fired electric generation, natural gas inventories are projected to remain at or slightly above historical five-year averages. Natural gas price differentials increased in the DJ Basin, while differentials in the Delaware Basin continue to be wide despite additional pipeline capacity from the Delaware Basin to Corpus Christi, Texas. Additional Delaware Basin natural gas pipeline expansions are targeted for in-service in late 2020.
NGL prices are also suppressed amid increased production, high inventory levels, and downstream fractionation and export bottlenecks. US NGL prices should strengthen as new processing and export facilities are brought online.
To mitigate the effect of commodity price volatility, we have entered into crude oil and natural gas price hedging arrangements which also serve to enhance the predictability of our cash flows.
Financial Initiatives
Financial Flexibility, Liquidity and Balance Sheet Strength As we progress through the remainder of 2019, we believe we are positioned for sustainability, operational efficiency, and long-term success throughout the oil and gas business cycle. We remain committed to maintaining capital discipline and financial strength. See Operating Outlook – 2019 Capital Investment Program.
If commodity prices decline or operating costs rise, we could experience material asset impairments, as well as material negative impacts on our revenues, profitability, cash flows, liquidity and proved reserves, and, in response, we may consider changes in our capital program, share repurchase program, dividends policy or operating cost structure, and/or potential asset sales. Our revenues and our stock price could decline as a result of these potential developments.
Recently Issued Accounting Standards
OPERATING OUTLOOK
2019 Organic Capital Investment Program Our initial 2019 organic capital program, which excludes capital funded by Noble Midstream Partners and acquisition capital related to the EMG Pipeline, ranged from $2.4 to $2.6 billion and was primarily allocated to US onshore development and completion of the Leviathan natural gas project. In second quarter 2019, we lowered our full year organic capital program by $100 million. In third quarter 2019, as a result of US onshore well cost reductions and the Leviathan project spending below budget, we lowered our full year organic capital program by an additional $100 million. Fourth quarter 2019 expected organic capital expenditures range from $425 to $475 million and will primarily be allocated to continued US onshore development and completion of the Leviathan natural gas project. Amounts exclude capital funded by Noble Midstream Partners and acquisition capital related to the EMG Pipeline. See Liquidity and Capital Resources.
Dividends In April, July and October 2019, our Board of Directors approved quarterly cash dividends in amounts that represented a 9% increase over the prior year. This is our second straight year to increase our dividend, reflecting our commitment to return value to shareholders.
Colorado Senate Bill 19-181 For some time, initiatives have been underway in the State of Colorado to limit or ban crude oil and natural gas exploration, development or operations. During first quarter 2019, Senate Bill 19-181 (SB 181) was passed by the State Legislature. On April 16, 2019, the Governor signed the bill into law. The legislation makes changes in Colorado oil and gas law, including, among other matters, requiring the Colorado Oil and Gas Conservation Commission (Commission) to prioritize public health and environmental concerns in its decisions, instructing the Commission to adopt rules to minimize emissions of methane and other air contaminants, and delegating considerable new authority to local governments to regulate surface impacts. The Commission has initiated new rulemakings related to, among other things, incorporating new public health, safety, and environmental priorities into their regulations, updating wellbore integrity and flowline rules, and adopting new alternative location analysis and cumulative impact procedures. In addition, some local communities have adopted further restrictions for oil and gas activities, such as requiring greater setbacks, and other groups have sought a cessation of permit issuances entirely until the Commission publishes new rules in keeping with SB 181.
The majority of our acreage in Colorado is in rural, unincorporated areas of Weld County, and we continue to work closely with local regulators and communities to ensure safe and responsible operations and future planning. At this time, we do not foresee significant changes to our development plans, as we have all necessary approvals of more than 550 permits to drill wells over the next several years. The approved permits are for wells in multiple Integrated Development Plans (IDPs), many of which are
in our Mustang Comprehensive Drilling Plan (CDP). We will continue to work closely with Weld County on the required local permits and agreements for the CDP. However, if additional regulatory measures are adopted, we could incur additional costs to comply with the requirements or we may experience delays and/or curtailment in the permitting or pursuit of our exploration, development, or production activities. Such compliance costs and delays, curtailments, limitations, or prohibitions could have a material adverse effect on our cash flows, results of operations, financial condition, and liquidity.
RESULTS OF OPERATIONS – EXPLORATION AND PRODUCTION (E&P)
We continue to advance our major development projects, which we expect to deliver incremental production and cash flows over the next several years.
Sanctioned Ongoing Development Projects
A “sanctioned” development project is one for which a final investment decision has been reached. Updates on major development projects are as follows:
US Onshore
During third quarter 2019, our US onshore E&P activities consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
Location
|
Average Rigs Operated
|
|
Wells Drilled (1)
|
|
Wells Brought Online
|
|
Average Sales Volumes
(MBoe/d)
|
|
DJ Basin
|
2
|
|
28
|
|
38
|
|
158
|
|
Delaware Basin
|
3
|
|
20
|
|
17
|
|
70
|
|
Eagle Ford Shale
|
—
|
|
—
|
|
—
|
|
65
|
|
Total
|
5
|
|
48
|
|
55
|
|
293
|
|
|
|
|
(1)
|
The number of wells drilled refers to the number of wells completed, regardless of when drilling was initiated.
|
DJ Basin During third quarter 2019, we achieved a quarterly average sales volume record of 158 MBoe/d. Our activities were focused primarily on progressing development in the Mustang, which benefits from our approved CDP, Wells Ranch and East Pony areas. We continue to see increased capital efficiencies as a result of improved drilling and completion performance. In the Mustang, we utilized our first electric powered drilling rig, resulting in reduced noise, emissions and fuel costs.
In addition, we submitted an application for approval of the North Wells Ranch CDP. This CDP covers approximately 38,000 net acres and up to 250 potential drilling permits. Final approval is targeted for early 2020.
Delaware Basin During third quarter 2019, we achieved a quarterly average sales volume record of 70 MBoe/d. Our activity focused primarily on drilling and completion optimization, leading to capital and operational cost efficiencies. We brought online our first field power substation, which will provide a reliable power source to support field operations.
Eagle Ford Shale During third quarter 2019, we focused on maximizing cash flows from existing production and conducted two well refractures on Gates Ranch. We continue to evaluate and assess our development plan for the area and are incorporating learnings from our refracture results.
International
Leviathan Natural Gas Project (Offshore Israel) As of September 30, 2019, the project was over 90% complete and is ahead of schedule and below budget. During third quarter 2019, the topsides set sail and arrived in Israel, where they were installed, and we completed all subsea construction scope and pre-commissioning activities. The remaining commissioning and operational readiness activities are underway, with first production anticipated in December 2019.
Leviathan and Tamar Gas Sales and Purchase Agreements (Offshore Israel) In October 2019, we announced that we and our partners had amended the agreements for the sale of natural gas to Dolphinus Holdings Limited from the Leviathan and Tamar fields. The amended agreements, which are subject to certain regulatory approvals, provide for total combined firm contract quantities of 3.0 trillion cubic feet (Tcf) of natural gas, more than doubling the firm volume commitments previously agreed. In addition, each agreement has been extended by five years to reflect 15-year terms and include take-or-pay commitments.
During the two-year period ending June 30, 2022, the Leviathan field will backstop any volume commitment that the Tamar field is unable to deliver under the amended agreement.
EMG Pipeline (Offshore Israel) During third quarter 2019, we funded a $185 million investment in EMED Pipeline B.V. in support of its planned acquisition of an approximate 39% equity interest in EMG, which owns the EMG Pipeline. Upon closing of the planned equity transaction, which is anticipated in fourth quarter 2019, we will own an effective, indirect interest of
approximately 10%, net, in EMG. The EMG Pipeline will support delivery of natural gas from our producing fields offshore Israel into Egypt.
Aseng Development Well (Offshore Equatorial Guinea) During third quarter 2019, the Aseng field surpassed 100 MMBbl of crude oil produced. In addition, we drilled and completed a development well which is expected to mitigate field decline. Production came online in October 2019.
Alen Natural Gas Development (Offshore Equatorial Guinea) In second quarter 2019, we announced the sanction of the Alen natural gas development. Natural gas from the Alen field will be processed through the existing Alba Plant LLC liquefied petroleum gas (LPG) processing plant (Alba Plant) and Equatorial Guinea's LNG production facility (EG LNG) located at Punta Europa, Bioko Island. Definitive agreements in support of the project have been executed among the Alen field partners, the Alba Plant and EG LNG plant owners, as well as the government of the Republic of Equatorial Guinea.
The Alen natural gas monetization project will produce through three existing high-capacity wells and will require minor platform modifications to deliver sales gas from the Alen field to the Alba Plant and EG LNG facilities. The Alen field partners plan to construct a 24-inch pipeline capable of handling 950 MMcfe/d to transport all natural gas processed through the Alen platform approximately 70 kilometers to the onshore facilities. First production is anticipated in the first half of 2021. At start-up, natural gas sales from the Alen field are anticipated to be between 200 and 300 MMcfe/d, gross (approximately 75 to 115 MMcfe/d, net). The wet gas stream will be tolled through the Alba Plant for additional liquids recovery before the dry gas is converted into LNG at the EG LNG facility.
Unsanctioned Projects
Cyprus Natural Gas Project (Offshore Cyprus) We continue to work with the Government of Cyprus on a plan of development for the Aphrodite field that, as currently contemplated, would deliver natural gas to regional customers. In addition, we are focused on capital cost improvements, as well as natural gas marketing efforts and execution of natural gas sales and purchase agreements, which, once secured, will progress the project to a final investment decision.
Exploration Program Update
US Onshore Acreage Our US onshore unconventional exploration position includes more than 175,000 acres residing in two plays in Wyoming. During third quarter 2019, we progressed activities to obtain required approvals and permits in support of planned future drilling activities.
Offshore Colombia We have signed an agreement for a 40% operated working interest in more than two million gross acres offshore Colombia, located on two blocks. We expect to drill an exploration well in 2020. During third quarter 2019, we continued well planning and permitting activities.
Potential for Future Dry Hole Costs, Lease Abandonment Expense or Property Impairments
Exploration Activities We continue to seek and evaluate significant onshore and/or offshore opportunities for future exploration. Through our drilling activities, we do not always encounter hydrocarbons or we may find hydrocarbons but subsequently reach a decision, through additional analysis or appraisal drilling, that a development project is not economically or operationally viable. Additionally, we may not be able to conduct exploration activities prior to lease expirations or may choose to relinquish or exit licenses or leases. Therefore, future dry hole cost and/or leasehold abandonment expense could be significant. See Item 1. Financial Statements – Note 5. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
Producing Properties A decline in future commodity prices could result in some of our properties becoming uneconomic, resulting in an impairment charge, decrease in proved reserves and/or shut-in of currently producing wells. In addition, in certain US onshore areas, transportation bottlenecks caused by production above transportation capacity and/or lack of infrastructure may reduce the amount of production reaching markets, resulting in lower in-basin pricing (i.e. higher basis differential). An increase in basis differentials could also reduce cash flows and result in property impairment charges.
Results of Operations
Third Quarter 2019 E&P Operating Highlights Included:
|
|
|
|
•
|
total average consolidated sales volumes of 379 MBoe/d, net;
|
|
|
|
|
•
|
record average daily sales volumes of 127 MBbl/d, net, for US crude oil;
|
|
|
|
|
•
|
average daily sales volumes of 1.1 Bcfe/d, gross, of natural gas from the Tamar field, offshore Israel;
|
|
|
|
|
•
|
reached total gross volumes of 2 Tcf of natural gas produced from the Tamar field; and
|
|
|
|
|
•
|
commencement of crude oil shipments on the EPIC Y-Grade pipeline, which began interim crude service in August.
|
Third Quarter 2019 E&P Financial Results Included:
|
|
|
|
•
|
additions to equity method investments of $185 million, as compared with zero for third quarter 2018;
|
|
|
|
|
•
|
capital expenditures, excluding acquisitions, of $540 million, as compared with $696 million for third quarter 2018;
|
|
|
|
|
•
|
pre-tax income of $205 million, as compared with $225 million for third quarter 2018; and
|
|
|
|
|
•
|
net gain on commodity derivative instruments of $129 million, as compared with a net loss of $155 million for third quarter 2018.
|
The following is a summarized statement of operations for our E&P business:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
(millions)
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
Oil, NGL and Gas Sales to Third Parties
|
$
|
1,003
|
|
|
$
|
1,136
|
|
|
$
|
2,894
|
|
|
$
|
3,409
|
|
|
Sales of Purchased Oil and Gas
|
22
|
|
|
—
|
|
|
64
|
|
|
—
|
|
|
Income from Equity Method Investments and Other
|
15
|
|
|
34
|
|
|
48
|
|
|
105
|
|
|
Total Revenues
|
1,040
|
|
|
1,170
|
|
|
3,006
|
|
|
3,514
|
|
|
Production Expense
|
370
|
|
|
316
|
|
|
1,019
|
|
|
997
|
|
|
Exploration Expense
|
25
|
|
|
25
|
|
|
82
|
|
|
89
|
|
|
Depreciation, Depletion and Amortization
|
544
|
|
|
456
|
|
|
1,512
|
|
|
1,336
|
|
|
Loss (Gain) on Divestitures, Net
|
—
|
|
|
5
|
|
|
—
|
|
|
(356
|
)
|
|
Asset Impairments
|
—
|
|
|
—
|
|
|
—
|
|
|
168
|
|
|
Cost of Purchased Oil and Gas
|
17
|
|
|
—
|
|
|
59
|
|
|
—
|
|
|
(Gain) Loss on Commodity Derivative Instruments
|
(129
|
)
|
|
155
|
|
|
23
|
|
|
483
|
|
|
Income Before Income Taxes
|
205
|
|
|
225
|
|
|
216
|
|
|
720
|
|
Average Oil, NGL and Gas Sales Volumes and Prices Average daily sales volumes from our share of production and realized sales prices were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Volumes (1)
|
|
Average Realized Sales Prices (1)
|
|
|
Crude Oil & Condensate
(MBbl/d)
|
|
NGLs
(MBbl/d)
|
|
Natural Gas
(MMcf/d)
|
|
Total
(MBoe/d)
|
|
Crude Oil & Condensate
(Per Bbl)
|
|
NGLs
(Per Bbl)
|
|
Natural Gas
(Per Mcf)
|
|
Three Months Ended September 30, 2019
|
|
United States
|
127
|
|
|
76
|
|
|
542
|
|
|
293
|
|
|
$
|
55.13
|
|
|
$
|
11.18
|
|
|
$
|
1.57
|
|
|
Eastern Mediterranean
|
—
|
|
|
—
|
|
|
231
|
|
|
39
|
|
|
—
|
|
|
—
|
|
|
5.55
|
|
|
West Africa (2)
|
15
|
|
|
—
|
|
|
190
|
|
|
47
|
|
|
58.62
|
|
|
—
|
|
|
0.27
|
|
|
Total Consolidated Operations (3)
|
142
|
|
|
76
|
|
|
963
|
|
|
379
|
|
|
55.48
|
|
|
11.18
|
|
|
2.27
|
|
|
Equity Investments (4)
|
1
|
|
|
5
|
|
|
—
|
|
|
6
|
|
|
57.44
|
|
|
25.85
|
|
|
—
|
|
|
Total (3)
|
143
|
|
|
81
|
|
|
963
|
|
|
385
|
|
|
$
|
55.50
|
|
|
$
|
12.06
|
|
|
$
|
2.27
|
|
|
Three Months Ended September 30, 2018
|
|
United States (5)
|
109
|
|
|
63
|
|
|
464
|
|
|
249
|
|
|
$
|
65.54
|
|
|
$
|
28.58
|
|
|
$
|
2.31
|
|
|
Eastern Mediterranean
|
—
|
|
|
—
|
|
|
241
|
|
|
41
|
|
|
—
|
|
|
—
|
|
|
5.49
|
|
|
West Africa (2)
|
13
|
|
|
—
|
|
|
217
|
|
|
49
|
|
|
73.70
|
|
|
—
|
|
|
0.27
|
|
|
Total Consolidated Operations
|
122
|
|
|
63
|
|
|
922
|
|
|
339
|
|
|
66.41
|
|
|
28.58
|
|
|
2.66
|
|
|
Equity Investments (4)
|
1
|
|
|
5
|
|
|
—
|
|
|
6
|
|
|
74.88
|
|
|
48.27
|
|
|
—
|
|
|
Total
|
123
|
|
|
68
|
|
|
922
|
|
|
345
|
|
|
$
|
66.50
|
|
|
$
|
29.92
|
|
|
$
|
2.66
|
|
|
Nine Months Ended September 30, 2019
|
|
United States
|
119
|
|
|
67
|
|
|
507
|
|
|
270
|
|
|
$
|
55.59
|
|
|
$
|
14.22
|
|
|
$
|
1.87
|
|
|
Eastern Mediterranean
|
—
|
|
|
—
|
|
|
224
|
|
|
38
|
|
|
—
|
|
|
—
|
|
|
5.55
|
|
|
West Africa (2)
|
13
|
|
|
—
|
|
|
186
|
|
|
44
|
|
|
61.75
|
|
|
—
|
|
|
0.27
|
|
|
Total Consolidated Operations (3)
|
132
|
|
|
67
|
|
|
917
|
|
|
352
|
|
|
56.18
|
|
|
14.22
|
|
|
2.45
|
|
|
Equity Investments (4)
|
1
|
|
|
4
|
|
|
—
|
|
|
5
|
|
|
59.81
|
|
|
30.94
|
|
|
—
|
|
|
Total (3)
|
133
|
|
|
71
|
|
|
917
|
|
|
357
|
|
|
$
|
56.22
|
|
|
$
|
15.23
|
|
|
$
|
2.45
|
|
|
Nine Months Ended September 30, 2018
|
|
United States (5)
|
113
|
|
|
63
|
|
|
479
|
|
|
255
|
|
|
$
|
63.98
|
|
|
$
|
26.22
|
|
|
$
|
2.42
|
|
|
Eastern Mediterranean
|
—
|
|
|
—
|
|
|
242
|
|
|
41
|
|
|
—
|
|
|
—
|
|
|
5.48
|
|
|
West Africa (2)
|
15
|
|
|
—
|
|
|
216
|
|
|
51
|
|
|
71.55
|
|
|
—
|
|
|
0.27
|
|
|
Total Consolidated Operations
|
128
|
|
|
63
|
|
|
937
|
|
|
347
|
|
|
64.86
|
|
|
26.22
|
|
|
2.71
|
|
|
Equity Investments (4)
|
2
|
|
|
5
|
|
|
—
|
|
|
7
|
|
|
72.46
|
|
|
43.70
|
|
|
—
|
|
|
Total
|
130
|
|
|
68
|
|
|
937
|
|
|
354
|
|
|
$
|
64.95
|
|
|
$
|
27.50
|
|
|
$
|
2.71
|
|
|
|
|
|
(1)
|
Natural gas is converted on the basis of six Mcf of gas per one barrel of crude oil equivalent (BOE). This ratio reflects an energy content equivalency and not a price or revenue equivalency. Given commodity price disparities, the prices for a barrel of crude oil equivalent for US natural gas and NGLs are significantly less than the price for a barrel of crude oil. In Israel, we sell natural gas under contracts where the majority of the price is fixed, resulting in less commodity price disparity between reporting periods.
|
|
|
|
|
(2)
|
Natural gas from the Alba field is sold under contract for $0.25 per MMBtu to a methanol plant, an LPG plant, an LNG plant and a power generation plant. The methanol and LPG plants are owned by affiliated entities accounted for under the equity method.
|
|
|
|
|
(3)
|
Includes a small amount of condensate sales from offshore Israel assets.
|
|
|
|
|
(4)
|
Volumes represent sales of condensate and LPG from the LPG plant in Equatorial Guinea. See Income from Equity Method Investments.
|
|
|
|
|
(5)
|
Includes 9 MBoe/d for first nine months of 2018 related to Gulf of Mexico assets sold in second quarter 2018. See Item 1. Financial Statements – Note 4. Acquisitions and Divestitures.
|
An analysis of revenues from sales of crude oil, NGLs and natural gas is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(millions)
|
Crude Oil & Condensate
|
|
NGLs
|
|
Natural Gas
|
|
Total
|
|
Three Months Ended September 30, 2018
|
$
|
744
|
|
|
$
|
166
|
|
|
$
|
226
|
|
|
$
|
1,136
|
|
|
Changes due to
|
|
|
|
|
|
|
|
|
Increase in Sales Volumes
|
123
|
|
|
30
|
|
|
7
|
|
|
160
|
|
|
Decrease in Sales Prices (1)
|
(143
|
)
|
|
(118
|
)
|
|
(32
|
)
|
|
(293
|
)
|
|
Three Months Ended September 30, 2019
|
$
|
724
|
|
|
$
|
78
|
|
|
$
|
201
|
|
|
$
|
1,003
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2018
|
$
|
2,266
|
|
|
$
|
449
|
|
|
$
|
694
|
|
|
$
|
3,409
|
|
|
Changes due to
|
|
|
|
|
|
|
|
|
Increase (Decrease) in Sales Volumes
|
123
|
|
|
22
|
|
|
(30
|
)
|
|
115
|
|
|
Decrease in Sales Prices (1)
|
(365
|
)
|
|
(213
|
)
|
|
(52
|
)
|
|
(630
|
)
|
|
Nine Months Ended September 30, 2019
|
$
|
2,024
|
|
|
$
|
258
|
|
|
$
|
612
|
|
|
$
|
2,894
|
|
Crude Oil and Condensate Sales Revenues Revenues from crude oil and condensate sales decreased in third quarter and the first nine months of 2019 as compared with 2018 primarily due to the following:
|
|
|
|
•
|
reduction in sales volumes of 7 MBbl/d for the first nine months of 2019 due to the sale of our Gulf of Mexico assets in second quarter 2018; and
|
|
|
|
|
•
|
lower West Africa sales volumes of 2 MBbl/d for the first nine months of 2019 due to timing of liftings and natural field decline;
|
partially offset by:
|
|
|
|
•
|
higher US onshore sales volumes of 18 MBbl/d and 13 MBbl/d for third quarter and the first nine months of 2019, respectively, primarily due to an increase in development activity in the DJ and Delaware Basins.
|
NGL Sales Revenues Revenues from NGL sales decreased in third quarter and the first nine months of 2019 as compared with 2018 primarily due to the following:
|
|
|
|
•
|
lower Eagle Ford Shale sales volumes of 8 MBbl/d for the first nine months of 2019 due to reduced activity and natural field decline;
|
partially offset by:
|
|
|
|
•
|
higher sales volumes in the DJ and Delaware Basins of 12 MBbl/d and 12 MBbl/d for third quarter and the first nine months of 2019, respectively, due to an increase in development activities.
|
Natural Gas Sales Revenues Revenues from natural gas sales decreased in third quarter and the first nine months of 2019 as compared with 2018 primarily due to the following:
|
|
|
|
•
|
lower Eagle Ford Shale sales volumes of 10 MMcf/d and 51 MMcf/d for third quarter and the first nine months of 2019, respectively, due to reduced activity and natural field decline;
|
|
|
|
|
•
|
lower West Africa sales volumes of 27 MMcf/d and 30 MMcf/d for third quarter and the first nine months of 2019, respectively, due to natural field decline and planned maintenance at onshore facilities during first quarter 2019, which required field shut-in for a portion of the period; and
|
|
|
|
|
•
|
lower Israel sales volumes of 10 MMcf/d and 18 MMcf/d for third quarter and the first nine months of 2019, respectively, primarily due to planned maintenance and the sale of a 7.5% interest in the Tamar field in March 2018;
|
partially offset by:
|
|
|
|
•
|
higher sales volumes in the DJ and Delaware Basins of 88 MMcf/d and 87 MMcf/d for third quarter and the first nine months of 2019, respectively, due to an increase in development activities.
|
Sales and Cost of Purchased Oil and Gas In third quarter and the first nine months of 2019, we engaged in third party sales and purchases of crude oil in the DJ Basin for flow assurance on pipelines used to deliver our production to market.
Income from Equity Method Investments and Other Income from equity method investments and other decreased in the first nine months of 2019 as compared with 2018. The decrease includes a $34 million decrease from Atlantic Methanol Production Company, LLC (AMPCO), our methanol investment, and a $24 million decrease from Alba Plant, our LPG investment, primarily due to decreases in average realized methanol and LPG prices and plant downtime due to planned maintenance activities.
Production Expense Components of production expense were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(millions, except unit rate)
|
Total per BOE (1)(2)
|
|
Total
|
|
United States (2)
|
|
Eastern Mediterranean
|
|
West Africa
|
|
Three Months Ended September 30, 2019
|
|
|
|
|
|
|
|
|
|
|
Lease Operating Expense (3)
|
$
|
4.02
|
|
|
$
|
140
|
|
|
$
|
111
|
|
|
$
|
7
|
|
|
$
|
22
|
|
|
Production and Ad Valorem Taxes
|
1.47
|
|
|
51
|
|
|
51
|
|
|
—
|
|
|
—
|
|
|
Gathering, Transportation and Processing
|
5.00
|
|
|
174
|
|
|
173
|
|
|
1
|
|
|
—
|
|
|
Other Royalty Expense
|
0.14
|
|
|
5
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
Total Production Expense
|
$
|
10.64
|
|
|
$
|
370
|
|
|
$
|
340
|
|
|
$
|
8
|
|
|
$
|
22
|
|
|
Total Production Expense per BOE
|
|
|
$
|
10.64
|
|
|
$
|
12.61
|
|
|
$
|
2.24
|
|
|
$
|
5.17
|
|
|
Three Months Ended September 30, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease Operating Expense (3)
|
$
|
4.37
|
|
|
$
|
136
|
|
|
$
|
114
|
|
|
$
|
7
|
|
|
$
|
15
|
|
|
Production and Ad Valorem Taxes
|
1.48
|
|
|
46
|
|
|
46
|
|
|
—
|
|
|
—
|
|
|
Gathering, Transportation and Processing
|
4.14
|
|
|
129
|
|
|
129
|
|
|
—
|
|
|
—
|
|
|
Other Royalty Expense
|
0.16
|
|
|
5
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
Total Production Expense
|
$
|
10.15
|
|
|
$
|
316
|
|
|
$
|
294
|
|
|
$
|
7
|
|
|
$
|
15
|
|
|
Total Production Expense per BOE
|
|
|
$
|
10.15
|
|
|
$
|
12.82
|
|
|
$
|
1.90
|
|
|
$
|
3.32
|
|
|
Nine Months Ended September 30, 2019
|
|
|
|
|
|
|
|
|
|
|
Lease Operating Expense (3)
|
$
|
4.50
|
|
|
$
|
432
|
|
|
$
|
350
|
|
|
$
|
26
|
|
|
$
|
56
|
|
|
Production and Ad Valorem Taxes
|
1.44
|
|
|
138
|
|
|
138
|
|
|
—
|
|
|
—
|
|
|
Gathering, Transportation and Processing
|
4.59
|
|
|
440
|
|
|
439
|
|
|
1
|
|
|
—
|
|
|
Other Royalty Expense
|
0.09
|
|
|
9
|
|
|
9
|
|
|
—
|
|
|
—
|
|
|
Total Production Expense
|
$
|
10.63
|
|
|
$
|
1,019
|
|
|
$
|
936
|
|
|
$
|
27
|
|
|
$
|
56
|
|
|
Total Production Expense per BOE
|
|
|
$
|
10.63
|
|
|
$
|
12.70
|
|
|
$
|
2.63
|
|
|
$
|
4.70
|
|
|
Nine Months Ended September 30, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease Operating Expense (3)
|
$
|
4.54
|
|
|
$
|
429
|
|
|
$
|
354
|
|
|
$
|
19
|
|
|
$
|
56
|
|
|
Production and Ad Valorem Taxes
|
1.55
|
|
|
147
|
|
|
147
|
|
|
—
|
|
|
—
|
|
|
Gathering, Transportation and Processing
|
4.11
|
|
|
389
|
|
|
389
|
|
|
—
|
|
|
—
|
|
|
Other Royalty Expense
|
0.34
|
|
|
32
|
|
|
32
|
|
|
—
|
|
|
—
|
|
|
Total Production Expense
|
$
|
10.54
|
|
|
$
|
997
|
|
|
$
|
922
|
|
|
$
|
19
|
|
|
$
|
56
|
|
|
Total Production Expense per BOE
|
|
|
$
|
10.54
|
|
|
$
|
13.22
|
|
|
$
|
1.73
|
|
|
$
|
4.04
|
|
|
|
|
|
(1)
|
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investments.
|
|
|
|
|
(2)
|
US production expense includes charges from our midstream operations that are eliminated on a consolidated basis.
|
|
|
|
|
(3)
|
Lease operating expense includes oil and gas operating costs (labor, fuel, repairs, replacements, saltwater disposal and other related lifting costs) and workover expense.
|
Production expense for third quarter and the first nine months of 2019 increased as compared with 2018, primarily due to the following:
|
|
|
|
•
|
increase in US gathering, transportation and processing (GTP) expense primarily due to increased development activities in our DJ and Delaware Basins and higher rates in our DJ Basin;
|
|
|
|
|
•
|
increase in Eastern Mediterranean lease operating expense due to planned maintenance activities; and
|
|
|
|
|
•
|
increase in West Africa lease operating expense due to increase in volumes lifted from the higher-cost Alen field;
|
partially offset by:
|
|
|
|
•
|
decrease in US lease operating expense primarily due to the sale of our Gulf of Mexico assets and cost reduction efforts in our US onshore basins; and
|
|
|
|
|
•
|
decrease in US other royalty expense due to lower commodity prices.
|
The unit rate per BOE increased for third quarter and the first nine months of 2019 as compared with 2018 primarily due to an increase in GTP expense, as noted above, and an increase in volumes from higher-cost areas within US onshore and West Africa, partially offset by cost reduction efforts in our US onshore basins.
Exploration Expense Exploration expense for third quarter and the first nine months of 2019 totaled $25 million and $82 million, respectively, including staff expense of $10 million and $34 million, respectively. Exploration expense for third quarter and the first nine months of 2018 totaled $25 million and $89 million, respectively, including staff expense of $14 million and $41 million, respectively.
Depreciation, Depletion and Amortization (DD&A) Expense DD&A expense was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(millions, except unit rate)
|
Total
|
|
United States
|
|
Eastern Mediterranean
|
|
West Africa
|
|
Other Int'l
|
|
Three Months Ended September 30, 2019
|
|
|
|
|
|
|
|
|
|
|
DD&A Expense
|
$
|
544
|
|
|
$
|
505
|
|
|
$
|
17
|
|
|
$
|
21
|
|
|
$
|
1
|
|
|
Unit Rate per BOE (1)
|
$
|
15.64
|
|
|
$
|
18.73
|
|
|
$
|
4.76
|
|
|
$
|
4.94
|
|
|
$
|
—
|
|
|
Three Months Ended September 30, 2018
|
|
|
|
|
|
|
|
|
|
|
DD&A Expense
|
$
|
456
|
|
|
$
|
414
|
|
|
$
|
16
|
|
|
$
|
25
|
|
|
$
|
1
|
|
|
Unit Rate per BOE (1)
|
$
|
14.64
|
|
|
$
|
18.05
|
|
|
$
|
4.34
|
|
|
$
|
5.53
|
|
|
$
|
—
|
|
|
Nine Months Ended September 30, 2019
|
|
|
|
|
|
|
|
|
|
|
DD&A Expense
|
$
|
1,512
|
|
|
$
|
1,401
|
|
|
$
|
50
|
|
|
$
|
60
|
|
|
$
|
1
|
|
|
Unit Rate per BOE (1)
|
$
|
15.77
|
|
|
$
|
19.01
|
|
|
$
|
4.86
|
|
|
$
|
5.04
|
|
|
$
|
—
|
|
|
Nine Months Ended September 30, 2018
|
|
|
|
|
|
|
|
|
|
|
DD&A Expense
|
$
|
1,336
|
|
|
$
|
1,214
|
|
|
$
|
44
|
|
|
$
|
77
|
|
|
$
|
1
|
|
|
Unit Rate per BOE (1)
|
$
|
14.12
|
|
|
$
|
17.41
|
|
|
$
|
4.00
|
|
|
$
|
5.55
|
|
|
$
|
—
|
|
|
|
|
|
(1)
|
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investments.
|
DD&A expense for third quarter and the first nine months of 2019 increased as compared with 2018, primarily due to the following:
|
|
|
|
•
|
capital investment and development activities in the DJ and Delaware Basins resulting in higher sales volumes; and
|
|
|
|
|
•
|
increase in Eastern Mediterranean due to the retirement of certain capital assets resulting in accelerated depreciation;
|
partially offset by:
|
|
|
|
•
|
decrease resulting from the sale of our Gulf of Mexico assets in second quarter 2018; and
|
|
|
|
|
•
|
reduced sales volumes in West Africa, as noted above, and reserves additions subsequent to third quarter 2018.
|
The unit rate per BOE for third quarter and the first nine months of 2019 increased as compared with 2018, primarily due to the increase in total DD&A expense, as noted above. Specifically, development activity increased in the higher-cost Delaware Basin and the 2018 sale of lower-cost Tamar reserves increased the overall unit rate per BOE. The rate was also impacted by year-end 2018 update to proved reserves quantities used to calculate DD&A, which reflected negative non-price reserves revisions recorded for the Delaware Basin attributable to changes in expected recoveries and higher operating and capital costs. The increase in the unit rate is partially offset by the sale of higher-cost production from the Gulf of Mexico assets.
Loss on Commodity Derivative Instruments Loss on commodity derivative instruments for the first nine months of 2019 decreased as compared with 2018.
For the first nine months of 2019, loss on commodity derivative instruments included:
|
|
|
|
•
|
net cash receipts of $28 million; and
|
|
|
|
|
•
|
net non-cash decrease of $51 million in the fair value of our net commodity derivative asset, primarily driven by changes in the forward commodity price curves for crude oil.
|
For the first nine months of 2018, loss on commodity derivative instruments included:
|
|
|
|
•
|
net cash payments of $160 million; and
|
|
|
|
|
•
|
net non-cash decrease of $323 million in the fair value of our net commodity derivative liability, primarily driven by changes in the forward commodity price curves for crude oil.
|
RESULTS OF OPERATIONS – MIDSTREAM
The Midstream segment develops, owns and operates domestic midstream infrastructure assets, as well as invests in other midstream projects, with current focus in the DJ and Delaware Basins.
Results of Operations
Third Quarter 2019 Midstream Operating Highlights and Financial Results Included:
|
|
|
|
•
|
entered into a strategic relationship with Saddlehorn Pipeline Company, LLC (Saddlehorn);
|
|
|
|
|
•
|
total revenues of $186 million, as compared with $168 million for third quarter 2018;
|
|
|
|
|
•
|
pre-tax income of $83 million, as compared with pre-tax income of $268 million for third quarter 2018; and
|
|
|
|
|
•
|
additions to equity method investments of $86 million, as compared with zero for third quarter 2018.
|
The following is a summarized statement of operations for our Midstream segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
(millions)
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
Midstream Services Revenues – Third Party
|
$
|
19
|
|
|
$
|
21
|
|
|
$
|
63
|
|
|
$
|
49
|
|
|
Sales of Purchased Oil and Gas
|
47
|
|
|
46
|
|
|
132
|
|
|
110
|
|
|
(Loss) Income from Equity Method Investments
|
(5
|
)
|
|
10
|
|
|
(5
|
)
|
|
35
|
|
|
Intersegment Revenues
|
125
|
|
|
91
|
|
|
322
|
|
|
257
|
|
|
Total Revenues
|
186
|
|
|
168
|
|
|
512
|
|
|
451
|
|
|
Operating Costs and Expenses
|
31
|
|
|
30
|
|
|
108
|
|
|
96
|
|
|
Depreciation, Depletion and Amortization
|
26
|
|
|
24
|
|
|
77
|
|
|
62
|
|
|
Gain on Divestitures, Net
|
—
|
|
|
(198
|
)
|
|
—
|
|
|
(503
|
)
|
|
Cost of Purchased Oil and Gas
|
46
|
|
|
44
|
|
|
125
|
|
|
106
|
|
|
Total Expense (Income)
|
103
|
|
|
(100
|
)
|
|
310
|
|
|
(239
|
)
|
|
Income Before Income Taxes
|
$
|
83
|
|
|
$
|
268
|
|
|
$
|
202
|
|
|
$
|
690
|
|
Midstream Services Revenues – Third Party The amount of revenue generated by the Midstream segment depends primarily on the volumes of crude oil, natural gas and water for which services are provided to dedicated acreage for our E&P business and to third-party customers. These volumes are affected by the level of drilling and completion activity and by changes in the supply of, and demand for, crude oil, NGLs and natural gas in the markets served directly or indirectly by our midstream assets.
Midstream services revenues for the first nine months of 2019 increased as compared with 2018, primarily due to increases in crude oil, natural gas and produced water gathering services and fresh water delivery. The increases were due primarily to higher Delaware Basin throughput volumes, commencement of services in the Mustang IDP in 2018, and services related to the Black Diamond system, which was acquired during first quarter 2018 in the Saddle Butte acquisition.
Sales and Costs of Purchased Oil and Gas Sales and costs of purchased oil for third quarter and the first nine months of 2019 increased as compared with 2018 due to a full nine months of services related to the Black Diamond system.
(Loss) Income from Equity Method Investments Income from equity method investments decreased for third quarter and the first nine months of 2019 as compared with 2018, primarily due to the sale of our investment in CNX Midstream Partners in second quarter 2018 and operating losses associated with EPIC Y-Grade, EPIC Crude Holdings and Delaware Crossing. Operating losses were primarily due to expenses incurred for the formation of the joint ventures and general and administrative expenses incurred prior to service commencement.
Operating Costs and Expenses Operating costs and expenses for third quarter and the first nine months of 2019 increased as compared with 2018, primarily due to an increase in gathering systems operating expense associated with the Delaware Basin central gathering facilities (CGF) that were completed during 2018, additional expenses associated with the Black Diamond system and expenses associated with the commencement of gathering services in the Mustang IDP in 2018.
DD&A Expense DD&A expense for third quarter and the first nine months of 2019 increased as compared with 2018, primarily due to certain assets being placed in service subsequent to third quarter 2018, including the Mustang IDP gathering system, the Delaware Basin CGFs, and additional Black Diamond assets. In addition, DD&A expense includes a full nine months of amortization related to intangible assets acquired in the Saddle Butte acquisition.
Saddlehorn In third quarter 2019, Noble Midstream Partners entered into a strategic relationship with Saddlehorn, resulting in new long-term firm transportation commitments and an option to acquire up to a 20% ownership interest in Saddlehorn, which transports crude oil and condensate from the DJ and Powder River Basins to storage facilities in Cushing, Oklahoma. The investment option expires in April 2020.
RESULTS OF OPERATIONS – CORPORATE
Expenses related to debt, such as interest and other debt-related costs, headquarters depreciation, corporate general and administrative (G&A) expenses, exit costs and certain costs associated with mitigating the effects of our retained Marcellus Shale transportation agreements, are recorded at the Corporate level.
Transportation Exit Cost Revenues and expenses associated with retained Marcellus Shale transportation contracts were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
(millions)
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
Sales of Purchased Gas (1)
|
$
|
18
|
|
|
$
|
26
|
|
|
$
|
68
|
|
|
$
|
81
|
|
|
Cost of Purchased Gas (1)
|
33
|
|
|
32
|
|
|
112
|
|
|
98
|
|
|
Firm Transportation Exit Cost (2)
|
—
|
|
|
—
|
|
|
92
|
|
|
—
|
|
|
|
|
|
(1)
|
Relates to third party mitigation activities we engage in to utilize a portion of our Marcellus Shale transportation commitment. Cost of purchased gas includes utilized and unutilized transportation expense. Amounts for the nine months ended 2019 increased as compared to 2018 due to increased transportation expense for pipelines that came into service in fourth quarter 2018.
|
|
|
|
|
(2)
|
Represents exit costs related to future commitments to a third party resulting from a permanent capacity assignment.
|
General and Administrative Expense G&A expense was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
(millions, except unit rate)
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
G&A Expense
|
$
|
91
|
|
|
$
|
107
|
|
|
$
|
298
|
|
|
$
|
316
|
|
|
Unit Rate per BOE (1)
|
$
|
2.62
|
|
|
$
|
3.44
|
|
|
$
|
3.11
|
|
|
$
|
3.34
|
|
|
|
|
|
(1)
|
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investments.
|
Due to our focus on overall G&A cost reductions, expense for third quarter and the first nine months of 2019 decreased as compared with 2018, and we achieved a 15% reduction as compared to third quarter 2018. Decreases were primarily due to reduced employee, office and travel expenses, partially offset by increases in technology costs. The unit rate per BOE for third quarter and the first nine months of 2019 also decreased as compared with 2018 due to the reduction in G&A expense and the increase in the total sales volumes.
Interest Expense and Capitalized Interest Interest expense and capitalized interest were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
(millions, except unit rate)
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
Interest Expense, Gross
|
$
|
92
|
|
|
$
|
88
|
|
|
$
|
269
|
|
|
$
|
269
|
|
|
Capitalized Interest
|
(25
|
)
|
|
(18
|
)
|
|
(73
|
)
|
|
(53
|
)
|
|
Interest Expense, Net
|
$
|
67
|
|
|
$
|
70
|
|
|
$
|
196
|
|
|
$
|
216
|
|
|
Unit Rate per BOE (1)
|
$
|
1.93
|
|
|
$
|
2.25
|
|
|
$
|
2.04
|
|
|
$
|
2.28
|
|
|
|
|
|
(1)
|
Consolidated unit rates exclude sales volumes and expenses attributable to equity method investments.
|
Interest expense, gross, for third quarter and the first nine months of 2019 remained relatively flat as compared with 2018. See Item 1. Financial Statements – Note 7. Debt. Capitalized interest for third quarter and the first nine months of 2019 increased as compared with 2018, primarily due to higher work in progress amounts related to Leviathan development and additions to equity method investments engaged in construction activities.
The unit rate per BOE for third quarter and the first nine months of 2019 decreased as compared with 2018, primarily due to the reduction in net interest expense, noted above, and the increase in total sales volumes.
LIQUIDITY AND CAPITAL RESOURCES
Capital Structure/Financing Strategy
In seeking to effectively fund and monetize our discovered hydrocarbons, we employ a capital structure and financing strategy designed to provide sufficient liquidity throughout commodity price cycles, including a sustained period of low prices.
Specifically, we strive to retain the ability to fund long cycle, multi-year, capital intensive development projects throughout a range of scenarios, while also funding a continuing exploration program and maintaining capacity to capitalize on financially attractive merger and acquisition opportunities. We endeavor to maintain a strong balance sheet and an investment grade debt rating in service of these objectives.
We strive to maintain a minimum liquidity level to address volatility and risk. Traditional sources of liquidity are cash flows from operations, cash on hand, proceeds from divestitures of properties and other investments, and available borrowing capacity under our $4.0 billion unsecured Revolving Credit Facility. We occasionally access the capital markets to ensure adequate liquidity exists in the form of unutilized capacity under our Revolving Credit Facility or to refinance scheduled debt maturities. Refer to Noble Midstream Services 2019 Term Loan Credit Facility and Subsequent Event below for recently completed capital market activities.
Supported by our investment grade credit rating, we established a $4.0 billion commercial paper program in first quarter 2019. This program can be accessed as needed to supplement operating cash flows for short-term funding needs. In addition, we may from time to time seek to retire or purchase our outstanding senior notes through cash purchases in the open market, privately negotiated transactions or otherwise. Such repurchases, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors.
We also evaluate potential strategic farm-out arrangements of our working interests for reimbursement of our capital spending. We periodically consider repatriations of foreign cash to increase our financial flexibility and fund our capital investment program. Additionally, we enter into crude oil and natural gas price hedging arrangements in an effort to mitigate the effects of commodity price volatility and enhance the predictability of cash flows relating to the marketing of a portion of our crude oil and natural gas production.
Thus far in 2019, we have funded our capital program with cash flows from operations, cash on hand, commercial paper borrowings, and proceeds from divestments of non-strategic assets. We did not repurchase any shares of Noble Energy common stock under the Board of Directors-authorized $750 million share repurchase program during the first nine months of 2019.
Third Quarter 2019 Highlights
During third quarter 2019, we completed the following financing activities:
|
|
|
|
•
|
borrowed $271 million, net, under our $4.0 billion commercial paper program for working capital purposes;
|
|
|
|
|
•
|
repaid $320 million, net, under the Noble Midstream Services Revolving Credit Facility; and
|
|
|
|
|
•
|
borrowed $400 million under the Noble Midstream Services 2019 Term Loan Credit Facility, primarily to repay a portion of borrowings outstanding under the Noble Midstream Services Revolving Credit Facility.
|
Available Liquidity
The following table summarizes our cash, debt and available liquidity:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2019
|
|
December 31, 2018
|
|
(millions, except percentages)
|
Noble Energy Excluding
Noble Midstream Partners
|
|
Noble Midstream Partners
|
|
Total
|
|
Noble Energy Excluding
Noble Midstream Partners
|
|
Noble Midstream Partners
|
|
Total
|
|
Total Cash (1)
|
$
|
455
|
|
|
$
|
18
|
|
|
$
|
473
|
|
|
$
|
707
|
|
|
$
|
12
|
|
|
$
|
719
|
|
|
Amounts Available for Borrowing (2)
|
3,489
|
|
|
—
|
|
|
3,489
|
|
|
4,000
|
|
|
—
|
|
|
4,000
|
|
|
Total Liquidity
|
$
|
3,944
|
|
|
$
|
18
|
|
|
$
|
3,962
|
|
|
$
|
4,707
|
|
|
$
|
12
|
|
|
$
|
4,719
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Debt (3)
|
$
|
6,601
|
|
|
$
|
950
|
|
|
$
|
7,551
|
|
|
$
|
6,115
|
|
|
$
|
560
|
|
|
$
|
6,675
|
|
|
Noble Energy Share of Equity
|
|
|
|
|
$
|
9,004
|
|
|
|
|
|
|
$
|
9,426
|
|
|
Ratio of Debt-to-Book Capital (4)
|
|
|
|
|
46
|
%
|
|
|
|
|
|
41
|
%
|
|
|
|
|
(1)
|
Total cash includes $3 million of restricted cash at December 31, 2018.
|
|
|
|
|
(2)
|
Excludes amounts available to be borrowed under the Noble Midstream Services Revolving Credit Facility, which is not available to Noble Energy for general corporate purposes.
|
|
|
|
|
(4)
|
We define our ratio of debt-to-book capital as total debt divided by the sum of total debt plus Noble Energy's share of equity.
|
Cash and Cash Equivalents We had $473 million in cash and cash equivalents at September 30, 2019, primarily denominated in US dollars and invested in money market funds and short-term deposits with major financial institutions. Approximately
$430 million of this cash is attributable to our foreign subsidiaries. We do not expect to incur significant US income tax expense with respect to future repatriation of foreign cash.
Revolving Credit Facilities and Commercial Paper Program Noble Energy's $4.0 billion Revolving Credit Facility and the $800 million Noble Midstream Services Revolving Credit Facility both mature in 2023. These facilities are used to fund capital investment programs and acquisitions and may periodically provide amounts for working capital purposes. Additionally, in first quarter 2019, we established a commercial paper program to provide for short-term funding needs. The program allows for a maximum of $4.0 billion of unsecured commercial paper notes and is supported by Noble Energy's Revolving Credit Facility.
At September 30, 2019, outstanding commercial paper borrowings of $511 million reduced the amount available for borrowing under Noble Energy's Revolving Credit Facility to approximately $3.5 billion. Additionally, at September 30, 2019, $50 million was outstanding under the Noble Midstream Services Revolving Credit Facility, leaving $750 million available for borrowing. See Item 1. Financial Statements – Note 7. Debt.
Noble Midstream Services 2019 Term Loan Credit Facility In August 2019, Noble Midstream Services entered into a three-year senior unsecured term loan agreement, which provides for aggregate borrowings of up to $400 million. Noble Midstream Services borrowed $400 million in third quarter 2019. See Item 1. Financial Statements – Note 7. Debt.
GIP Preferred Equity Commitment In March 2019, Noble Midstream Partners secured a $200 million preferred equity commitment from GIP to fund capital contributions to Dos Rios Crude Intermediate LLC, a newly-formed subsidiary holding Noble Midstream Partners’ 30% equity interest in EPIC Crude Holdings. Of the $200 million total commitment, $100 million was funded, with the remaining $100 million available for a one year period, subject to certain conditions precedent. See Item 1. Financial Statements – Note 4. Acquisitions and Divestitures.
Subsequent Event On October 1, 2019, we issued $1.0 billion of notes, using proceeds from the issuance to fund the tender offer and redemption of our $1.0 billion 4.15% notes due December 15, 2021. In connection with the tender and redemption, in fourth quarter 2019, we will record early debt extinguishment fees of approximately $44 million in our consolidated statements of operations. See Item 1. Financial Statements – Note 7. Debt.
Contractual Obligations
Marcellus Shale Transportation Commitments We have remaining financial commitments of approximately $1.0 billion, undiscounted, associated with Marcellus Shale transportation contracts. See Item 1. Financial Statements – Note 9. Exit Cost – Transportation Commitments.
Letters of Credit In the ordinary course of business, we maintain letters of credit and bank guarantees with a variety of banks in support of certain performance obligations of our subsidiaries. Outstanding letters of credit and bank guarantees, including those of Noble Midstream Partners, totaled approximately $121 million at September 30, 2019.
Cash Flows
The following table summarizes our total cash provided by (used in) operating, investing and financing activities:
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|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
(millions)
|
2019
|
|
2018
|
|
Operating Activities
|
$
|
1,529
|
|
|
$
|
1,776
|
|
|
Investing Activities
|
(2,528
|
)
|
|
(1,502
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)
|
|
Financing Activities
|
753
|
|
|
(266
|
)
|
|
(Decrease) Increase in Cash, Cash Equivalents and Restricted Cash
|
$
|
(246
|
)
|
|
$
|
8
|
|
Operating Activities Cash provided by operating activities for the first nine months of 2019 decreased $247 million as compared with 2018. The decrease was primarily driven by a decrease in net revenues driven by lower commodity prices and higher production costs attributable to increased operational activity in US onshore, partially offset by cash received in settlements for commodity derivatives of $28 million, as compared with cash payments of $160 million in the prior year.
Investing Activities Cash used in investing activities increased approximately $1.0 billion for the first nine months of 2019 as compared with 2018, primarily due to a decrease in net proceeds provided by divestitures and additions to equity method investments of $686 million. These were partially offset by a decrease in capital spending for property, plant and equipment and the absence of spending on acquisitions, compared to $653 million in the prior year.
Financing Activities Our financing activities during the first nine months of 2019 included net borrowings of $511 million under the commercial paper program, Noble Midstream Partners' borrowings of $400 million on the Noble Midstream Services 2019 Term Loan Credit Facility, the receipt of $97 million of GIP preferred equity, net of offering costs, and net repayments of
$10 million on the Noble Midstream Services Revolving Credit Facility. Proceeds from the 2019 Term Loan Credit Facility were used to repay borrowings on Noble Midstream Services Revolving Credit Facility. In addition, during the first nine months of 2019, we paid $168 million of cash dividends to Noble Energy shareholders.
Our financing activities during the first nine months of 2018 included a $230 million, net, Revolving Credit Facility repayment and $35 million, net, Noble Midstream Services Revolving Credit Facility repayment, which included borrowings of $465 million primarily used to fund the Saddle Butte acquisition, offset by a repayment of $500 million drawn under the Noble Midstream Services 2018 Term Loan Credit Facility. We used $384 million of cash to redeem senior notes, repurchased $223 million of common stock pursuant to our stock repurchase program, paid $156 million of cash dividends to Noble Energy shareholders and paid $35 million of cash distributions to Noble Midstream Partners noncontrolling interest owners. We also received $348 million of contributions from noncontrolling interest owners. See Item 1. Financial Statements – Consolidated Statements of Cash Flows.
Capital Expenditure Activities
Our capital expenditures (on an accrual basis) were as follows:
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|
|
|
|
|
|
|
|
Three Months Ended September 30,
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|
Nine Months Ended September 30,
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(millions)
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2019
|
|
2018
|
|
2019
|
|
2018
|
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Unproved Property Acquisition (1)
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$
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(4
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)
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|
$
|
8
|
|
|
$
|
35
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|
|
$
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21
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|
|
Proved Property Acquisition (1)
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—
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|
|
—
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|
|
4
|
|
|
—
|
|
|
Exploration and Development
|
518
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|
|
676
|
|
|
1,728
|
|
|
2,090
|
|
|
Midstream (2)
|
56
|
|
|
69
|
|
|
174
|
|
|
685
|
|
|
Corporate and Other
|
21
|
|
|
11
|
|
|
52
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|
|
38
|
|
|
Total
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$
|
591
|
|
|
$
|
764
|
|
|
$
|
1,993
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|
|
$
|
2,834
|
|
|
|
|
|
|
|
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|
|
Additions to Equity Method Investments
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|
|
|
|
|
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EMED Pipeline B.V.
|
$
|
185
|
|
|
$
|
—
|
|
|
$
|
185
|
|
|
$
|
—
|
|
|
EPIC Y-Grade
|
18
|
|
|
—
|
|
|
169
|
|
|
—
|
|
|
EPIC Crude Holdings
|
54
|
|
|
—
|
|
|
273
|
|
|
—
|
|
|
Delaware Crossing
|
14
|
|
|
—
|
|
|
53
|
|
|
—
|
|
|
Other
|
—
|
|
|
—
|
|
|
6
|
|
|
—
|
|
|
Total Additions to Equity Method Investments (3)
|
$
|
271
|
|
|
$
|
—
|
|
|
$
|
686
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
Increase in Finance Lease Obligations
|
$
|
1
|
|
|
$
|
9
|
|
|
$
|
4
|
|
|
$
|
9
|
|
|
|
|
|
(1)
|
Costs relate to US onshore leasehold activity.
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(2)
|
Midstream expenditures for the nine months ended September 30, 2018 include $206 million related to the Saddle Butte acquisition.
|
Exploration and development costs for third quarter and the first nine months of 2019 decreased as compared with 2018 due to our focus on US onshore capital efficiencies and the near-term completion of Leviathan development activities. Year-to-date exploration and development costs include approximately $1.3 billion for US onshore and $368 million for Eastern Mediterranean, primarily related to Leviathan.
Midstream capital spending, excluding acquisitions, for third quarter and the first nine months of 2019 decreased as compared with 2018. 2019 activities focused primarily on well connections in the DJ and Delaware Basins, as well as expansion of the Mustang IDP gathering system. 2018 activities included construction and commencement of services for the Mustang IDP gathering and fresh water systems, Delaware Basin CGFs, and connecting the Black Diamond system to a major crude oil takeaway outlet in the DJ Basin.
Dividends
On October 22, 2019, our Board of Directors declared a quarterly cash dividend of 12 cents per Noble Energy common share, which will be paid on November 18, 2019 to shareholders of record on November 4, 2019. The amount of future dividends will be determined on a quarterly basis at the discretion of our Board of Directors and will depend on earnings, financial condition, capital requirements and other factors.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
Derivative Instruments Held for Non-Trading Purposes At September 30, 2019, our open commodity derivative instruments were in a net asset position with a fair value of $102 million. Based on the September 30, 2019 published commodity futures price curves for the underlying commodities, a hypothetical price increase of 10% per Bbl for crude oil and 10% per MMBtu for natural gas would decrease the fair value of our net commodity derivative asset by approximately $228 million. Even with certain hedging arrangements in place to mitigate the risk of commodity price volatility, our 2019 revenues and results of operations could be adversely affected if commodity prices decline. See Item 1. Financial Statements – Note 12. Derivative Instruments and Hedging Activities.
Interest Rate Risk
Changes in interest rates affect the amount of interest we pay on certain of our borrowings. Borrowings under our commercial paper program, the Revolving Credit Facility, Noble Midstream Services Revolving Credit Facility, and Noble Midstream Services Term Loan Credit Facilities, which as of September 30, 2019 total $1.5 billion and have a weighted average interest rate of 2.96%, are subject to variable interest rates which expose us to the risk of earnings or cash flow loss due to potential increases in market interest rates. While we currently have no interest rate derivative instruments as of September 30, 2019, we may invest in such instruments in the future in order to mitigate interest rate risk.
A change in the interest rate applicable to amounts, if any, outstanding under the facilities or commercial paper issuances mentioned above, would have had a de minimis impact on interest expense for third quarter and the first nine months of 2019. See Item 1. Financial Statements – Note 7. Debt.
Disclosure Regarding Forward-Looking Statements
This quarterly report on Form 10-Q contains forward-looking statements within the meaning of the federal securities laws. Forward-looking statements give our current expectations or forecasts of future events. These forward-looking statements include, among others, the following:
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•
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our future results of operations;
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•
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our liquidity and ability to finance our exploration and development activities;
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•
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our ability to successfully and economically explore for and develop crude oil, NGL and natural gas resources;
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•
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anticipated trends in our business;
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•
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market conditions in the oil and gas industry;
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•
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the impact of governmental regulation, including US federal, state, local, and foreign host government tax regulations, fiscal policies and terms, as well as that involving the protection of the environment or marketing of production and other regulations;
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•
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our ability to make and integrate acquisitions or execute divestitures; and
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Any such projections or statements reflect Noble Energy’s views (as of the date such projections were published or such statements were made) about future events and financial performance. No assurances can be given that such events or performance will occur as projected, and actual results may differ materially from those projected. Important factors that could cause the actual results to differ materially from those projected include, without limitation, the volatility in commodity prices for crude oil and natural gas, the presence or recoverability of estimated reserves, the ability to replace reserves, environmental risks, drilling and operating risks, exploration and development risks, information technology and security risks, competition, government regulation or other action, the ability of management to execute its plans to meet its goals and other risks inherent in Noble Energy’s business that are detailed in its Securities and Exchange Commission filings.
Forward-looking statements are typically identified by use of terms such as “may,” “will,” “expect,” “believe,” “anticipate,” “estimate,” “intend,” and similar words, although some forward-looking statements may be expressed differently. These forward-looking statements are made based upon our current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements. You should consider carefully the statements under Item 1A. Risk Factors included in our Annual Report on Form 10-K for the year ended December 31, 2018, which describe factors that could cause our actual results to differ from
those set forth in the forward-looking statements. Our Annual Report on Form 10-K for the year ended December 31, 2018 is available on our website at www.nblenergy.com.
Item 4. Controls and Procedures
Based on the evaluation of our disclosure controls and procedures by our principal executive officer and our principal financial officer, as of the end of the period covered by this quarterly report, each of them has concluded that our disclosure controls and procedures (as defined in Rule 13a-15(e) and Rule 15d-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act)), are effective. There were no changes in internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f) and 15d-15(f)) that occurred during the quarter covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. These forms can also be obtained from the SEC by calling 1-800-SEC-0330. Alternatively, you may access these reports at the SEC’s website at www.sec.gov.