UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31,June 30, 2020
OR
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____to_____
Commission file number: 001-07964
NOBLE ENERGY, INC.
(Exact name of registrant as specified in its charter)
|
| | | |
Delaware | | 73-0785597 |
(State or other jurisdiction of incorporation or organization) | | (I.R.S. employer identification number) |
1001 Noble Energy Way | | |
Houston, | Texas | | 77070 |
(Address of principal executive offices) | | (Zip Code) |
(281) | 872-3100 |
|
(281) 872-3100
(Registrant’s telephone number, including area code)
|
| | | | |
Securities registered pursuant to Section 12(b) of the Act: |
Title of each class | | Trading Symbol(s) | | Name of each exchange on which registered |
Common Stock, $0.01 par value | | NBL | | The Nasdaq Stock Market LLC |
| | | | (NASDAQ Global Select Market) |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller
reporting company or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
|
| | | | | | | |
Large accelerated filer | ☒ | Accelerated filer ☐ | Non-accelerated filer ☐ | Smaller reporting company | ☐ | Emerging growth company | ☐ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes ☐ No ☒
As of March 31,June 30, 2020, there were 479,698,676479,768,764 shares of the registrant’s common stock, par value $0.01 per share, outstanding.
TABLE OF CONTENTS
Part I. Financial Information
Item 1. Financial Statements
Noble Energy, Inc.
Consolidated Statements of Operations and Comprehensive Loss
(millions, except per share amounts)
(unaudited) | | | Three Months Ended March 31, | Three Months Ended June 30, | | Six Months Ended June 30, |
| 2020 | | 2019 | 2020 | | 2019 | | 2020 | | 2019 |
Revenues | | | | | | | | | | |
Oil, NGL and Gas Sales | $ | 894 |
| | $ | 937 |
| $ | 493 |
| | $ | 954 |
| | $ | 1,387 |
| | $ | 1,891 |
|
Sales of Purchased Oil and Gas | 125 |
| | 74 |
| 49 |
| | 103 |
| | 174 |
| | 177 |
|
Other Revenue | 1 |
| | 41 |
| 29 |
| | 36 |
| | 30 |
| | 77 |
|
Total | 1,020 |
| | 1,052 |
| 571 |
| | 1,093 |
| | 1,591 |
| | 2,145 |
|
Costs and Expenses | | | | |
| | |
| | | | |
Production Expense | 276 |
| | 305 |
| 214 |
| | 260 |
| | 490 |
| | 565 |
|
Exploration Expense | 1,504 |
| | 24 |
| 15 |
| | 33 |
| | 1,519 |
| | 57 |
|
Depreciation, Depletion and Amortization | 492 |
| | 508 |
| 320 |
| | 528 |
| | 812 |
| | 1,036 |
|
General and Administrative | 85 |
| | 102 |
| 63 |
| | 105 |
| | 148 |
| | 207 |
|
Cost of Purchased Oil and Gas | 139 |
| | 87 |
| 63 |
| | 113 |
| | 202 |
| | 200 |
|
Asset Impairments | 2,703 |
| | — |
| 51 |
| | — |
| | 2,754 |
| | — |
|
Goodwill Impairment | 110 |
| | — |
| — |
| | — |
| | 110 |
| | — |
|
Other Operating Expense, Net | 44 |
| | 117 |
| 73 |
| | 22 |
| | 117 |
| | 139 |
|
Total | 5,353 |
| | 1,143 |
| 799 |
| | 1,061 |
| | 6,152 |
| | 2,204 |
|
Operating Expense | (4,333 | ) | | (91 | ) | |
Other (Income) Expense | | | | |
(Gain) Loss on Commodity Derivative Instruments | (389 | ) | | 212 |
| |
Operating (Loss) Income | | (228 | ) | | 32 |
| | (4,561 | ) | | (59 | ) |
Other Expense (Income) | | |
| | |
| | | | |
Loss (Gain) on Commodity Derivative Instruments | | 158 |
| | (60 | ) | | (231 | ) | | 152 |
|
Interest, Net of Amount Capitalized | 81 |
| | 66 |
| 87 |
| | 63 |
| | 168 |
| | 129 |
|
Other Non-Operating (Income) Expense , Net | (7 | ) | | 4 |
| |
Other Non-Operating Expense (Income), Net | | 3 |
| | 1 |
| | (4 | ) | | 5 |
|
Total | (315 | ) | | 282 |
| 248 |
| | 4 |
| | (67 | ) | | 286 |
|
Loss Before Income Taxes | (4,018 | ) | | (373 | ) | |
Income Tax Benefit | (11 | ) | | (84 | ) | |
Net Loss and Comprehensive Loss Including Noncontrolling Interests | (4,007 | ) | | (289 | ) | |
Less: Net (Loss) Income and Comprehensive (Loss) Income Attributable to Noncontrolling Interests | (44 | ) | | 24 |
| |
(Loss) Income Before Income Taxes | | (476 | ) | | 28 |
| | (4,494 | ) | | (345 | ) |
Income Tax (Benefit) Expense | | (89 | ) | | 20 |
| | (100 | ) | | (64 | ) |
Net (Loss) Income and Comprehensive (Loss) Income Including Noncontrolling Interests | | (387 | ) | | 8 |
| | (4,394 | ) | | (281 | ) |
Less: Net Income (Loss) and Comprehensive Income (Loss) Attributable to Noncontrolling Interests | | 21 |
| | 18 |
| | (23 | ) | | 42 |
|
Net Loss and Comprehensive Loss Attributable to Noble Energy | $ | (3,963 | ) | | $ | (313 | ) | $ | (408 | ) | | $ | (10 | ) | | $ | (4,371 | ) | | $ | (323 | ) |
|
|
| |
|
|
|
| |
|
| |
|
| |
|
|
Net Loss Attributable to Noble Energy Common Shareholders per Share | | | | | | | | | | |
Basic and Diluted | $ | (8.27 | ) | | $ | (0.65 | ) | $ | (0.85 | ) | | $ | (0.02 | ) | | $ | (9.11 | ) | | $ | (0.68 | ) |
Weighted Average Number of Common Shares Outstanding | | | | | | | | | | |
Basic and Diluted | 479 |
| | 478 |
| 479 |
| | 478 |
| | 480 |
| | 478 |
|
The accompanying notes are an integral part of these consolidated financial statements.
Noble Energy, Inc.
Consolidated Balance Sheets
(millions)
(unaudited)
| | | March 31, 2020 | | December 31, 2019 | June 30, 2020 | | December 31, 2019 |
ASSETS | | | | | | |
Current Assets | | | | | | |
Cash and Cash Equivalents | $ | 1,397 |
| | $ | 484 |
| $ | 324 |
| | $ | 484 |
|
Accounts Receivable, Net | 562 |
| | 730 |
| 465 |
| | 730 |
|
Other Current Assets | 353 |
| | 148 |
| 214 |
| | 148 |
|
Total Current Assets | 2,312 |
| | 1,362 |
| 1,003 |
| | 1,362 |
|
Property, Plant and Equipment | |
| | |
| |
| | |
|
Oil and Gas Properties (Successful Efforts Method of Accounting) | 30,824 |
| | 30,404 |
| 30,941 |
| | 30,404 |
|
Property, Plant and Equipment, Other | 1,087 |
| | 1,083 |
| 1,089 |
| | 1,083 |
|
Total Property, Plant and Equipment, Gross | 31,911 |
| | 31,487 |
| 32,030 |
| | 31,487 |
|
Accumulated Depreciation, Depletion and Amortization | (18,690 | ) | | (14,036 | ) | (19,044 | ) | | (14,036 | ) |
Total Property, Plant and Equipment, Net | 13,221 |
| | 17,451 |
| 12,986 |
| | 17,451 |
|
Other Noncurrent Assets | 1,925 |
| | 1,834 |
| 1,910 |
| | 1,834 |
|
Total Assets | $ | 17,458 |
| | $ | 20,647 |
| $ | 15,899 |
| | $ | 20,647 |
|
LIABILITIES, MEZZANINE EQUITY AND SHAREHOLDERS' EQUITY | | | | | | |
Current Liabilities | | | |
| | | |
|
Accounts Payable – Trade | $ | 1,099 |
| | $ | 1,250 |
| $ | 676 |
| | $ | 1,250 |
|
Other Current Liabilities | 651 |
| | 719 |
| 706 |
| | 719 |
|
Total Current Liabilities | 1,750 |
| | 1,969 |
| 1,382 |
| | 1,969 |
|
Long-Term Debt | 8,632 |
| | 7,477 |
| 7,936 |
| | 7,477 |
|
Deferred Income Taxes | 615 |
| | 662 |
| 518 |
| | 662 |
|
Other Noncurrent Liabilities | 1,306 |
| | 1,378 |
| 1,288 |
| | 1,378 |
|
Total Liabilities | 12,303 |
| | 11,486 |
| 11,124 |
| | 11,486 |
|
Commitments and Contingencies |
| |
|
|
| |
|
|
Mezzanine Equity | | | | | | |
Redeemable Noncontrolling Interest, Net | 109 |
| | 106 |
| 113 |
| | 106 |
|
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; 524 Million and 522 Million Shares Issued, respectively | 5 |
| | 5 |
| 5 |
| | 5 |
|
Additional Paid in Capital | 8,942 |
| | 8,927 |
| 8,966 |
| | 8,927 |
|
Accumulated Other Comprehensive Loss | (30 | ) | | (31 | ) | (29 | ) | | (31 | ) |
Treasury Stock, at Cost; 39 Million Shares | (740 | ) | | (732 | ) | (741 | ) | | (732 | ) |
(Accumulated Deficit) Retained Earnings | (3,780 | ) | | 241 |
| (4,198 | ) | | 241 |
|
Noble Energy Share of Equity | 4,397 |
| | 8,410 |
| 4,003 |
| | 8,410 |
|
Noncontrolling Interests | 649 |
| | 645 |
| 659 |
| | 645 |
|
Total Shareholders' Equity | 5,046 |
| | 9,055 |
| 4,662 |
| | 9,055 |
|
Total Liabilities, Mezzanine Equity and Shareholders' Equity | $ | 17,458 |
| | $ | 20,647 |
| $ | 15,899 |
| | $ | 20,647 |
|
The accompanying notes are an integral part of these consolidated financial statements.
Noble Energy, Inc.
Consolidated Statements of Cash Flows
(millions)
(unaudited)
| | | Three Months Ended March 31, | Six Months Ended June 30, |
| 2020 | | 2019 | 2020 | | 2019 |
Cash Flows From Operating Activities | | | | | | |
Net Loss Including Noncontrolling Interests | $ | (4,007 | ) | | $ | (289 | ) | $ | (4,394 | ) | | $ | (281 | ) |
Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities | | | | | | |
Leasehold Impairment | 1,485 |
| | — |
| 1,488 |
| | — |
|
Depreciation, Depletion and Amortization | 492 |
| | 508 |
| 812 |
| | 1,036 |
|
Deferred Income Tax Benefit | (48 | ) | | (100 | ) | (144 | ) | | (101 | ) |
(Gain) Loss on Commodity Derivative Instruments | (389 | ) | | 212 |
| (231 | ) | | 152 |
|
Net Cash Received in Settlement of Commodity Derivative Instruments | 208 |
| | 14 |
| 314 |
| | 15 |
|
Asset Impairments | 2,703 |
| | — |
| 2,754 |
| | — |
|
Goodwill Impairment | 110 |
| | — |
| 110 |
| | — |
|
Finance Lease Impairment | | 40 |
| | — |
|
Firm Transportation Exit Cost | — |
| | 92 |
| — |
| | 92 |
|
Other Adjustments for Noncash Items Included in Income | 82 |
| | 28 |
| 108 |
| | 59 |
|
Changes in Operating Assets and Liabilities | | | | | | |
Decrease in Accounts Receivable | 90 |
| | 9 |
| 158 |
| | 35 |
|
(Decrease) Increase in Accounts Payable | (48 | ) | | 106 |
| (296 | ) | | 126 |
|
Increase in Partner Advances | | — |
| | 132 |
|
Other Current Assets and Liabilities, Net | (122 | ) | | (7 | ) | (225 | ) | | (108 | ) |
Other Operating Assets and Liabilities, Net | (74 | ) | | (45 | ) | (94 | ) | | (65 | ) |
Net Cash Provided by Operating Activities | 482 |
|
| 528 |
| 400 |
| | 1,092 |
|
Cash Flows From Investing Activities | | | | | | |
Additions to Property, Plant and Equipment | (479 | ) | | (763 | ) | (724 | ) | | (1,405 | ) |
Additions to Equity Method Investments | (226 | ) | | (271 | ) | (228 | ) | | (415 | ) |
Proceeds from Divestitures, Net | 17 |
| | 123 |
| 18 |
| | 123 |
|
Other | (8 | ) | | — |
| (31 | ) | | — |
|
Net Cash Used in Investing Activities | (696 | ) |
| (911 | ) | (965 | ) | | (1,697 | ) |
Cash Flows From Financing Activities | | | | | | |
Proceeds from Revolving Credit Facility | 1,120 |
| | 50 |
| 1,300 |
| | 50 |
|
Repayment of Revolving Credit Facility | (120 | ) | | (50 | ) | (975 | ) | | (50 | ) |
Proceeds from Noble Midstream Services Revolving Credit Facility | 260 |
| | 345 |
| 350 |
| | 560 |
|
Repayment of Noble Midstream Services Revolving Credit Facility | (105 | ) | | (175 | ) | (210 | ) | | (250 | ) |
Proceeds from Commercial Paper Borrowings, Net | | — |
| | 240 |
|
Dividends Paid, Common Stock | (58 | ) | | (53 | ) | (68 | ) | | (111 | ) |
Contributions from Noncontrolling Interest Owners | 78 |
| | 10 |
| 81 |
| | 21 |
|
Proceeds from Issuance of Mezzanine Equity, Net of Offering Costs | — |
| | 99 |
| — |
| | 99 |
|
Other | (48 | ) | | (32 | ) | (73 | ) | | (71 | ) |
Net Cash Provided by Financing Activities | 1,127 |
|
| 194 |
| 405 |
| | 488 |
|
Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash | 913 |
|
| (189 | ) | |
Decrease in Cash, Cash Equivalents, and Restricted Cash | | (160 | ) |
| (117 | ) |
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | 484 |
| | 719 |
| 484 |
| | 719 |
|
Cash, Cash Equivalents, and Restricted Cash at End of Period | $ | 1,397 |
| | $ | 530 |
| $ | 324 |
| | $ | 602 |
|
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 | | | | | Attributable to Noble Energy | | | | |
| Common Stock | | Additional Paid in Capital | | Accumulated Other Comprehensive Loss | | Treasury Stock at Cost | | (Accumulated Deficit) Retained Earnings | | Non-controlling Interests | | Total Equity | Common Stock | | Additional Paid in Capital | | Accumulated Other Comprehensive Loss | | Treasury Stock at Cost | | (Accumulated Deficit) Retained Earnings | | Non-controlling Interests | | Total Equity |
December 31, 2019 | $ | 5 |
| | $ | 8,927 |
| | $ | (31 | ) | | $ | (732 | ) | | $ | 241 |
| | $ | 645 |
| | $ | 9,055 |
| $ | 5 |
| | $ | 8,927 |
| | $ | (31 | ) | | $ | (732 | ) | | $ | 241 |
| | $ | 645 |
| | $ | 9,055 |
|
Net Loss | — |
| | — |
| | — |
| | — |
| | (3,963 | ) | | (44 | ) | | (4,007 | ) | — |
| | — |
| | — |
| | — |
| | (3,963 | ) | | (44 | ) | | (4,007 | ) |
Stock-based Compensation | — |
| | 17 |
| | — |
| | — |
| | — |
| | — |
| | 17 |
| — |
| | 17 |
| | — |
| | — |
| | — |
| | — |
| | 17 |
|
Dividends (12 cents per share) | — |
| | — |
| | — |
| | — |
| | (58 | ) | | — |
| | (58 | ) | — |
| | — |
| | — |
| | — |
| | (58 | ) | | — |
| | (58 | ) |
Distributions to Noncontrolling Interest Owners | — |
| | — |
| | — |
| | — |
| | — |
| | (29 | ) | | (29 | ) | — |
| | — |
| | — |
| | — |
| | — |
| | (29 | ) | | (29 | ) |
Contributions from Noncontrolling Interest Owners | — |
| | — |
| | — |
| | — |
| | — |
| | 78 |
| | 78 |
| — |
| | — |
| | — |
| | — |
| | — |
| | 78 |
| | 78 |
|
Other | — |
| | (2 | ) | | 1 |
| | (8 | ) | | — |
| | (1 | ) | | (10 | ) | — |
| | (2 | ) | | 1 |
| | (8 | ) | | — |
| | (1 | ) | | (10 | ) |
March 31, 2020 | $ | 5 |
| | $ | 8,942 |
| | $ | (30 | ) | | $ | (740 | ) | | $ | (3,780 | ) | | $ | 649 |
| | $ | 5,046 |
| $ | 5 |
| | $ | 8,942 |
| | $ | (30 | ) | | $ | (740 | ) | | $ | (3,780 | ) | | $ | 649 |
| | $ | 5,046 |
|
Net (Loss) Income | | — |
| | — |
| | — |
| | — |
| | (408 | ) | | 21 |
| | (387 | ) |
Stock-based Compensation | | — |
| | 26 |
| | — |
| | — |
| | — |
| | — |
| | 26 |
|
Dividends (2 cents per share) | | — |
| | — |
| | — |
| | — |
| | (10 | ) | | — |
| | (10 | ) |
Distributions to Noncontrolling Interest Owners | | — |
| | — |
| | — |
| | — |
| | — |
| | (14 | ) | | (14 | ) |
Contributions from Noncontrolling Interest Owners | | — |
| | — |
| | — |
| | — |
| | — |
| | 3 |
| | 3 |
|
Other | | — |
| | (2 | ) | | 1 |
| | (1 | ) | | — |
| | — |
| | (2 | ) |
June 30, 2020 | | $ | 5 |
| | $ | 8,966 |
| | $ | (29 | ) | | $ | (741 | ) | | $ | (4,198 | ) | | $ | 659 |
| | $ | 4,662 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
December 31, 2018 | $ | 5 |
| | $ | 8,203 |
| | $ | (32 | ) | | $ | (730 | ) | | $ | 1,980 |
| | $ | 1,058 |
| | $ | 10,484 |
| $ | 5 |
| | $ | 8,203 |
| | $ | (32 | ) | | $ | (730 | ) | | $ | 1,980 |
| | $ | 1,058 |
| | $ | 10,484 |
|
Net (Loss) Income | — |
| | — |
| | — |
| | — |
| | (313 | ) | | 24 |
| | (289 | ) | — |
| | — |
| | — |
| | — |
| | (313 | ) | | 24 |
| | (289 | ) |
Stock-based Compensation | — |
| | 14 |
| | — |
| | — |
| | — |
| | — |
| | 14 |
| — |
| | 14 |
| | — |
| | — |
| | — |
| | — |
| | 14 |
|
Dividends (11 cents per share) | — |
| | — |
| | — |
| | — |
| | (53 | ) | | — |
| | (53 | ) | — |
| | — |
| | — |
| | — |
| | (53 | ) | | — |
| | (53 | ) |
Distributions to Noncontrolling Interest Owners | — |
| | — |
| | — |
| | — |
| | — |
| | (17 | ) | | (17 | ) | — |
| | — |
| | — |
| | — |
| | — |
| | (17 | ) | | (17 | ) |
Contributions from Noncontrolling Interest Owners | — |
| | — |
| | — |
| | — |
| | — |
| | 10 |
| | 10 |
| — |
| | — |
| | — |
| | — |
| | — |
| | 10 |
| | 10 |
|
Other | — |
| | 2 |
| | — |
| | (5 | ) | | — |
| | (3 | ) | | (6 | ) | — |
| | 2 |
| | — |
| | (5 | ) | | — |
| | (3 | ) | | (6 | ) |
March 31, 2019 | $ | 5 |
| | $ | 8,219 |
| | $ | (32 | ) | | $ | (735 | ) | | $ | 1,614 |
| | $ | 1,072 |
| | $ | 10,143 |
| $ | 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 |
|
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; 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.
Chevron Merger On July 20, 2020, we entered into a definitive merger agreement (the Chevron Merger Agreement) with Chevron Corporation (NYSE: CVX) pursuant to which, and subject to the conditions of the agreement, all outstanding shares of Noble Energy will be acquired by Chevron in an all-stock transaction valued at $13 billion, including debt, or $10.38 per share. Under the terms of the agreement, Noble Energy shareholders will receive 0.1191 shares of Chevron common stock for each Noble Energy share. The transaction was approved by the Boards of Directors of both companies and is anticipated to close in fourth quarter 2020. The transaction is subject to Noble Energy stockholder approval, regulatory approvals, and other customary closing conditions. See Item 1A. Risk Factors for a discussion of risks related to the Chevron Merger. 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 March 31,June 30, 2020 and December 31, 2019 and for the three and six months ended March 31,June 30, 2020 and 2019 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 six months ended March 31,June 30, 2020 are not necessarily indicative of the results that may be expected for the year ending December 31, 2020.
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, 2019.
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). Noble Energy has determined that the partners with equity at risk in Noble Midstream Partners lack the authority, through voting rights or similar rights, to direct the activities that most significantly impact Noble Midstream Partners' economic performance; therefore, Noble Midstream Partners is considered a variable interest entity. Through Noble Energy's ownership interest in Noble Midstream GP LLC (the General Partner to Noble Midstream Partners), Noble Energy has the authority to direct the activities that most significantly affect economic performance and the obligation to absorb losses or the right to receive benefits that could be potentially significant to Noble Midstream Partners. Therefore, Noble Energy is considered the primary beneficiary and consolidates Noble Midstream Partners.
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. Amounts recorded within equity method investments, including contributions, include capitalized interest when the primary asset is under construction.
All significant intercompany balances and transactions have been eliminated upon consolidation.
Noncontrolling Interests Our consolidated financial statements include both noncontrolling interests and a redeemable noncontrolling interest. The noncontrolling interests represent the public's ownership in Noble Midstream Partners and third-party ownership in Noble Midstream Partners' consolidated non-wholly owned subsidiaries. Net loss attributable to noncontrolling interests for the threesix months ended March 31,June 30, 2020 includes goodwill impairment expense of $72 million based upon third party ownership interests in the underlying asset. See Note 4. Impairments. The redeemable noncontrolling interest represents perpetual preferred equity with a 6.5% annual dividend rate. Noble Midstream Partners may redeem the preferred equity in whole or in part at any time for cash at a predetermined redemption price. The preferred equity partner can request redemption at a pre-determined base return on or after March 25, 2025.
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
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
reporting period. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment.
The current commodity price, supply and demand environment coupled with the COVID-19 pandemic contributed significanthave increased uncertainty related to our estimates this quarter.for the six months ended June 30, 2020. Actual results could differ significantly from those estimates.
Impairments We performed a review for impairment indicators related to our proved and unproved properties on a field-by-field basis as of June 30, 2020, concluding there were no indicators of impairment. Assumptions utilized within this review were consistent with those utilized in first quarter 2020, as outlined further below.
Additionally, we performed impairment assessments over other long-lived assets, including property, plant and equipment, equity method investments, right-of-use assets and intangible assets. No impairment indicators were identified with the exception of certain capitalized exploratory well costs, as discussed below.
We reviewed capitalized exploratory well costs to determine whether facts and circumstances support continued capitalization of such costs. These considerations included management's long-range plans, whether sufficient progress has been made in assessing reserves, and whether each project remains economically and operationally viable. During second quarter 2020, we recognized asset impairment expense related to the Felicita project, Block O, offshore Equatorial Guinea. See Note 4. Impairments and Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
During first quarter 2020, we identified certain impairment indicators including the recent significant decrease in commodity prices as a result ofresulting from the COVID-19 pandemic, loweringwhich lowered demand for our products, as well as the supply response from the Organization of Petroleum Exporting Countries (OPEC) and non-OPEC producers,producers. Collectively, these factors which have caused us to
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
change our development plans.plans in first quarter 2020. Due to these impairment indicators, we conducted impairment testing of certain of our assets as of March 31, 2020, as follows:
Proved Properties
| |
• | Asset Recovery Test We conducted asset recovery testing of our proved properties on a field-by-field basis, inclusive of associated Midstream assets. For each field, we developed estimates of future undiscounted cash flows expected in connection with the property and compared these estimates to the carrying amount of the property. Assumptions used in these estimates includeincluded expectations for future commodity prices, development and capital spending plans, reservoir performance and production. Additionally, these estimates includeincluded certain asset specific assumptions, such as the political and regulatory impacts on future development activity, exploration plans, our geologists' evaluation of the property and the remaining lease term of the property. An impairment iswas indicated if, as a result of the assessment, an asset's carrying value exceeds its future net undiscounted cash flows. |
In preparing and reviewing assumptions used in the recovery test, we reassessed our historical methodology and rationale of inputs given the current industry and global environment. We concluded that our historical methodology and inputs were reasonable with the exception of estimating future commodity prices.
Historically, management has relied on future undiscounted net cash flows which included five-year strip prices for crude oil and natural gas, with prices subsequent to the fifth year held constant, unless contractual arrangements designated the price to be used. This pricing methodology has been similar to pricing assumptions used in creating management's long-range plans for asset development and capital allocation decisions. However, during first quarter 2020, forward five-year strip prices experienced considerable volatility and limited liquidity in the outer years of the forward strip. As such, we concluded that estimating future commodity prices using only five-year strip pricing would not be representative of expected market prices for certain of the years within our undiscounted cash flow models.
As such, absent contractual arrangements designating the price to be used, we aligned our future commodity price estimates used in the recovery test with those utilized in our updated long-range plans for asset development and capital allocation. This pricing reflects our analysis of market supply and demand considerations and industry cost of supply curve.
Except for our Delaware Basin proved properties, we determined that the carrying amount of each field was recoverable.
| |
• | Fair Value Determination We estimated the fair value of our Delaware Basin proved properties using a number of fair value inputs, which are Level 3 on the fair value hierarchy. We utilized a discounted cash flow model, estimating future net cash flows based on our expectations of future crude oil and natural gas production, commodity prices, and operating and development costs and discounted the cash flows using a weighted average cost of capital. |
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
As a result of the fair value determination, we concluded that the carrying amount of our Delaware Basin proved properties was impaired and recognized impairment expense for the excess of the carrying value above the fair value of the properties. See Note 4. Impairments. Unproved Properties Our unproved properties consist of leasehold costs and value allocated to probable and possible reserves resulting from acquisitions. During thefirst quarter 2020, we assessed our unproved properties for impairment by considering numerous factors including, but not limited to, current development plans, favorable or unfavorable exploration activity on the property being evaluated and/or adjacent properties, our geologists' evaluation of the property, and the remaining months in the lease term for the property.
We determined that the carrying values relating to both our Delaware Basin and Eagle Ford Shale unproved properties were impaired and recognized exploration expense. See Note 4. Impairments. Other Property, Plant & Equipment Other property includes lease right-of-use assets such as compressors and buildings, leasehold improvements, automobiles, trucks and other fixed assets. During thefirst quarter 2020, we identified certain impairment indicators with regards to a corporate real estate finance lease. We performed an impairment assessment which indicated the right-of-use asset's carrying value exceeded its future net undiscounted cash flows. As such, in first quarter 2020 we estimated the fair value of the asset, recognizing impairment expense for the excess of the carrying value above the fair value of the right-of-use asset. See Note 4. Impairments. Equity Method Investments We consider our equity method investments to be essential components of our business and necessary and integral elements of our value chain in support of our upstream operations. We considered whether any facts or circumstances suggested that our equity method investments were impaired on an other-than-temporary basis and concluded that the carrying values of our equity method investments were not impaired.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
Goodwill Noble Midstream Partners recorded goodwill upon the acquisition of Saddle Butte Rockies Midstream, LLC and affiliates (collectively Saddle Butte and subsequently renamed Black Diamond). The currentIn first quarter 2020, the commodity price environment and decrease incoupled with decreased market capitalization were indicators that the goodwill may be impaired. Noble Midstream Partners performed a qualitative assessment, concluding it was more likely than not that the fair value of the reporting unit was less than its carrying value. As a result, Noble Midstream Partners then performed a fair value assessment takingwhich took into account changes in customer development plans. Based on these assessments, Noble Midstream Partners concluded that the goodwill was fully impaired.impaired and recorded goodwill impairment expense in first quarter 2020. See Note 4. Impairments. Deferred Taxes We record valuation allowances to reduce deferred tax assets if it is more likely than not that some portion or all of the deferred tax assets will not be realized. In first quarter 2020, we changed our US onshore development plans in response to significant decreases in commodity prices, excess supply and lower demand for commodities resulting from the COVID-19 pandemic, as well as expected slower global economic growth. Additionally, in first quarter 2020 we recorded an impairmentimpairments to our Delaware Basin proved and unproved properties and to our Eagle Ford Shale unproved properties. Together,Collectively, these factors suggest thatsuggested it iswas more likely than not that our forecasted domestic net deferred tax asset willwould not be realized.realized and as such, we recorded a valuation allowance in first quarter 2020. See Note 10. Income Taxes. 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. We routinely monitor the credit worthiness of our purchasers. While we maintain credit insurance associated with certain purchasers, we do not carry credit insurance for all purchasers.
In Israel, certain of our Tamar and Leviathanthe Eastern Mediterranean, we sell natural gas under natural gas sales and purchase agreements (GSPAs) to customers in Israel, Egypt, and Jordan. The majority of these contracts include total contracted quantities for which we will deliver volumes to customers over the life of the agreements. As of June 30, 2020, a total of approximately 9.5 Tcf, gross (2.6 Tcf, net), of natural gas remained to be delivered under these contracts. Based on current production levels, our available quantities of proved reserves are more than sufficient to meet delivery commitments associated with these sales agreements with minimal additional capital investment.
Certain of our Tamar and Leviathan GSPAs have fixed minimum sales volumesbuyer-minimum take or pay volume-obligations and fixed base pricing with annual index escalations. Additionally, certain ofprices subject to minimum-price floor supports. In addition, our Egyptian export contracts include provisions which trigger adjustments to either decrease, or increase, fixed minimum salestake or pay volumes in the event the arithmetic average of daily Brent crude oil prices fallfalls below, or rises above, $50 per barrel for certain periods of time.
Our GSPAs do not preclude us from selling natural gas to customers, at amounts which exceed fixed minimum sales volumes. Estimated future net revenues related to remaining performance obligations subject to minimum sales volumes and base pricing as of June 30, 2020 were as follows as of March 31, 2020:follows: | | (millions) | Remainder of 2020 | | 2021 | | 2022 | | 2023 | | 2024 | | Thereafter | | Total | Remainder of 2020 | | 2021 | | 2022 | | 2023 | | 2024 | | Thereafter | | Total |
Natural Gas Revenues (1) | $ | 407 |
| | $ | 599 |
| | $ | 418 |
| | $ | 412 |
| | $ | 412 |
| | $ | 3,695 |
| | $ | 5,943 |
| $ | 298 |
| | $ | 553 |
| | $ | 546 |
| | $ | 550 |
| | $ | 552 |
| | $ | 5,192 |
| | $ | 7,691 |
|
| |
(1)Noble Energy, Inc. Notes to Consolidated Financial Statements (Unaudited)
Our actual future natural gas sales volumes may exceed future minimum volume commitments. Additionally, future natural gas revenues will vary due to variable consideration exceeding the contractual minimum volume or floor price provision. For example, estimates related to our Egyptian export contracts included in the table above calculate minimum fixed volume commitments assuming the arithmetic average of daily Brent crude oil prices are less than $50 per barrel for the remainder of the contract terms, which extend into 2035. In addition, these Egyptian export contracts include increases in minimum volume commitments up to 650 MMcf/d, gross, by mid-2022 once certain conditions precedent are satisfied. As of June 30, 2020, the table above reflects the increase in contractual minimum volumes to 450 MMcf/d, gross, from the Tamar and Leviathan fields. Actual results could differ significantly from these estimates. | Our actual future natural gas sales volumes may exceed future minimum volume commitments. Additionally, future natural gas revenues will vary due to variable consideration exceeding the contractual minimum volume or floor price provision. For example, estimates related to our Egyptian export contracts included in the table above calculate minimum fixed volume commitments assuming the arithmetic average of daily Brent crude oil prices are less than $50 per barrel for the remainder of the contract terms, which extend into 2035. Actual results could differ significantly from these estimates. |
Recently Issued Accounting Standards
London Interbank Offered Rate (LIBOR) Reform In first quarter 2020, the FASB issued ASU No. 2020-04 (ASU 2020-04): Reference Rate Reform (Topic 848), which provides optional guidance for a limited period of time to ease the transition from LIBOR to an alternative reference rate. The ASU intends to address certain concerns relating to accounting for contract modifications and hedge accounting. These optional expedients and exceptions to applying GAAP, assuming certain criteria are met, are allowed through December 31, 2022. We are currently evaluating the provisions of ASU 2020-04 and have not yet determined whether we will elect the optional expedients. We do not expect the transition to an alternative rate to have a significant impact on our business, operations or liquidity.
Recently Adopted Accounting Standards
Clarifying Certain Accounting Standards Codification (ASC) Topics In first quarter 2020, the FASB issued ASU No. 2020-01: Investments - Equity Securities (Topic 321), Investments - Equity Method and Joint Ventures (Topic 323), and Derivatives and Hedging (Topic 815), to clarify the interactions between these Topics. The update provides clarifications for entities investing in equity securities accounted for under the ASC 321 measurement alternative and companies that hold certain non-derivative forward contracts and purchased options to acquire equity securities. ASU 2020-01 is effective for fiscal years beginning after December 15, 2020, with early adoption permitted. We early adopted this ASU in first quarter 2020. This adoption did not have a material impact on our financial statements.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
Statements of Operations Information Other statements of operations information is as follows: | | | Three Months Ended March 31, | Three Months Ended June 30, | | Six Months Ended June 30, |
(millions) | 2020 | | 2019 | 2020 | | 2019 | | 2020 | | 2019 |
Other Revenue | | | | |
| | |
| | | | |
(Loss) Income from Equity Method Investments and Other | $ | (24 | ) | | $ | 17 |
| |
Income (Loss) from Equity Method Investments and Other | | $ | 3 |
| | $ | 16 |
| | $ | (21 | ) | | $ | 33 |
|
Midstream Services Revenues – Third Party | 25 |
| | 24 |
| 26 |
| | 20 |
| | 51 |
| | 44 |
|
Total | $ | 1 |
| | $ | 41 |
| $ | 29 |
| | $ | 36 |
| | $ | 30 |
| | $ | 77 |
|
Production Expense | | | | |
| | |
| | | | |
Lease Operating Expense | $ | 138 |
| | $ | 151 |
| $ | 98 |
| | $ | 122 |
| | $ | 236 |
| | $ | 273 |
|
Production and Ad Valorem Taxes | 39 |
| | 49 |
| 24 |
| | 41 |
| | 63 |
| | 90 |
|
Gathering, Transportation and Processing Expense | 95 |
| | 102 |
| 89 |
| | 96 |
| | 184 |
| | 198 |
|
Other Royalty Expense | 4 |
| | 3 |
| 3 |
| | 1 |
| | 7 |
| | 4 |
|
Total | $ | 276 |
| | $ | 305 |
| $ | 214 |
| | $ | 260 |
| | $ | 490 |
| | $ | 565 |
|
Exploration Expense | | | | | | | | | | |
Leasehold Impairment (1) | $ | 1,485 |
| | $ | — |
| $ | 3 |
| | $ | — |
| | $ | 1,488 |
| | $ | — |
|
Seismic, Geological and Geophysical | 4 |
| | 5 |
| |
Staff Expense | 13 |
| | 12 |
| |
Other | 2 |
| | 7 |
| |
Seismic, Staffing Expense and Other | | 12 |
| | 33 |
| | 31 |
| | 57 |
|
Total | $ | 1,504 |
| | $ | 24 |
| $ | 15 |
| | $ | 33 |
| | $ | 1,519 |
| | $ | 57 |
|
Other Operating Expense, Net | | | | | | | | | | |
Finance Lease Right-of-Use Asset Impairment (2) | $ | 40 |
| | $ | — |
| $ | — |
| | $ | — |
| | $ | 40 |
| | $ | — |
|
Marketing Expense | | 10 |
| | 14 |
| | 19 |
| | 19 |
|
Firm Transportation Exit Cost | — |
| | 92 |
| — |
| | — |
| | — |
| | 92 |
|
Corporate Restructuring (3) | | 30 |
| | 1 |
| | 30 |
| | 1 |
|
Other, Net | 4 |
| | 25 |
| 33 |
| | 7 |
| | 28 |
| | 27 |
|
Total | $ | 44 |
| | $ | 117 |
| $ | 73 |
| | $ | 22 |
| | $ | 117 |
| | $ | 139 |
|
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
| |
(1) | See Note 4. Impairments and Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs. |
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
| |
(3) | Relates to cash severance, termination benefits and acceleration of stock-based compensation for workforce reduction. |
Balance Sheet Information Other balance sheet information is as follows:
| | (millions) | March 31, 2020 | | December 31, 2019 | June 30, 2020 | | December 31, 2019 |
Accounts Receivable, Net | | | | | | |
Commodity Sales | $ | 308 |
| | $ | 446 |
| $ | 270 |
| | $ | 446 |
|
Joint Interest Billings | 136 |
| | 164 |
| 115 |
| | 164 |
|
Other | 125 |
| | 128 |
| 88 |
| | 128 |
|
Current Expected Credit Losses | (7 | ) | | (8 | ) | (8 | ) | | (8 | ) |
Total | $ | 562 |
| | $ | 730 |
| $ | 465 |
| | $ | 730 |
|
Other Current Assets | |
| | |
| |
| | |
|
Commodity Derivative Assets | $ | 221 |
| | $ | 14 |
| $ | 61 |
| | $ | 14 |
|
Inventories, Materials and Supplies | 68 |
| | 59 |
| |
Inventory - Materials and Supplies | | 68 |
| | 59 |
|
Assets Held for Sale (1) | 1 |
| | 14 |
| 2 |
| | 14 |
|
Prepaid Expenses and Other Current Assets | 63 |
| | 61 |
| 83 |
| | 61 |
|
Total | $ | 353 |
| | $ | 148 |
| $ | 214 |
| | $ | 148 |
|
Other Noncurrent Assets | |
| | |
| |
| | |
|
Equity Method Investments | $ | 1,249 |
| | $ | 1,066 |
| $ | 1,246 |
| | $ | 1,066 |
|
Operating Lease Right-of-Use Assets, Net (2)(1) | 244 |
| | 227 |
| 225 |
| | 227 |
|
Customer-Related Intangible Assets, Net (3)(2) | 270 |
| | 278 |
| 262 |
| | 278 |
|
Goodwill (4)(3) | — |
| | 110 |
| — |
| | 110 |
|
Other Assets, Noncurrent | 162 |
| | 153 |
| 177 |
| | 153 |
|
Total | $ | 1,925 |
| | $ | 1,834 |
| $ | 1,910 |
| | $ | 1,834 |
|
Other Current Liabilities | |
| | |
| |
| | |
|
Production and Ad Valorem Taxes | $ | 113 |
| | $ | 118 |
| $ | 109 |
| | $ | 118 |
|
Commodity Derivative Liabilities | | 151 |
| | 36 |
|
Asset Retirement Obligations | 84 |
| | 84 |
| 89 |
| | 84 |
|
Interest Payable | 80 |
| | 74 |
| 59 |
| | 74 |
|
Operating Lease Liabilities | 95 |
| | 88 |
| 79 |
| | 88 |
|
Compensation and Benefits Payable | 25 |
| | 126 |
| 53 |
| | 126 |
|
Other Liabilities, Current | 254 |
| | 229 |
| 166 |
| | 193 |
|
Total | $ | 651 |
| | $ | 719 |
| $ | 706 |
| | $ | 719 |
|
Other Noncurrent Liabilities | |
| | |
| |
| | |
|
Deferred Compensation Liabilities | $ | 112 |
| | $ | 133 |
| $ | 121 |
| | $ | 133 |
|
Asset Retirement Obligations | 709 |
| | 730 |
| 732 |
| | 730 |
|
Operating Lease Liabilities | 172 |
| | 164 |
| 169 |
| | 164 |
|
Firm Transportation Exit Cost Accrual (5) | 114 |
| | 129 |
| |
Firm Transportation Exit Cost Accrual (4) | | 113 |
| | 129 |
|
Other Liabilities, Noncurrent | 199 |
| | 222 |
| 153 |
| | 222 |
|
Total | $ | 1,306 |
| | $ | 1,378 |
| $ | 1,288 |
| | $ | 1,378 |
|
| |
(1) | Assets held for sale at December 31, 2019 relate to the divestiture of non-core assets in Reeves County, Texas. The assets were reclassified to held and used during first quarter 2020. |
| |
(2)
| Amount at March 31, 2020Balance includes a five-year $28 million lease renewal executed in first quarter 2020 for a vessel offshore West Africa. |
| |
(3)(2)
| Intangible asset balancesBalances at March 31,June 30, 2020 and December 31, 2019 are net of accumulated amortization of $70$78 million and $62 million, respectively. |
| |
(5)(4)
| Represents the discounted present value of our remaining obligations to third parties for permanent assignments of capacity on pipelines in the Marcellus Shale. |
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
Reconciliation of Total Cash We define total cash as cash, cash equivalents and restricted cash. Carrying amounts approximate fair value due to the short-term nature. The following table provides a reconciliation of total cash: | | | Three Months Ended March 31, | Six Months Ended June 30, |
(millions) | 2020 | | 2019 | 2020 | | 2019 |
Cash and Cash Equivalents at Beginning of Period | $ | 484 |
| | $ | 716 |
| $ | 484 |
| | $ | 716 |
|
Restricted Cash at Beginning of Period | — |
| | 3 |
| — |
| | 3 |
|
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | $ | 484 |
| | $ | 719 |
| $ | 484 |
| | $ | 719 |
|
Cash and Cash Equivalents at End of Period | $ | 1,397 |
| | $ | 528 |
| $ | 324 |
| | $ | 470 |
|
Restricted Cash at End of Period | — |
| | 2 |
| — |
| | 132 |
|
Cash, Cash Equivalents, and Restricted Cash at End of Period | $ | 1,397 |
| | $ | 530 |
| $ | 324 |
| | $ | 602 |
|
Note 3. Segment Information
We have the following reportable segments: US onshore; Eastern Mediterranean (Israel, Egypt and Cyprus); West Africa (Equatorial Guinea, Cameroon and Gabon)Gabon until June 2020); Other International (Canada, Colombia and New Ventures); and Midstream. The Midstream segment includes the consolidated accounts of Noble Midstream Partners.
The geographical reportable segments (US onshore, Eastern Mediterranean, West Africa and Other International) 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, with current focus areas being the DJ and Delaware Basins. Expenses related to debt, such as interest and other debt-related costs, headquarters depreciation, corporate general and administrative expenses, exit costs, corporate restructurings, and certain costs associated with mitigating the effects of our retained Marcellus Shale transportation agreements, are recorded atin the Corporate level.reportable segment.
The chief operating decision maker analyzes (loss) 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.
| | | | | Oil and Gas Exploration and Production | | Midstream | | | | | 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 | Consolidated | | United States | | Eastern Mediter-ranean | | West Africa | | Other Int'l | | United States | | Intersegment Eliminations and Other(1) | | Corporate |
Three Months Ended March 31, 2020 | | | | | | | | | | | | | | | |
Three Months Ended June 30, 2020 | | Three Months Ended June 30, 2020 | | | | | | | | | | | | | | |
Crude Oil Sales | $ | 578 |
| | $ | 492 |
| | $ | 1 |
| | $ | 85 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | 261 |
| | $ | 230 |
| | $ | — |
| | $ | 31 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
NGL Sales | 62 |
| | 62 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| 40 |
| | 40 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Natural Gas Sales | 254 |
| | 60 |
| | 190 |
| | 4 |
| | — |
| | — |
| | — |
| | — |
| 192 |
| | 48 |
| | 139 |
| | 5 |
| | — |
| | — |
| | — |
| | — |
|
Total Crude Oil, NGL and Natural Gas Sales | 894 |
| | 614 |
| | 191 |
| | 89 |
| | — |
| | — |
| | — |
| | — |
| 493 |
| | 318 |
| | 139 |
| | 36 |
| | — |
| | — |
| | — |
| | — |
|
Sales of Purchased Oil and Gas | 125 |
| | 25 |
| | — |
| | — |
| | — |
| | 83 |
| | — |
| | 17 |
| 49 |
| | 4 |
| | — |
| | — |
| | — |
| | 29 |
| | — |
| | 16 |
|
Loss from Equity Method Investments and Other | (24 | ) | | — |
| | (2 | ) | | (17 | ) | | — |
| | (5 | ) | | — |
| | — |
| |
Income (Loss) from Equity Method Investments and Other | | 3 |
| | (1 | ) | | (1 | ) | | 8 |
| | — |
| | (3 | ) | | — |
| | — |
|
Midstream Services Revenues – Third Party | 25 |
| | — |
| | — |
| | — |
| | — |
| | 25 |
| | — |
| | — |
| 26 |
| | — |
| | — |
| | — |
| | — |
| | 26 |
| | — |
| | — |
|
Intersegment Revenues | — |
| | — |
| | — |
| | — |
| | — |
| | 115 |
| | (115 | ) | | — |
| — |
| | — |
| | — |
| | — |
| | — |
| | 92 |
| | (92 | ) | | — |
|
Total Revenues | 1,020 |
| | 639 |
| | 189 |
| | 72 |
| | — |
| | 218 |
| | (115 | ) | | 17 |
| 571 |
| | 321 |
| | 138 |
| | 44 |
| | — |
| | 144 |
| | (92 | ) | | 16 |
|
Lease Operating Expense | 138 |
| | 108 |
| | 13 |
| | 30 |
| | — |
| | 1 |
| | (14 | ) | | — |
| 98 |
| | 81 |
| | 15 |
| | 20 |
| | — |
| | (1 | ) | | (17 | ) | | — |
|
Production and Ad Valorem Taxes | 39 |
| | 37 |
| | — |
| | — |
| | — |
| | 2 |
| | — |
| | — |
| 24 |
| | 23 |
| | — |
| | — |
| | — |
| | 1 |
| | — |
| | — |
|
Gathering, Transportation and Processing Expense | 95 |
| | 146 |
| | 3 |
| | — |
| | — |
| | 21 |
| | (75 | ) | | — |
| 89 |
| | 133 |
| | 3 |
| | — |
| | — |
| | 20 |
| | (67 | ) | | — |
|
Other Royalty Expense | 4 |
| | 4 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| 3 |
| | 3 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total Production Expense | 276 |
| | 295 |
| | 16 |
| | 30 |
| | — |
| | 24 |
| | (89 | ) | | — |
| 214 |
| | 240 |
| | 18 |
| | 20 |
| | — |
| | 20 |
| | (84 | ) | | — |
|
Exploration Expense | 1,504 |
| | 1,494 |
| | 2 |
| | 3 |
| | 5 |
| | — |
| | — |
| | — |
| 15 |
| | 5 |
| | 2 |
| | 5 |
| | 3 |
| | — |
| | — |
| | — |
|
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
| | | | | Oil and Gas Exploration and Production | | Midstream | | | | | 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 | Consolidated | | United States | | Eastern Mediter-ranean | | West Africa | | Other Int'l | | United States | | Intersegment Eliminations and Other(1) | | Corporate |
Depreciation, Depletion and Amortization | 492 |
| | 419 |
| | 19 |
| | 24 |
| | — |
| | 26 |
| | (9 | ) | | 13 |
| 320 |
| | 252 |
| | 16 |
| | 22 |
| | — |
| | 26 |
| | (8 | ) | | 12 |
|
Cost of Purchased Oil and Gas | 139 |
| | 28 |
| | — |
| | — |
| | — |
| | 80 |
| | — |
| | 31 |
| 63 |
| | 4 |
| | — |
| | — |
| | — |
| | 29 |
| | — |
| | 30 |
|
Asset Impairments | 2,703 |
| | 2,703 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| 51 |
| | — |
| | — |
| | 51 |
| | — |
| | — |
| | — |
| | — |
|
Goodwill Impairment | 110 |
| | — |
| | — |
| | — |
| | — |
| | 110 |
| | — |
| | — |
| |
Gain on Commodity Derivative Instruments | (389 | ) | | (389 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
Loss on Commodity Derivative Instruments | | 158 |
| | 149 |
| | — |
| | 9 |
| | — |
| | — |
| | — |
| | — |
|
(Loss) Income Before Income Taxes | (4,018 | ) | | (3,917 | ) | | 145 |
| | 10 |
| | (6 | ) | | (31 | ) | | (11 | ) | | (208 | ) | (476 | ) | | (359 | ) | | 83 |
| | (69 | ) | | (6 | ) | | 58 |
| | 11 |
| | (194 | ) |
Additions to Long-Lived Assets, Excluding Acquisitions | 442 |
| | 357 |
| | 31 |
| | 19 |
| | 9 |
| | 43 |
| | (24 | ) | | 7 |
| 106 |
| | 65 |
| | 13 |
| | 19 |
| | 2 |
| | 5 |
| | (4 | ) | | 6 |
|
Additions to Equity Method Investments | 153 |
| | — |
| | — |
| | — |
| | — |
| | 153 |
| | — |
| | — |
| 3 |
| | — |
| | — |
| | — |
| | — |
| | 3 |
| | — |
| | — |
|
Three Months Ended March 31, 2019 | | | | | | | | | | | | | | | |
Three Months Ended June 30, 2019 | | Three Months Ended June 30, 2019 | | | | | | | | | | | | | | |
Crude Oil Sales | $ | 612 |
| | $ | 545 |
| | $ | 1 |
| | $ | 66 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | 688 |
| | $ | 617 |
| | $ | 2 |
| | $ | 69 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
NGL Sales | 96 |
| | 96 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| 84 |
| | 84 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Natural Gas Sales | 229 |
| | 108 |
| | 117 |
| | 4 |
| | — |
| | — |
| | — |
| | — |
| 182 |
| | 72 |
| | 105 |
| | 5 |
| | — |
| | — |
| | — |
| | — |
|
Total Crude Oil, NGL and Natural Gas Sales | 937 |
| | 749 |
| | 118 |
| | 70 |
| | — |
| | — |
| | — |
| | — |
| 954 |
| | 773 |
| | 107 |
| | 74 |
| | — |
| | — |
| | — |
| | — |
|
Sales of Purchased Oil and Gas | 74 |
| | 14 |
| | — |
| | — |
| | — |
| | 33 |
| | — |
| | 27 |
| 103 |
| | 28 |
| | — |
| | — |
| | — |
| | 52 |
| | — |
| | 23 |
|
Income from Equity Method Investments and Other | 17 |
| | — |
| | — |
| | 15 |
| | — |
| | 2 |
| | — |
| | — |
| |
Income (Loss) from Equity Method Investments and Other | | 16 |
| | 1 |
| | — |
| | 17 |
| | — |
| | (2 | ) | | — |
| | — |
|
Midstream Services Revenues – Third Party | 24 |
| | — |
| | — |
| | — |
| | — |
| | 24 |
| | — |
| | — |
| 20 |
| | — |
| | — |
| | — |
| | — |
| | 20 |
| | — |
| | — |
|
Intersegment Revenues | — |
| | — |
| | — |
| | — |
| | — |
| | 106 |
| | (106 | ) | | — |
| — |
| | — |
| | — |
| | — |
| | — |
| | 91 |
| | (91 | ) | | — |
|
Total Revenues | 1,052 |
| | 763 |
| | 118 |
| | 85 |
| | — |
| | 165 |
| | (106 | ) | | 27 |
| 1,093 |
| | 802 |
| | 107 |
| | 91 |
| | — |
| | 161 |
| | (91 | ) | | 23 |
|
Lease Operating Expense | 151 |
| | 125 |
| | 10 |
| | 24 |
| | — |
| | 1 |
| | (9 | ) | | — |
| 122 |
| | 114 |
| | 9 |
| | 10 |
| | — |
| | 1 |
| | (12 | ) | | — |
|
Production and Ad Valorem Taxes | 49 |
| | 47 |
| | — |
| | — |
| | — |
| | 2 |
| | — |
| | — |
| 41 |
| | 40 |
| | — |
| | — |
| | — |
| | 1 |
| | — |
| | — |
|
Gathering, Transportation and Processing Expense | 102 |
| | 142 |
| | — |
| | — |
| | — |
| | 29 |
| | (69 | ) | | — |
| 96 |
| | 124 |
| | — |
| | — |
| | — |
| | 31 |
| | (59 | ) | | — |
|
Other Royalty Expense | 3 |
| | 3 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| 1 |
| | 1 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total Production Expense | 305 |
| | 317 |
| | 10 |
| | 24 |
| | — |
| | 32 |
| | (78 | ) | | — |
| 260 |
| | 279 |
| | 9 |
| | 10 |
| | — |
| | 33 |
| | (71 | ) | | — |
|
Depreciation, Depletion and Amortization | 508 |
| | 439 |
| | 16 |
| | 20 |
| | — |
| | 25 |
| | (7 | ) | | 15 |
| 528 |
| | 457 |
| | 17 |
| | 19 |
| | — |
| | 26 |
| | (6 | ) | | 15 |
|
Cost of Purchased Oil and Gas | 87 |
| | 14 |
| | — |
| | — |
| | — |
| | 31 |
| | — |
| | 42 |
| 113 |
| | 28 |
| | — |
| | — |
| | — |
| | 48 |
| | — |
| | 37 |
|
Firm Transportation Exit Cost | 92 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 92 |
| |
Loss on Commodity Derivative Instruments | 212 |
| | 188 |
| | — |
| | 24 |
| | — |
| | — |
| | — |
| | — |
| |
(Loss) Income Before Income Taxes | (373 | ) | | (247 | ) | | 84 |
| | 11 |
| | (16 | ) | | 73 |
| | (14 | ) | | (264 | ) | |
Gain on Commodity Derivative Instruments | | (60 | ) | | (58 | ) | | — |
| | (2 | ) | | — |
| | — |
| | — |
| | — |
|
Income (Loss) Before Income Taxes | | 28 |
| | 70 |
| | 65 |
| | 59 |
| | (15 | ) | | 46 |
| | (15 | ) | | (182 | ) |
Additions to Long-Lived Assets, Excluding Acquisitions | 712 |
| | 511 |
| | 132 |
| | 5 |
| | 10 |
| | 66 |
| | (23 | ) | | 11 |
| 647 |
| | 478 |
| | 119 |
| | 12 |
| | 2 |
| | 52 |
| | (25 | ) | | 9 |
|
Additions to Equity Method Investments | 271 |
| | — |
| | — |
| | — |
| | — |
| | 271 |
| | — |
| | — |
| 144 |
| | — |
| | — |
| | — |
| | — |
| | 144 |
| | — |
| | — |
|
March 31, 2020 | |
| | |
| | |
| | |
| | | | | | | | |
| |
Property, Plant and Equipment, Net | $ | 13,221 |
| | $ | 7,641 |
| | $ | 3,055 |
| | $ | 792 |
| | $ | 53 |
| | $ | 1,734 |
| | $ | (225 | ) | | $ | 171 |
| |
Six Months Ended June 30, 2020 | | Six Months Ended June 30, 2020 | | | | | | | | | | | | | | |
Crude Oil Sales | | $ | 839 |
| | $ | 722 |
| | $ | 1 |
| | $ | 116 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
NGL Sales | | 102 |
| | 102 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Natural Gas Sales | | 446 |
| | 108 |
| | 329 |
| | 9 |
| | — |
| | — |
| | — |
| | — |
|
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 |
December 31, 2019 | | | |
| | |
| | |
| | | | | | | | |
|
Property, Plant and Equipment, Net | $ | 17,451 |
| | $ | 11,859 |
| | $ | 3,041 |
| | $ | 793 |
| | $ | 44 |
| | $ | 1,721 |
| | $ | (223 | ) | | $ | 216 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 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 |
Total Crude Oil, NGL and Natural Gas Sales | 1,387 |
| | 932 |
| | 330 |
| | 125 |
| | — |
| | — |
| | — |
| | — |
|
Sales of Purchased Oil and Gas | 174 |
| | 29 |
| | — |
| | — |
| | — |
| | 112 |
| | — |
| | 33 |
|
Loss from Equity Method Investments and Other | (21 | ) | | (1 | ) | | (3 | ) | | (9 | ) | | — |
| | (8 | ) | | — |
| | — |
|
Midstream Services Revenues – Third Party | 51 |
| | — |
| | — |
| | — |
| | — |
| | 51 |
| | — |
| | — |
|
Intersegment Revenues | — |
| | — |
| | — |
| | — |
| | — |
| | 207 |
| | (207 | ) | | — |
|
Total Revenues | 1,591 |
| | 960 |
| | 327 |
| | 116 |
| | — |
| | 362 |
| | (207 | ) | | 33 |
|
Lease Operating Expense | 236 |
| | 189 |
| | 28 |
| | 50 |
| | — |
| | — |
| | (31 | ) | | — |
|
Production and Ad Valorem Taxes | 63 |
| | 60 |
| | — |
| | — |
| | — |
| | 3 |
| | — |
| | — |
|
Gathering, Transportation and Processing Expense | 184 |
| | 279 |
| | 6 |
| | — |
| | — |
| | 41 |
| | (142 | ) | | — |
|
Other Royalty Expense | 7 |
| | 7 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total Production Expense | 490 |
| | 535 |
| | 34 |
| | 50 |
| | — |
| | 44 |
| | (173 | ) | | — |
|
Exploration Expense | 1,519 |
| | 1,499 |
| | 4 |
| | 8 |
| | 8 |
| | — |
| | — |
| | — |
|
Depreciation, Depletion and Amortization | 812 |
| | 671 |
| | 35 |
| | 46 |
| | — |
| | 52 |
| | (17 | ) | | 25 |
|
Cost of Purchased Oil and Gas | 202 |
| | 32 |
| | — |
| | — |
| | — |
| | 109 |
| | — |
| | 61 |
|
Asset Impairments | 2,754 |
| | 2,703 |
| | — |
| | 51 |
| | — |
| | — |
| | — |
| | — |
|
Goodwill Impairment | 110 |
| | — |
| | — |
| | — |
| | — |
| | 110 |
| | — |
| | — |
|
(Gain) Loss on Commodity Derivative Instruments | (231 | ) | | (240 | ) | | — |
| | 9 |
| | — |
| | — |
| | — |
| | — |
|
(Loss) Income Before Income Taxes | (4,494 | ) | | (4,276 | ) | | 228 |
| | (59 | ) | | (12 | ) | | 27 |
| | — |
| | (402 | ) |
Additions to Long-Lived Assets, Excluding Acquisitions | 548 |
| | 422 |
| | 44 |
| | 38 |
| | 11 |
| | 48 |
| | (28 | ) | | 13 |
|
Additions to Equity Method Investments | 155 |
| | — |
| | — |
| | — |
| | — |
| | 155 |
| | — |
| | — |
|
Six Months Ended June 30, 2019 | | | | | | | | | | | | | | |
Crude Oil Sales | $ | 1,300 |
| | $ | 1,162 |
| | $ | 3 |
| | $ | 135 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
NGL Sales | 180 |
| | 180 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Natural Gas Sales | 411 |
| | 180 |
| | 222 |
| | 9 |
| | — |
| | — |
| | — |
| | — |
|
Total Crude Oil, NGL and Natural Gas Sales | 1,891 |
| | 1,522 |
| | 225 |
| | 144 |
| | — |
| | — |
| | — |
| | — |
|
Sales of Purchased Oil and Gas | 177 |
| | 42 |
| | — |
| | — |
| | — |
| | 85 |
| | — |
| | 50 |
|
Income from Equity Method Investments and Other | 33 |
| | 1 |
| | — |
| | 32 |
| | — |
| | — |
| | — |
| | — |
|
Midstream Services Revenues – Third Party | 44 |
| | — |
| | — |
| | — |
| | — |
| | 44 |
| | — |
| | — |
|
Intersegment Revenues | — |
| | — |
| | — |
| | — |
| | — |
| | 197 |
| | (197 | ) | | — |
|
Total Revenues | 2,145 |
| | 1,565 |
| | 225 |
| | 176 |
| | — |
| | 326 |
| | (197 | ) | | 50 |
|
Lease Operating Expense | 273 |
| | 239 |
| | 19 |
| | 34 |
| | — |
| | 2 |
| | (21 | ) | | — |
|
Production and Ad Valorem Taxes | 90 |
| | 87 |
| | — |
| | — |
| | — |
| | 3 |
| | — |
| | — |
|
Gathering, Transportation and Processing Expense | 198 |
| | 266 |
| | — |
| | — |
| | — |
| | 60 |
| | (128 | ) | | — |
|
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 |
Other Royalty Expense | 4 |
| | 4 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total Production Expense | 565 |
| | 596 |
| | 19 |
| | 34 |
| | — |
| | 65 |
| | (149 | ) | | — |
|
Depreciation, Depletion and Amortization | 1,036 |
| | 896 |
| | 33 |
| | 39 |
| | — |
| | 51 |
| | (13 | ) | | 30 |
|
Cost of Purchased Oil and Gas | 200 |
| | 42 |
| | — |
| | — |
| | — |
| | 79 |
| | — |
| | 79 |
|
Firm Transportation Exit Cost | 92 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 92 |
|
Loss on Commodity Derivative Instruments | 152 |
| | 130 |
| | — |
| | 22 |
| | — |
| | — |
| | — |
| | — |
|
(Loss) Income Before Income Taxes | (345 | ) | | (177 | ) | | 149 |
| | 70 |
| | (31 | ) | | 119 |
| | (29 | ) | | (446 | ) |
Additions to Long-Lived Assets, Excluding Acquisitions | 1,359 |
| | 990 |
| | 251 |
| | 18 |
| | 12 |
| | 118 |
| | (48 | ) | | 18 |
|
Investments in Equity Method Investees | 415 |
| | — |
| | — |
| | — |
| | — |
| | 415 |
| | — |
| | — |
|
June 30, 2020 | |
| | |
| | |
| | |
| | | | | | | | |
|
Property, Plant and Equipment, Net | $ | 12,986 |
| | $ | 7,473 |
| | $ | 3,058 |
| | $ | 737 |
| | $ | 55 |
| | $ | 1,721 |
| | $ | (222 | ) | | $ | 164 |
|
December 31, 2019 | | | |
| | |
| | |
| | | | | | | | |
|
Property, Plant and Equipment, Net | $ | 17,451 |
| | $ | 11,859 |
| | $ | 3,041 |
| | $ | 793 |
| | $ | 44 |
| | $ | 1,721 |
| | $ | (223 | ) | | $ | 216 |
|
| |
(1) | Intersegment eliminations related to income (loss)loss before income taxes are the result of midstream expenditures. Certain of these expenditures 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. Other expenditures are presented as production expense. Intercompany revenues and expenses are eliminated upon consolidation. |
Note 4. Impairments
The effect of impairments on our consolidated statements of operations and comprehensive loss was as follows: |
| | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
(millions) | Statement of Operations Location | 2020 | | 2019 | | 2020 | | 2019 |
Asset Impairment Expense | | | | | | | | |
Proved Property Impairment - Delaware Basin | Asset Impairments | $ | — |
| | $ | — |
| | $ | 2,703 |
| | $ | — |
|
Capitalized Exploratory Well Costs - Felicita | Asset Impairments | 51 |
| | — |
| | 51 |
| | — |
|
Total Asset Impairment Expense | | $ | 51 |
| | $ | — |
| | $ | 2,754 |
| | $ | — |
|
Leasehold Impairment Expense | | | | | | | | |
Leasehold Impairment - Delaware Basin | Exploration Expense | $ | — |
| | $ | — |
| | $ | 1,385 |
| | $ | — |
|
Leasehold Impairment - Eagle Ford Shale | Exploration Expense | — |
| | — |
| | 100 |
| | — |
|
Leasehold Impairment - Gabon | Exploration Expense | 3 |
| | — |
| | 3 |
| | — |
|
Total Leasehold Impairment Expense | | $ | 3 |
| | $ | — |
| | $ | 1,488 |
| | $ | — |
|
| | | | | | | | |
Goodwill Impairment - Noble Midstream Partners | Goodwill Impairment | $ | — |
| | $ | — |
| | $ | 110 |
| | $ | — |
|
Finance Lease Right-of-Use Asset Impairment | Other Operating Expense, Net | — |
| | — |
| | 40 |
| | — |
|
Second Quarter 2020 Impairment
In second quarter 2020, we concluded that while our 2008 Felicita discovery, Block O, offshore West Africa was successful in locating hydrocarbons, it was not competitive with other assets in our portfolio being considered for future development. We fully impaired the asset based on management's decision not to move forward with development.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
First Quarter 2020 Impairments
We performed a number of impairment assessments during first quarter 2020.These2020. These assessments included using various valuation techniques and Level 3 inputs on the fair value hierarchy. See Note 2. Basis of Presentation. Information regarding impairments recorded in first quarter 2020 is as follows:
|
| | | | | | | | | | |
(millions) | | Statement of Operations Location | | Net Book Value (1) | | Pre-tax Impairment |
Proved Property Impairment - Delaware Basin | | Asset Impairments | | $ | 3,613 |
| | $ | 2,703 |
|
| | | | | | |
Leasehold Impairment - Delaware Basin | | Exploration Expense | | 1,915 |
| | 1,385 |
|
Leasehold Impairment - Eagle Ford Shale | | Exploration Expense | | 100 |
| | 100 |
|
Total Exploration Expense | | | | $ | 2,015 |
| | $ | 1,485 |
|
| | | | | | |
Goodwill Impairment - Noble Midstream Partners | | Goodwill Impairment | | $ | 110 |
| | $ | 110 |
|
Finance Lease Right-of-Use Asset Impairment | | Other Operating Expense, Net | | 88 |
| | 40 |
|
| |
(1)
| Represents net book value at the date of assessment prior to recording pre-tax impairment. |
Property Impairments In first quarter 2020, following our impairment analysis, we recorded impairment expense as follows:
| |
• | Delaware Basin Assets The fair values of our Delaware Basin assets were estimated using the income approach and resulted in fair values of approximately $910 million and $530 million associated with proved properties (inclusive of associated midstream assets) and unproved properties, respectively. WeAs of March 31, 2020, the carrying values of our Delaware Basin proved and unproved properties were $3.6 billion and $1.9 billion, respectively, and as such, we recognized total impairment expense of $4.1 billion for the excess of the carrying value above the fair value of the properties. |
| |
• | Eagle Ford Shale Unproved Properties After assessing future development scenarios and in contemplation of the current commodity and supply/demand environment, we determined that all $100 million of remaining unproved leasehold costs were impaired due to the likelihood of future drilling in certain zones in this area. |
Goodwill Impairment Noble Midstream Partners concluded the fair value of its Black Diamond reporting unit was less than its carrying value and therefore performed a fair value assessment. Based on the assessment, Noble Midstream Partners concluded that the entire carrying amount of goodwill was fully impaired and recorded goodwill impairment expense of $110 million.million in first quarter 2020. Of the $110 million of goodwill impairment expense included in our consolidated statements of operations, approximately $38 million is attributable to Noble Energy relating to our ownership interests in the Black Diamond entity, while the remainder of $72 million is attributable to noncontrolling interests.
Finance Lease Right-of-Use Asset Impairment During thefirst quarter 2020, we recognized $40 million of impairment expense for the excess of the carrying value above the fair value of the right-of-use asset relating to a corporate real estate lease. As of March 31, 2020, the associated carrying value was $88 million. The impairment which was recorded at the Corporate level, is the result of economic facts and circumstances and plans pertaining to the future use of the asset.
Notes to Consolidated Financial Statements (Unaudited)
Note 5. Acquisitions, Divestitures and Equity Method Investments
We maintain an ongoing portfolio management program and have engaged in various transactions over recent years.
2020 Transactions
Saddlehorn In February 2020, Black Diamond Gathering LLC (Black Diamond), in which Noble Midstream Partners owns a 54.4% interest, exercised its option to acquire a 20% ownership interest in Saddlehorn Pipeline Company, LLC (Saddlehorn) for $160 million ($87 million, net to Noble Midstream Partners). Saddlehorn owns a pipeline that transports crude oil and condensate from the DJ and Powder River Basins to storage facilities in Cushing, Oklahoma. Noble Midstream Partners consolidates Black Diamond and the Saddlehorn investment is accounted for using the equity method.
EPIC Pipelines 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 constructed the EPIC Y-Grade pipeline, and a 30% equity interest in EPIC Crude Holdings, which constructed the EPIC crude oil pipeline. The EPIC crude oil pipeline supports transportation of our production from the Delaware Basin to Corpus Christi, Texas. InFor the first quartersix months of 2020, Noble Midstream Partners made capital contributions to EPIC Y-Grade and EPIC Crude Holdings of $14 million and $33 million, respectively. EPIC Crude Holdings completedAs of April 1, 2020 the EPIC crude oil pipeline during first quarter 2020commenced full service. EPIC Y-Grade began the transition to full NGL service in May and the EPIC Y-grade pipeline is transitioning from interim crude service to Y-grade service. Y-grade service is expected to begincompleted construction of its new build fractionator in second quarterJune 2020.
Additionally, in December 2019, Noble Midstream Partners exercised and closed an option with EPIC to acquire an interest in EPIC Propane, which is constructing a propane pipeline that will run from Robstown, Texas to Sweeney, Texas, with additional connectivity to the Markham underground storage caverns. InFor the first quartersix months of 2020, Noble Midstream Partners made capital contributions to EPIC Propane of approximately $2$4 million.
Delaware Crossing Joint Venture In February 2019, Noble Midstream Partners executed definitive agreements with Salt Creek Midstream LLC (Salt Creek) to form a 50/50 joint venture, Delaware Crossing LLC (Delaware Crossing), in order to construct a 160 MBbl/d day crude oil pipeline system in the Delaware Basin.Basin, which began delivering crude oil into all connection points in April 2020. In the first quartersix months of 2020, Noble Midstream Partners made capital contributions to Delaware Crossing of $17 million.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
2019 Transactions
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 Pipelines In first quarter 2019, Noble Midstream Partners exercised and closed options with EPIC totaling $227 million. In second quarter 2019, Noble Midstream Partners contributed $28 million and $114 million to EPIC Y-Grade and EPIC Crude Holdings, respectively.
Delaware Crossing Joint Venture InDuring the first quartersix months of 2019, Noble Midstream Partners made capital contributions of $38$39 million to Delaware Crossing.
Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs
Capitalized Exploratory Well Costs There were no significant changes to ourChanges in capitalized exploratory well costs duringare as follows and exclude amounts that were capitalized and subsequently expensed in the period. same period:
|
| | | |
(millions) | Six Months Ended June 30, 2020 |
Capitalized Exploratory Well Costs, Beginning of Period | $ | 280 |
|
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves | 15 |
|
Capitalized Exploratory Well Costs Charged to Expense (1) | (51 | ) |
Capitalized Exploratory Well Costs, End of Period | $ | 244 |
|
| |
(1) | Relates to second quarter 2020 impairment of Felicita discovery, Block O, offshore Equatorial Guinea; see Note 2. Basis of Presentation and Note 4. Impairments. |
The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced: | | (millions, except number of projects) | March 31, 2020 | | December 31, 2019 | June 30, 2020 | | December 31, 2019 |
Exploratory Well Costs Capitalized for a Period of One Year or Less | $ | 30 |
| | $ | 22 |
| $ | 30 |
| | $ | 22 |
|
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 261 |
| | 258 |
| 214 |
| | 258 |
|
Capitalized Exploratory Well Costs, End of Period | $ | 291 |
| | $ | 280 |
| $ | 244 |
| | $ | 280 |
|
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 5 |
| | 5 |
| 4 |
| | 5 |
|
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
Undeveloped Leasehold Costs Changes in undeveloped leasehold costs are as follows: | | (millions) | Three Months Ended March 31, 2020 | Six Months Ended June 30, 2020 |
Undeveloped Leasehold Costs, Beginning of Period | $ | 2,152 |
| $ | 2,152 |
|
Additions to Undeveloped Leasehold Costs | 2 |
| 2 |
|
Impairment (1) | (1,485 | ) | (1,488 | ) |
Other | (2 | ) | (2 | ) |
Undeveloped Leasehold Costs, End of Period | $ | 667 |
| $ | 664 |
|
| |
(1) | Relates toIncludes first quarter 2020 impairments of undeveloped leasehold costs for unproved properties in the Delaware Basin and Eagle Ford Shale.Shale of $1.5 billion collectively and $3 million related to our decision not to pursue lease renewal of undeveloped acreage in Gabon. See Note 2. Basis of Presentation and Note 4. Impairments. |
As of March 31,June 30, 2020, undeveloped leasehold costs included $530 million, $80 million, and $57$54 million attributable to the Delaware Basin, 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, while other costs pertain to acreage that is being held by production.
Notes to Consolidated Financial Statements (Unaudited)
Note 7. 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: | | | Three Months Ended March 31, | Six Months Ended June 30, |
(millions) | 2020 | | 2019 | 2020 | | 2019 |
Asset Retirement Obligations, Beginning Balance | $ | 814 |
| | $ | 880 |
| $ | 814 |
| | $ | 880 |
|
Liabilities Incurred | 3 |
| | 2 |
| 19 |
| | 15 |
|
Liabilities Settled | (27 | ) | | (27 | ) | (42 | ) | | (56 | ) |
Revisions of Estimates | (8 | ) | | — |
| 9 |
| | (70 | ) |
Accretion Expense | 11 |
| | 12 |
| 21 |
| | 23 |
|
Asset Retirement Obligations, Ending Balance | $ | 793 |
| | $ | 867 |
| $ | 821 |
| | $ | 792 |
|
ThreeSix Months Ended March 31,June 30, 2020 Liabilities incurred primarily relate to properties in Israel and the DJ Basin. Liabilities settled primarily relate to abandonment of US onshore properties, with $21$35 million 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. The revision of estimates is due to changes in theboth timing of spend and cost in the DJ Basin.
ThreeSix Months Ended March 31,June 30, 2019 Liabilities settled of $27 million relate to abandonment of US onshore properties, primarily 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 primarily relate to a decrease of $73 million in the DJ Basin as a result of improved cycle times and cost reductions for vertical wells.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
Note 8. Debt
Debt consists of the following: | | | March 31, 2020 | | December 31, 2019 | June 30, 2020 | | December 31, 2019 |
(millions, except percentages) | Debt | | Interest Rate |
| | Debt | | Interest Rate | Debt | | Interest Rate |
| | Debt | | Interest Rate |
Noble Energy, Excluding Noble Midstream Partners | | | | | | | | | | | | | | |
Revolving Credit Facility, due March 9, 2023 | $ | 1,000 |
| | 1.92 | % | | $ | — |
| | — | % | $ | 325 |
| | 1.41 | % | | $ | — |
| | — | % |
Senior Notes and Debentures | 5,884 |
| | (1 | ) | | 5,884 |
| | (1 | ) | 5,884 |
| | (1 | ) | | 5,884 |
| | (1 | ) |
Finance Lease Obligations | 203 |
| | — | % | | 205 |
| | — | % | 193 |
| | — | % | | 205 |
| | — | % |
Total Noble Energy Debt, Excluding Noble Midstream Partners Debt | 7,087 |
| | | | 6,089 |
| | | 6,402 |
| | | | 6,089 |
| | |
Noble Midstream Partners | | | | | | | | | | | | | | |
Noble Midstream Services Revolving Credit Facility, due March 9, 2023 | 750 |
| | 2.16 | % | | 595 |
| | 3.11 | % | 735 |
| | 1.61 | % | | 595 |
| | 3.11 | % |
Noble Midstream Services Term Loan Credit Facility, due July 31, 2021 | 500 |
| | 1.94 | % | | 500 |
| | 2.85 | % | 500 |
| | 1.36 | % | | 500 |
| | 2.85 | % |
Noble Midstream Services Term Loan Credit Facility, due August 23, 2022 | 400 |
| | 1.82 | % | | 400 |
| | 2.74 | % | 400 |
| | 1.24 | % | | 400 |
| | 2.74 | % |
Total Noble Midstream Partners Debt | 1,650 |
| | | | 1,495 |
| | | 1,635 |
| | | | 1,495 |
| | |
Total Debt | 8,737 |
| | | | 7,584 |
| | | 8,037 |
| | | | 7,584 |
| | |
Net Unamortized Discounts and Debt Issuance Costs | (64 | ) | | | | (65 | ) | | | (63 | ) | | | | (65 | ) | | |
Total Debt, Net of Unamortized Discounts and Debt Issuance Costs | 8,673 |
| | | | 7,519 |
| | | 7,974 |
| | | | 7,519 |
| | |
Less Amounts Due Within One Year | | | | | | | | | | | | | | |
Finance Lease Obligations | (41 | ) | | | | (42 | ) | | | (38 | ) | | | | (42 | ) | | |
Long-Term Debt Due After One Year | $ | 8,632 |
| | | | $ | 7,477 |
| | | $ | 7,936 |
| | | | $ | 7,477 |
| | |
| |
(1) | The Senior Notes and Debentures have weighted average interest rates of 4.93% for both March 31,at June 30, 2020 and December 31, 2019. |
Revolving Credit Facilities and Commercial Paper Program We have total borrowing capacity of $4.0 billion across our Revolving Credit Facility and our commercial paper program, which is backed by our Revolving Credit Facility. We choose to borrow under the commercial paper program or Revolving Credit Facility based on market availability and interest rates at the
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
time of borrowing. During thefirst quarter 2020, we borrowed $1.0 billion, net, on our Revolving Credit Facility to increase our cash on hand balance to mitigate potential future issues in the global financial system. During second quarter 2020, we reduced our outstanding borrowings by $675 million, net, leaving $325 million outstanding as of June 30, 2020. As of March 31,June 30, 2020 and December 31, 2019, the Revolving Credit Facility had $3.0$3.7 billion and $4.0 billion available for borrowing, respectively.
Noble Midstream Partners borrowed $155 million, net, on the Noble Midstream Services Revolving Credit Facility. Proceeds received were used to partially fund the investment in Saddlehorn, capital investment program and for working capital purposes. As of March 31,June 30, 2020 and December 31, 2019, the Noble Midstream Services Revolving Credit Facility had $400$415 million and $555 million available for borrowing, respectively.
Fair Value of Debt The fair value of fixed-rate, public debt is estimated based on observable and available market information. 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 outstanding, including our Revolving Credit Facility, 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. Fair value information regarding our debt, which excludes finance lease obligations, is as follows: |
| | | | | | | | | | | | | | | |
| June 30, 2020 | | December 31, 2019 |
(millions) | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
Debt | $ | 7,844 |
| | $ | 7,529 |
| | $ | 7,379 |
| | $ | 8,033 |
|
|
| | | | | | | | | | | | | | | |
| March 31, 2020 | | December 31, 2019 |
(millions) | Carrying Amount | | Fair Value (1) | | Carrying Amount | | Fair Value |
Debt | $ | 8,534 |
| | $ | 6,705 |
| | $ | 7,379 |
| | $ | 8,033 |
|
| |
(1)
| As of March 31, 2020, the difference between the carrying amount and the fair value is primarily due to increased spreads resulting from the current commodity price, supply and demand environment coupled with the COVID-19 pandemic. |
Note 9. 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.
Bureau of Safety and Environmental Enforcement Penalty Assessment In July 2020, we received a penalty assessment of approximately $136,000 from the federal Bureau of Safety and Environmental Enforcement related to an alleged unauthorized discharge from an offshore platform located in the Gulf of Mexico, formerly owned by Noble Energy and sold to Fieldwood Energy, Inc. (Fieldwood), in April 2018. The unauthorized discharge is alleged to have occurred in May 2018, during the transition period when Noble Energy operated the platform on behalf of Fieldwood. Fieldwood is required to fully indemnify Noble Energy for any liabilities that arose during the transition period. Noble Energy has notified Fieldwood of the penalty and is currently seeking a resolution of this matter with Fieldwood. While we cannot predict the outcome of this matter, we do not believe the resolution will have a material adverse effect on our financial position, results of operations or cash flows.
MOEP NotificationsIn April and May 2020, we received two separate notices of intent (NOIs) from Israel’s Ministry of Environmental Protection (MOEP), notifying us of potential enforcement and imposition of monetary sanctions for alleged violations of Israeli environmental laws relating to our Leviathan facility. MOEP’s April NOI alleges breaches of the Leviathan facility’s effluent discharge permit for discharges that occurred primarily before startup of the Leviathan facility and seeks a penalty of approximately $1.2 million, net to the Company's interest in the Leviathan facility, pursuant to Israel’s Prevention of Sea Pollution from Land-Based Sources Law. In the May NOI, MOEP alleges violations of the Leviathan facility's air permit for the alleged failure to transmit to MOEP continuous monitoring data for flares, along with other alleged administrative infractions of Israel's Clean Air Law. Pursuant to Israel's Clean Air Law, MOEP seeks a penalty of approximately $147,000, net to the Company's interest in the Leviathan facility.
In July 2020, a NOI was received from the MOEP notifying us of a potential enforcement and imposition of a monetary sanction of approximately $632,000, net to the Company's interest in the Leviathan facility, pursuant to the Clean Air Law following alleged violations of the emissions permit during the activation of the Leviathan facility's flares.
We have discussed the NOIs with MOEP enforcement staff and anticipate further meetings regarding a 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.
Colorado FracFocus MatterIn July 2019, we received a Notice of Alleged Violation (NOAV) from the Colorado Oil and Gas Conservation Commission (COGCC) advising us of alleged violations of COGCC rules for delinquent disclosures to the FracFocus Chemical Disclosure Registry following commencement of certain hydraulic fracturing activities. We responded to the NOAV in July 2019, confirming with the COGCC that required disclosures had been made prior to issuance of the NOAV. In May 2020, COGCC enforcement staff proposed an administrative penalty in the amount of approximately $149,000 to resolve the enforcement of this matter. We are in the process of reviewing the proposed settlement document. 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.
Colorado Clean Water Act Referral Notice In September 2018, we received a letter from the Department of Justice (DOJ) providing notification of referral from the Environmental Protection Agency (EPA) 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 EPA 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 10. Income Taxes
Income tax (benefit) expense (benefit) consists of the following: | | | Three Months Ended March 31, | Three Months Ended June 30, | | Six Months Ended June 30, |
(millions, except percentages) | 2020 | | 2019 | 2020 | | 2019 | | 2020 | | 2019 |
Current | $ | 37 |
| | $ | 16 |
| $ | 7 |
| | $ | 21 |
| | $ | 44 |
| | $ | 37 |
|
Deferred | (48 | ) | | (100 | ) | (96 | ) | | (1 | ) | | (144 | ) | | (101 | ) |
Total Income Tax Benefit | $ | (11 | ) | | $ | (84 | ) | |
Total Income Tax (Benefit) Expense | | $ | (89 | ) | | $ | 20 |
| | $ | (100 | ) | | $ | (64 | ) |
Effective Tax Rate | 0.27 | % | | 22.5 | % | 18.7 | % | | 71.4 | % | | 2.2 | % | | 18.6 | % |
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. We have concluded that the annual ETR is a reliable estimate considering recent economic and financial market effects of decreased commodity prices and COVID-19. Due to the
In first quarter 2020, as a result of impairments recorded during firstthe quarter, 2020, we have further evaluated our ability to utilize domestic federal and state net operating loss (NOL) and credit carryforwards prior to expiration, concluding a valuation allowance should be recorded for the associated deferred tax assets. See Note 4. Impairments.Impairments. The ETR for the threesix months ended March 31,June 30, 2020 decreased as compared with the same period 2019, primarily due to the valuation allowance discussed above which significantly reduced the deferred tax benefit recorded for the current year loss. The deferred tax benefit was further reduced by the $470 million of deferred tax expense associated with the valuation allowance on losses generated in prior years recorded as a discrete item in first quarter 2020. In addition, the increase in current tax expense was the result of increased earnings in our Eastern Mediterranean segment.
Impact of the Coronavirus Aid, Relief, and Economic Security Act (CARES Act) We evaluated provisions of the CARES Act, signed into law on March 27, 2020. Certain provisions of the CARES Act include modifications to NOL limitations and business interest expense limitations, which are expected to impact utilization of future NOL carryovers. The provisions did not have a material impact on our financial statements for the period ended March 31,June 30, 2020.
Tax Examinations 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.
Note 11. Derivative Instruments and Hedging Activities
Objective and Strategies for Using Derivative Instruments We enter into price hedging arrangements to mitigate effects of commodity price volatility and enhance the predictability of cash flows for a portion of our 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.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
Unsettled Commodity Derivative Instruments As of March 31,June 30, 2020, we had entered into the following crude oil derivative instruments: |
| | | | | | | | | | | | | | | | | | | |
| | | | 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 |
Apr2020-Dec2020 | Sold Calls | NYMEX WTI | 8,000 | $ | — |
| $ | 65.59 |
| | $ | — |
| $ | — |
| $ | — |
|
Apr2020-Dec2020 | Swaps | NYMEX WTI | 11,500 | — |
| 57.79 |
| | — |
| — |
| — |
|
Apr2020-Jun2020 | Swaps | NYMEX WTI | 72,000 | — |
| 37.09 |
| | — |
| — |
| — |
|
Jul2020-Dec2020 | Three-Way Collars | NYMEX WTI | 53,000 | — |
| — |
| | 10.00 |
| 25.00 |
| 37.20 |
|
Jul2020-Dec2020 | Call Swaption | NYMEX WTI | 11,000 | — |
| 58.95 |
| | — |
| — |
| — |
|
2020 | Basis Swaps | Midland (1) | 15,000 | (5.01 | ) | — |
| | — |
| — |
| — |
|
|
| | | | | | | | | | | | | | | | | | | | |
| | | | | Swaps | | Collars |
Settlement Month | Settlement Year | 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 |
Jul-Sept | 2020 | Swaps | NYMEX WTI | 37,500 | $ | — |
| $ | 36.80 |
| | $ | — |
| $ | — |
| $ | — |
|
Oct-Dec | 2020 | Swaps | NYMEX WTI | 14,500 | — |
| 51.91 |
| | — |
| — |
| — |
|
Jul-Dec | 2020 | Three-Way Collars | NYMEX WTI | 53,000 | — |
| — |
| | 10.00 |
| 25.00 |
| 37.20 |
|
Jul-Dec | 2020 | Sold Calls | NYMEX WTI | 8,000 | — |
| 65.59 |
| | — |
| — |
| — |
|
Jul-Sept | 2020 | Basis Swaps | Midland (1) | 27,000 | (4.03 | ) | — |
| | — |
| — |
| — |
|
Oct-Dec | 2020 | Basis Swaps | Midland (1) | 22,000 | (4.21 | ) | — |
| | — |
| — |
| — |
|
Jul-Sept | 2020 | Basis Swaps | WTI Roll (2) | 78,000 | (2.28 | ) | — |
| | — |
| — |
| — |
|
Oct-Dec | 2020 | Basis Swaps | WTI Roll (2) | 64,000 | (2.19 | ) | — |
| | — |
| — |
| — |
|
| |
(1) | These contracts 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. |
| |
(2) | Represents the value differential associated with NYMEX West Texas Intermediate (WTI) futures delivery months and prompt month physical delivery. |
As of March 31,June 30, 2020, we had entered into the following natural gas liquid (NGL) derivative instruments: |
| | | | | | | |
| | | | | Swaps |
Settlement Period | Type of Contract | Index | Bbls per Day | | Weighted Average Fixed Price |
Apr 2020-Sept 2020 | Ethane Swaps | Mont Belvieu | 2,000 | | $ | 7.77 |
|
Apr 2020-Sept 2020 | Propane Swaps | Mont Belvieu | 5,000 | | 21.04 |
|
Apr 2020-Sept 2020 | Isobutane Swaps | Mont Belvieu | 1,000 | | 25.36 |
|
Apr 2020-Sept 2020 | Butane Swaps | Mont Belvieu | 1,500 | | 24.31 |
|
|
| | | | | | | | |
| | | | | | Swaps |
Settlement Month | Settlement Year | Type of Contract | Index | Bbls per Day | | Weighted Average Fixed Price |
Jul | 2020 | Ethane Swaps | Mont Belvieu | 6,500 | | $ | 8.39 |
|
Aug | 2020 | Ethane Swaps | Mont Belvieu | 8,500 | | 8.39 |
|
Sept | 2020 | Ethane Swaps | Mont Belvieu | 10,500 | | 8.45 |
|
Oct-Dec | 2020 | Ethane Swaps | Mont Belvieu | 8,500 | | 8.60 |
|
Jul-Sept | 2020 | Propane Swaps | Mont Belvieu | 5,000 | | 21.04 |
|
Jul-Sept | 2020 | Isobutane Swaps | Mont Belvieu | 1,000 | | 25.36 |
|
Jul-Sept | 2020 | Butane Swaps | Mont Belvieu | 1,500 | | 24.31 |
|
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
As of March 31,June 30, 2020, we had entered into the following natural gas derivative instruments: |
| | | | | | | | | | | | | | | | | | | | |
| | | | 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 |
Apr2020-Dec2020 | Swaps | NYMEX HH | 90,000 |
| $ | — |
| $ | 2.60 |
| | $ | — |
| $ | — |
| $ | — |
|
Apr2020-Oct2020 | Three-Way Collars | NYMEX HH | 40,000 |
| — |
| — |
| | 2.25 |
| 2.70 |
| 2.85 |
|
Apr2020-Dec2020 | Sold Puts | NYMEX HH | 90,000 |
| — |
| — |
| | 2.15 |
| — |
| — |
|
2020 | Basis Swaps | CIG (1) | 139,000 |
| (0.56 | ) | — |
| | — |
| — |
| — |
|
2020 | Basis Swaps | WAHA (1) | 49,500 |
| (1.05 | ) | — |
| | — |
| — |
| — |
|
2021 | Swaps | NYMEX HH | 70,000 |
| — |
| 2.42 |
| | — |
| — |
| — |
|
2021 | Call Swaption | NYMEX HH | 70,000 |
| — |
| 2.42 |
| | — |
| — |
| — |
|
2021 | Basis Swaps | CIG (1) | 60,000 |
| (0.52 | ) | — |
| | — |
| — |
| — |
|
2021 | Basis Swaps | WAHA (1) | 32,000 |
| (0.71 | ) | — |
| | — |
| — |
| — |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| | | | | Swaps | | Collars |
Settlement Month | Settlement Year | 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 |
Jul-Dec | 2020 | Swaps | NYMEX HH | 90,000 |
| $ | — |
| $ | 2.60 |
| | $ | — |
| $ | — |
| $ | — |
|
Jul-Dec | 2020 | Sold Puts | NYMEX HH | 90,000 |
| — |
| — |
| | 2.15 |
| — |
| — |
|
Jul-Oct | 2020 | Three-Way Collars | NYMEX HH | 40,000 |
| — |
| — |
| | 2.25 |
| 2.70 |
| 2.85 |
|
Jul-Dec | 2020 | Basis Swaps | CIG (1) | 139,000 |
| (0.57 | ) | — |
| | — |
| — |
| — |
|
Jul-Dec | 2020 | Basis Swaps | WAHA (1) | 49,500 |
| (1.05 | ) | — |
| | — |
| — |
| — |
|
Jan-Dec | 2021 | Swaps | NYMEX HH | 70,000 |
| — |
| 2.42 |
| | — |
| — |
| — |
|
Jan-Dec | 2021 | Sold Call Swaptions | NYMEX HH | 70,000 |
| — |
| 2.42 |
| | — |
| — |
| — |
|
Jan-Dec | 2021 | Three-Way Collars | NYMEX HH | 62,000 |
| — |
| — |
| | 1.90 |
| 2.40 |
| 2.88 |
|
Jan-Dec | 2021 | Basis Swaps | CIG (1) | 114,000 |
| (0.44 | ) | — |
| | — |
| — |
| — |
|
Jan-Dec | 2021 | Basis Swaps | WAHA (1) | 32,000 |
| (0.71 | ) | — |
| | — |
| — |
| — |
|
Jan-Dec | 2021 | Swaps | ICE TTF (2) | 35,000 |
| — |
| 4.15 |
| | — |
| — |
| — |
|
Jan-Dec | 2022 | Swaps | ICE TTF (2) | 49,000 |
| — |
| 4.26 |
| | — |
| — |
| — |
|
| |
(1) | These contracts establish a fixed amount for the differential between index pricing for Colorado Interstate Gas (CIG) and Waha Hub versus NYMEX Henry Hub (HH). The weighted average differential represents the amount of reduction to NYMEX HH prices for the notional volumes covered by the basis swap contracts. |
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
| |
(2) | In second quarter 2020, we entered into derivative instruments for price hedging protection related to our future production of liquified natural gas (LNG) from our Alen natural gas monetization project, offshore West Africa. The swaps, which were entered into in US dollars per MMBtu, are indexed to ICE Dutch Title Transfer Facility (TTF), an international natural gas benchmark. |
Fair Value Amounts The fair values of commodity derivative instruments on our consolidated balance sheets were as follows (in millions): | | Asset Derivative Instruments | Asset Derivative Instruments | | Liability Derivative Instruments | Asset Derivative Instruments | | Liability Derivative Instruments |
Balance Sheet Location | March 31, 2020 | | December 31, 2019 | | Balance Sheet Location | March 31, 2020 | | December 31, 2019 | June 30, 2020 | | December 31, 2019 | | Balance Sheet Location | June 30, 2020 | | December 31, 2019 |
Other Current Assets | $ | 221 |
| | $ | 14 |
| | Other Current Liabilities | $ | 59 |
| | $ | 36 |
| $ | 61 |
| | $ | 14 |
| | Other Current Liabilities | $ | 151 |
| | $ | 36 |
|
Other Noncurrent Assets | — |
| | 1 |
| | Other Noncurrent Liabilities | 3 |
| | 1 |
| — |
| | 1 |
| | Other Noncurrent Liabilities | 15 |
| | 1 |
|
Total | $ | 221 |
| | $ | 15 |
| | | $ | 62 |
| | $ | 37 |
| $ | 61 |
| | $ | 15 |
| | | $ | 166 |
| | $ | 37 |
|
We estimate the fair values of these instruments using published forward commodity price curves as of the date of the estimate. The discount rate used in the discounted 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. Amounts include the impact of netting clauses within our master agreements that allow us to net cash settle asset and liability positions with the same counterparty.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
Gains and Losses on Commodity Derivative Instruments The effect of commodity derivative instruments on our consolidated statements of operations and comprehensive loss was as follows: | | | Three Months Ended March 31, | Three Months Ended June 30, | | Six Months Ended June 30, |
(millions) | 2020 | | 2019 | 2020 | | 2019 | | 2020 | | 2019 |
Cash (Received) Paid in Settlement of Commodity Derivative Instruments | | | | | | | | | | |
Crude Oil (1) | $ | (210 | ) | | $ | (9 | ) | $ | (103 | ) | | $ | 7 |
| | $ | (313 | ) | | $ | (2 | ) |
NGL | — |
| | — |
| (3 | ) | | — |
| | (3 | ) | | — |
|
Natural Gas | 2 |
| | (5 | ) | — |
| | (8 | ) | | 2 |
| | (13 | ) |
Total Cash Received in Settlement of Commodity Derivative Instruments | (208 | ) | | (14 | ) | $ | (106 | ) | | $ | (1 | ) | | $ | (314 | ) | | $ | (15 | ) |
Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments | | | | |
Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments | | | | | | | | |
Crude Oil | (187 | ) | | 223 |
| $ | 226 |
| | $ | (54 | ) | | $ | 39 |
| | $ | 169 |
|
NGL | (10 | ) | | — |
| 10 |
| | — |
| | — |
| | — |
|
Natural Gas | 16 |
| | 3 |
| 28 |
| | (5 | ) | | 44 |
| | (2 | ) |
Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments | (181 | ) | | 226 |
| |
(Gain) Loss on Commodity Derivative Instruments | | | | |
Total Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments | | $ | 264 |
| | $ | (59 | ) | | $ | 83 |
| | $ | 167 |
|
Loss (Gain) on Commodity Derivative Instruments | | | | | | | | |
Crude Oil | (397 | ) | | 214 |
| $ | 123 |
| | $ | (47 | ) | | $ | (274 | ) | | $ | 167 |
|
NGL | (10 | ) | | — |
| 7 |
| | — |
| | (3 | ) | | — |
|
Natural Gas | 18 |
| | (2 | ) | 28 |
| | (13 | ) | | 46 |
| | (15 | ) |
Total (Gain) Loss on Commodity Derivative Instruments | $ | (389 | ) | | $ | 212 |
| |
Total Loss (Gain) on Commodity Derivative Instruments | | $ | 158 |
| | $ | (60 | ) | | $ | (231 | ) | | $ | 152 |
|
| |
(1) | DuringSix months ended June 30, 2020 includes first quarter 2020 we monetizedmonetization of certain crude oil derivative instruments by settling the instruments prior to their original settlement dates anddates. Additionally, in first quarter 2020 we entered into certain new instruments for the remainder of the year. Certain of this activity was intraperiod and related to crude oil instruments that were not part of our derivative portfolio as of December 31, 2019 and March 31, 2020. Net cash received in first quarter 2020 for these transactions was $160 million. |
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
Note 12. Net Loss Per Share Attributable to Noble Energy Common Shareholders
Noble Energy's basic loss per share of common stock is computed by dividing net 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 loss per share: | | | Three Months Ended March 31, | Three Months Ended June 30, | | Six Months Ended June 30, |
(millions, except per share amounts) | 2020 | | 2019 | 2020 | | 2019 | | 2020 | | 2019 |
Net Loss and Comprehensive Loss Attributable to Noble Energy | $ | (3,963 | ) | | $ | (313 | ) | $ | (408 | ) | | $ | (10 | ) | | $ | (4,371 | ) | | $ | (323 | ) |
Weighted Average Number of Shares Outstanding, Basic | 479 |
| | 478 |
| 479 |
| | 478 |
| | 480 |
| | 478 |
|
Incremental Shares from Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust | — |
| | — |
| — |
| | — |
| | — |
| | — |
|
Weighted Average Number of Shares Outstanding, Diluted | 479 |
| | 478 |
| 479 |
| | 478 |
| | 480 |
| | 478 |
|
Loss Per Share, Basic and Diluted | $ | (8.27 | ) | | $ | (0.65 | ) | $ | (0.85 | ) | | $ | (0.02 | ) | | $ | (9.11 | ) | | $ | (0.68 | ) |
Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above | 16 |
| | 15 |
| 16 |
| | 15 |
| | 16 |
| | 15 |
|
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 sections:
The preceding consolidated financial statements, including the notes thereto, contain detailed information that should be read in conjunction with our MD&A. See also Item 1A. Risk Factors. and Disclosure Regarding Forward-Looking Statements.
EXECUTIVE OVERVIEW AND OPERATING OUTLOOK
The following discussion highlights the current operating environment as well as significant operating and financial results for firstsecond quarter 2020.2020. This discussion should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2019, which includes disclosures regarding our critical accounting policies as part of “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
The impacts on our business of both the significant decline in commodity prices and the novel coronavirus (COVID-19)COVID-19 pandemic are unprecedented. During this time,While we continue actions to address the severe decline in revenues that began in March 2020, including reductions in capital spending, cost controls and changes to our long-term cost structure, the impact of the reduction of development activities will have a significant negative multi-year impact on our production and cash flows and leverage levels and impair the future growth trajectory of the business. Our largely suspended US development activity levels will lead to near-term declines in production, sales volumes and cash flows from operations. This impact will carry into 2021 and, likely, until more constructive commodity prices and the commodity price outlook economically justify new investment. This situation, coupled with SEC reserves prices, will also likely result in a lower level of proved hydrocarbon reserves.
Chevron Merger
On July 20, 2020, we entered into a definitive merger agreement (the Chevron Merger Agreement) with Chevron Corporation (NYSE: CVX) pursuant to which, and subject to the conditions of the agreement, all outstanding shares of Noble Energy will be acquired by Chevron in an all-stock transaction valued at $13 billion, including debt, or $10.38 per share. Under the terms of the agreement, Noble Energy shareholders will receive 0.1191 shares of Chevron common stock for each Noble Energy share. The transaction was approved by the Boards of Directors of both companies and is committed firstanticipated to close in fourth quarter 2020. The transaction is subject to Noble Energy stockholder approval, regulatory approvals, and foremostother customary closing conditions.
For additional information regarding the Chevron Merger Agreement and the Board of Director’s process and rationale for the Chevron Merger, please see the proxy statement and other documents filed with the Securities and Exchange Commission when they become available.
Second Quarter 2020 Operating Highlights
While the global economies have been significantly impacted from the COVID-19 pandemic, we continue actions to address the safetysevere decline in revenues resulting from the current market conditions while progressing certain offshore projects.
Reduced the 2020 Capital ProgramThe 2020 organic capital investment program was reduced approximately 55% from the initial budget, with the reductions coming primarily from the US onshore business.
Significantly Reduced CostDuring the quarter, we significantly reduced our costs in response to current market conditions. We reduced capital and operating costs, with unit production costs per BOE well below 2019 levels. General and administrative (G&A) expenses were also reduced almost 40% from second quarter 2019, primarily as a result of workforce reduction initiatives and reduced travel costs.
Voluntarily Curtailed US Onshore Production In May and June 2020, we voluntarily curtailed certain of our global workforceUS onshore production, which contributed to significantly reducing costs incurred during the period. See Results of Operations, below.
Progressed Capacity Increases from Leviathan and TamarInstallation of compression equipment onshore at the Ashkelon metering station in Israel progressed during second quarter 2020 and commissioning was finalized in July, enabling increased volumes from Leviathan and the communitiesstart of supply from Tamar into Egypt via the EMG Pipeline.
Progressing Natural Gas Monetization Offshore West Africa During second quarter 2020, we progressed the Alen natural gas monetization project and we currently plan to install the offshore pipeline in third quarter 2020. During the quarter, we also entered into international natural gas hedges for a portion of our 2021 and 2022 LNG production. The project is on schedule with first production expected early 2021.
Exploration Program UpdateIn June 2020, we were awarded concessions on two exploration blocks offshore Egypt, which encompass 800,000 square acres. We will hold a 27% non-operated working interest in the position and we, along with our partners, have a three-year initial phase of exploration during which we operate,plan to conduct a seismic program targeting deepwater oil and ensuring thatnatural gas prospects.
Additionally, during the quarter we continuemade the decision not to fulfillpursue lease renewal of our purpose: Energizing the World, Bettering People's Lives®.undeveloped acreage in Gabon.
Commodity Prices
Market Conditions In first quarter 2020, theThe COVID-19 pandemic spread quickly across the globehas continued to cause unprecedented and countries mobilized to implement containment mechanisms and minimize impacts to their populations and economies. Various containment measures, which have included business closures, work stoppages, shuttering of public spaces and events and/or severe restrictions of global and regional travel, among others, have caused unprecedented declinesprolonged reductions in the global demand for crude oil and natural gas commodities. This declinegas. While the relaxation of certain virus containment measures in globalthe second quarter to support the resumption of economic activity resulted in increased commodity demand driven by reduced consumption has contributed toand modest improvement in commodity prices, declining precipitously beginningcommodity demand continues to be significantly lower than levels experienced prior to the COVID-19 pandemic. Even as commodity prices began to turn in mid-March 2020.June 2020, additional virus outbreaks and/or a return of containment measures or further restrictions could negatively impact commodity prices moving forward. The uncertainty regarding the longevity and severity of the impacts of COVID-19 to the oil and gas industry, including the reduced demand for crude oil and natural gas commodities and its resulting impact on commodity prices, may continue until a vaccine or alternative treatment is made widely available across the globe.
Contemporaneously with the COVID-19 pandemic, the oil and gas industry continues to be impacted by excess global supply. The Organization of Petroleum Exporting Countries (OPEC) and certain non-OPEC producers failed to agree in March 2020agreed to production cuts beginning in May 2020 which were intended to stabilize and support global crude oil prices. With no agreement in place, certain large international crude oil producers, including Saudi Arabia and Russia,
began to deeply discount prices of their crude oil and committed to ramping up production in an attempt to protect, or increase, their global market share. This increased production further contributed to global production levels far exceeding current demand, a trend that exacerbated already depressed commodity prices. These extreme supply and demand dynamics have caused a significant decline in crude oil prices negatively impacting all crude oil producers.
In April 2020, members of OPEC and certain non-OPEC producers agreed to production cutsextend through first quarter 2022. While these production cuts are expectedhave proven unable to reduce excess global crude oil inventories in 2021, they are unlikely to be sufficient tosufficiently offset the sharpongoing decreases in demand decreases caused by COVID-19, production from these producers has fallen to its lowest levels in decades.
These factors have caused a number of producers, including many operating in the near-term.
With commodity demandUS, to reduce capital spending levels and consumption significantly depressed, andshut-in production addingat certain fields. While these shut-ins have decreased operating cash flows for producers, they have also served to lower inventory levels crude oil storage began to reach capacity placing further commodity pricing pressure on all elementsand thereby alleviate some of the crude oil and natural gas commodity value chain. For example,storage constraints experienced in April 2020, pricing for the NYMEX West Texas Intermediate (WTI)beginning of second quarter 2020.
In addition to the US crude oil futures contract was negative for one day, resulting from a combination of the May 2020 futures contract trading deadline with a physical settlement and a limited number of buyers with available crude oil storage capacity. This unprecedented negative price was driven by excessive oversupply of crude oil in the US market, and concerns that supply would exceed available crude oil storage capacities. As a result, sales volumes indexed to WTI for that time resulted in certain buyers receiving payments to take crude oil production as storage capacities became scarce and filled.
Additionally, the US domestic natural gas market and US natural gas liquid (NGL) market arecontinue to be oversupplied, with the NGL market also being impacted by export capacity constraints. These factors have contributed to depressed pricing for both US domestic natural gas and US NGLs. We expect that asif US development activity begins to declineremains at the current lower levels, it will result in the US leading to reduced crude oil and associated natural gas production, leading to the eventual adjustment of US domestic natural gas prices will adjust as supply and demand levels equalize.
Reduced demand and resulting commodity price volatility driven by factors discussed above have also contributed to increased short-term competition amongst fuel alternatives to crude oil and natural gas. For example, in the Eastern Mediterranean, spot coal and spot liquefied natural gas (LNG)LNG prices could temporarily behave recently traded below prices in our long-term natural gas salesGSPAs leading to an increase in our customers' use of spot LNG cargoes as an alternative to our natural gas. Where applicable, we believe that in certain instances purchase of spot LNG is in breach of the relevant agreement and purchase agreements (GSPAs).we are exploring all legal avenues available under our contractual arrangements and by law.
Also, certainCertain of our Tamar and Leviathan GSPAs have fixed minimum sales volumesbuyer-minimum take or pay volume-obligations and fixed base pricing with annual index escalations. Certain ofprices subject to minimum-price floor supports. In addition, our Egyptian export contracts include provisions which trigger adjustments to either decrease, or increase, fixed minimum salestake or pay volumes in the event the arithmetic average of daily Brent crude oil prices fallfalls below, or rises above, $50 per barrel for certain periods of time. Our GSPAs do not preclude us from selling natural gas to domestic, or other regional customers, at amounts which exceed fixed minimum sales volumes.
The commodity price environment may continue to remain depressed for an extended period of time based on oversupply decreasingand/or sustained decreases in demand and a potential global economic recessioninstability caused by COVID-19, discussed further below.
Our average realized sales prices, which exclude the impacts of hedges settled in the respective periods, are as follows:
|
| | | | | | | | | | |
| Three Months Ended | | |
Average Realized Sales Prices | March 31, 2020 | | March 31, 2019 | | % Change |
Crude Oil & Condensate (Per Bbl) | $ | 46.21 |
| | $ | 54.19 |
| | (15 | )% |
NGLs (Per Bbl) | 10.30 |
| | 17.86 |
| | (42 | )% |
Natural Gas (Per Mcf) | 2.58 |
| | 2.88 |
| | (10 | )% |
Current and Future Expected Impact to Noble Energy The recentsustained decline in commodity prices adversely affected our realized prices in first quarter 2020 and we expect this trend will continue in the second quarter and, perhaps, beyond. First quarter 2020 realized prices included January and February 2020 prices that were much stronger than those realized in March 2020. Therefore, we expect our realized prices may decline further in second quarter reflecting a full quarter of lower pricing. In addition, our stock price has been negatively impacted by the current environment, significantly reducing our market capitalization. Prolonged lower commodity prices would impact the amount of cash generated from our operating activities, results of operations and our financial position. In response to the current environment, we executed the following actions:actions in first half 2020:
| |
• | Reduced our initial 2020 organic capital investment program - Our initialIn May 2020, organic capital investment program, which excludes Noble Midstream Partners and acquisition capital, was in the range of $1.6 to $1.8 billion. As a result of the current macroeconomic and commodity environment, we have revised our planned 2020 organic capital investment program to a range of $750 million to $850 million approximately 50% of which was spent in first quarter 2020.from $1.6 billion to $1.8 billion. The majority of these reductions are attributed to our US onshore business, resulting in a higher concentration of production from our international assets. Additionally, we have deferred spending on the offshore Colombia exploration well offshorewell. We are continuing to progress the Alen natural gas monetization project, with first production expected in early 2021. |
Table of Contents | |
• | Voluntary production curtailments - In our US onshore business, we voluntarily curtailed an average of 30 MBoe/d, 11 MBbl/d of which was crude oil production. With improvements to operating costs and commodity pricing, the majority of these curtailed volumes were brought back online in July 2020. Our reduced production levels did not impact our ability to deliver volumes under our firm sales or processing commitments during second quarter 2020.
Colombia. We are continuing to progress the Alen natural gas monetization project, with first production expected in early 2021.
|
| |
• | Reduced our quarterly dividend and identified additional cash savings costs- We reduced our quarterly cash dividend to $0.02, down from $0.12 per Noble Energy common share. The reduction to our dividend, which beginsshare in secondfirst quarter 2020, which is expected to preserve approximately $195 million in annualized cash flow. Our Board of Directors will continue reviewing the dividend quarterly in context of market conditions. See Liquidity and Capital Resources, below. Additionally, we identified cash cost savings related to production expenses, general and administrative (G&A) expenses and asset retirements. Certain of these cost savings initiatives included strategic ramp down of activity in our US onshore business and successful negotiation of reduced rates for certain contracts. |
| |
• | Borrowed on our Revolving Credit Facility - During first quarter 2020, we borrowed $1.0 billion, net, on our $4.0 billion Revolving Credit Facility to increase our cash balance on hand in an abundance of caution to mitigate potential future issues in the global financial system. As of March 31, 2020, we had $3.0 billion remaining available on the Revolving Credit Facility and approximately $1.4 billion of cash on hand.
|
| |
• | Cash settled hedges - We enhanced our liquidity by cash settling certain 2020 crude oil hedges prior to their original settlement dates and entered into new instruments for the remainder of the year. Net cash received in first quarter 2020 for these transactions was approximately $160 million. See Item 1. Financial Statements – Note 11. Derivative Instruments and Hedging Activities. |
| |
• | Assessed production levels - As a result of the COVID-19 pandemic and resulting decline in demand for our products, we expect production levels to be lower than our originally expected 2020 production levels, which ranged from 385 MBoe/d to 405 MBoe/d. We expect some of these decreases will result from voluntary curtailments of certain US onshore production beginning in May 2020 and extending into June 2020. The amount and duration of these curtailments could be shortened or extended depending on commodity markets. We do not expect reduced production levels will impact our ability to deliver on our firm sales or processing commitments.
|
| |
• | Assessed proved reserves -We assessed our proved reserves during the quarter and recorded a downward reserves revision of 14 MMBoe primarily attributable to removal of proved undeveloped reserves in the Delaware Basin due to changes in our development plans.
|
| |
• | Assessed long-lived assets for impairment - We performed impairment assessments on proved and unproved oil and gas properties, equity method investments, customer-related intangible assets, goodwill and lease right-of-use assets. Based on these assessments, we recorded impairments related to certainin light of the current commodity price environment, concluding our Delaware Basin proved and unproved properties and Eagle Ford Shale unproved properties, as well as to a finance lease right-of-use asset. Noble Midstream Partners recorded goodwill impairment expense related to a previous acquisition.Felicita discovery, offshore Equatorial Guinea, was fully impaired. See Item 1. Financial Statements – Note 4. Impairments. |
| |
• | Reviewed deferred tax asset valuation allowancesReduced employee headcount - The impairment of our Delaware Basin proved and unproved properties and Eagle Ford Shale unproved properties caused usIn response to establish a valuation allowance for our forecasted domestic net deferred tax asset, which resulted in a corresponding reduction in the deferred tax benefit. See Item 1. Financial Statements – Note 10. Income Taxes. |
| |
• | Adjustedcurrent environment, we have also reduced our employee workforce capacity -and, as a result, in second quarter 2020 recorded $30 million of corporate restructuring expense associated with severance, termination benefits and accelerated stock-based compensation. We implementedalso reduced our contractor workforce to align with operational activities. Additionally, certain employees are still participating in the furlough and part-time workingwork programs for certain employeesimplemented in response to reductions in planned activity levels, representing approximately 30% of our US workforce. Employees will continue receiving enrolled benefits under these programs; however, furloughed employees will not receive salaries and employees under the part-time program will receive 50% of their base salaries. Furthermore, the decreases in planned activity levels caused us to significantly reduce our contractor workforce.first quarter 2020. We expect these actions will reduce future G&A spending beginning in second quarter 2020.and operational spend.
|
| |
• | Lowered executive leadership salaries and director cash retainers - Salaries for the Chief Executive Officer, Senior Officers and Vice Presidents were lowered by 20%, 15% and 10%, respectively. In addition, cash retainers for members of the Board of Directors were lowered by 25%. These reductions continued throughout second quarter 2020 and are expected to extend through the end of 2020. |
COVID-19
Market Conditions ContainmentContinued containment measures and responsive actions to the COVID-19 pandemic, while aiding in the prevention of further outbreak, have resultedcontinue to result in severe declines involatile general economic activity and energy demand. As a result, the global economy has experienced a slowing of economic growth, disruption of global manufacturing supply chains, stagnation of oil and gas consumption and interference with workforce continuity.
Current and Future Expected Impact to Noble Energy TheAlthough certain restrictions related to the COVID-19 pandemic specifically measureshave been relaxed, the virus continues to restrict individuals
within their homes, has impactedimpact the global demand for commodities, a trend we expect to continue into the secondthird quarter, and, perhaps, beyond. Additionally, the risks associated with the virus have impacted our workforce and the way we meet our business objectives. In response to this, we executed the following actions:
| |
• | Remote workforce and personnel management - Due to concerns over health and safety, we have asked the vast majority of our global workforce continues to work remotely until further notice. As of March 31,June 30, 2020, working remotely has not significantly impacted our ability to maintain operations, including use of financial reporting systems, nor has it significantly impacted our internal control environment. In addition, certain of our employees and contractors work in remote field locations or on offshore platforms. We have implemented various health and safety protocols including, among others, reduction of certain operational workloads to critical maintenance and personnel, mandating use of certain secure travel options, review of critical medical supplies and procedures and implementation of other safeguards to protect operational personnel. We have not incurred, and in the future do not expect to incur, significant expenses related to business continuity as employees work from home. |
| |
• | Mobilized our Crisis Management Team (CMT) - Our corporate CMT is responsible for ensuring the organization implements our corporate Employee Health and Wellness plan elements pertaining to pandemic response. This plan follows Center for Disease Control and Prevention (CDC), national, state and local guidance in preparing and responding to COVID-19. The CMT implemented communication protocols should an employee become sick, and we will continue to follow CDC guidance, which is subject to change in the future. To date, we have not experienced significant business or operational interruption due to workforce health or safety concerns pertaining to COVID-19. |
Regarding our supply chain, the structure of the global oilfield material and services supply chain provides us flexibility in sourcing equipment and services for our international development projects. However, the global nature of our supply chains, particularly in relation to our major international construction projects, exposes us to the risk of dispersed supply chain disruptions. We have experienced some delays in deliveries, as well as international travel restrictions impacting service providers, and are monitoring the situation to mitigate impacts on development projects. In the US, while certain of our oilfield service providers and suppliers have become financially distressed and/or experienced bankruptcies, we have been able to utilize alternative suppliers without business interruptions.
The COVID-19 pandemic and impact of lower commodity prices have also caused disruptions in our distribution networks, including, among other things, storage and pipeline constraints and decreased demand from downstream consumers. These have the potential to result in claims of force majeure from transportation, processing, or other downstream service providers, as well as customers and other entities with which we conduct business. Prolonged constraints to the distribution chain could lead to additionalrepeated shut-ins and/or increasedother production curtailment from certain of our US onshore wells in the future, further preventing us from producing our proved reserves. Additionally, we will continue to evaluate the amount and duration of ourany future voluntary production curtailments, which could be shortened or extended depending on commodity markets.
Should our US production be shut-in or curtailed for an extended period of time, we couldwould experience further declines in cash flows attributable to both our US onshore and Midstream segments. Our capital spending and development plans are flexible and we have already curtailed the majority of near-term US onshore development. As our pace of development slows, our inventory of drilled but uncompleted wells is expected to increase in the DJ Basin.
Potential Global RecessionEconomic Instability
Market Conditions COVID-19, coupled with the drop in commodity prices, have contributed to equity market volatility and potentially, the risk ofwhat experts now conclude amounted to a global recession. We expect this global equity market volatility experiencedrecession in first quarter 20202020. Estimated ranges of the duration of these impacts to continue untilequity markets and the global economy vary widely, especially given the continued impacts of COVID-19 pandemic stabilizes.are unknown.
In March and April 2020,recent months, the US government has passed a series of stimulus packages which, collectively, providehave provided the largest relief packages in US history. These packages include various provisions intended to provide relief to individuals and businesses in the form of tax changes, loans and grants, among others. At this time, we do not believe these stimulus measures will have a material impact on Noble Energy; however, we do believe itthey could aid the economy by providing relief to certain individuals and smaller businesses.
Current and Future Expected Impact to Noble Energy We have experienced a sharpThe decline in our stock price overand the firstcorresponding reduction in our
market capitalization were sustained throughout second quarter 2020, a condition that is consistent across our sector. We do not have any debt covenants or other lending arrangements that depend upon our stock price. As of March 31,June 30, 2020, we are in compliance with the financial covenant contained in our Revolving Credit Facility which provides that our total debt to capitalization ratio, as defined in the Revolving Credit Facility agreement, may not exceed 65% at any time. As of March 31,June 30, 2020, this total debt to capitalization ratio was below 40%.
Our consolidated financial statements include the accounts of Noble Midstream Partners. Noble Midstream Partners is subject to financial covenants under the Noble Midstream Services Revolving Credit Facility and term loans, for which the outstanding debt is non-recourse to Noble Energy. As of March 31,June 30, 2020, Noble Midstream Partners is in compliance with these financial covenants. We receive limited partnership cash distributions from Noble Midstream Partners. Changes in Noble Midstream Partners' covenant compliance or changes in distributions to us would not have a material impact to Noble Energy.
During the quarter, we borrowed $1.0 billion, net, on our Revolving Credit Facility to ensure ample cash on hand, leaving over
As cities, states and countries implement plans to loosencontinue relaxing confinement restrictions, and stimulate markets and economies, there is athe risk for the resurgence and recurrence of COVID-19. Such an event is likely to impact global populations and could result in theCOVID-19 remains. The reinstatement of containment measures could potentially leadinglead to an extended period of reduced demand for crude oil and natural gas commodities.
First Quarter 2020 Operating Highlights
Regional Gas Sales From Leviathan FieldBy January 15th, we were selling natural gas from the Leviathan field to customers in Israel, Egypt and Jordan. First quarter 2020 sales volumes from Tamar and Leviathan increased 80% compared to fourth quarter 2019.
Progressing Natural Gas Monetization Offshore West Africa During first quarter 2020, we progressed construction of the offshore pipeline which will transport natural gas from the Alen platform for processing at Punta Europa. Additionally, we finalized commercial LNG sales agreements for our Alen natural gas monetization project, securing sales to a large multi-national LNG trader. The Alen natural gas monetization project provides capital-efficient access to additional reserves and our entry intocommodities, as well as assert further pressure on the global LNG markets.economy.
Potential for Future Reserves ReductionsFirst production is anticipated in early 2021.
Exploration Program Update
DueDecreased capital expenditures for 2020 may result in reductions to our proved reserves quantities and/or delays in timing of additional proved reserves being recognized. For example, the reduction in planned capital funding in 2020 for the DJ and Delaware Basins may result in future negative revisions in proved undeveloped reserves quantities as of December 31, 2020. In addition, while we have implemented measures to reduce our cost structure, should the current low commodity price environment we are delaying the majority of expenditures undercontinue, it is likely that proved reserves quantities would decrease primarily across our exploration program. In offshore Colombia, we have postponed drilling of an exploration well until at least 2021. In 2020, we do not expect to incur significant costs advancing US onshore exploration opportunities.asset portfolio where economic limits are negatively affected. The impact of the reduction in capital expenditures, decrease in commodity prices, and their combined effects on proved reserves will be assessed in fourth quarter 2020 consistent with our annual reserves process. We cannot predict the amounts or timing of future reserves revisions. If such revisions are significant, they could alter future depletion and result in impairment of long-lived assets that may be material.
Potential for Future Impairments
We performed impairment assessments as of March 31,June 30, 2020, including assessments of proved and unproved properties, other long-lived assets, including property, plant and equipment and equity method investments, right-of-use assets and customer relationship intangible assets, including customer relationships and goodwill. These assessments indicatedassets. Other than an impairment to our Felicita discovery, Block O, offshore Equatorial Guinea, we concluded that certainthere were no indicators of our assets were impaired as of March 31,impairment for the second quarter 2020. See Item 1. Financial Statements – Note 4. Impairments. Impairment testing involves uncertainties related to key assumptions such as expectations for future commodity prices, development and capital spending plans, reservoir performance and production, among others. These assumptions are relevant to all of the Company’s operating segments and a significant number of interdependent variables are derived from these key assumptions. There is a high degree of complexity in their application in determining use and value in asset recovery tests and fair value determinations.
Given the inherent volatility of the current market conditions driven by the COVID-19 pandemic and crude oil and natural gas supply dynamics, there exists the potential for future conditions to deviate from our current assumptions. For example, properties that have been previously reduced to fair value, such as our Eagle Ford Shale proved properties in 2019, could become further impaired, or certain other assets, including capitalized exploratory well costs and undeveloped leasehold costs, could become impaired in a future environment. Further, it is likely additional impairments could be triggered if the COVID-19 pandemic leads to a continued and sustained reduction in global economic activity and demand for crude oil and natural gas.
Additionally, our industry is subject to complex laws and regulations adopted or promulgated by international, federal, state and local authorities. These various authorities have the ability to issue or rescind various regulations which, at times, can prevent us from accessing land for which we own mineral rights, surface rights or surface leases.
Recently Issued Accounting Standards
RESULTS OF OPERATIONS – EXPLORATION AND PRODUCTION (E&P)
US Onshore
See Management's Discussion and Analysis - Executive Overview and Operating Outlook for updates to our US onshore capital program. In light of the current commodity price environment, we plan to run one drilling rig in the DJ Basin for the remainder of 2020. We plan to temporarily defer completion activities, which we expect to resume based upon economic and commodity conditions.
The results of operations outlined below are significantly impacted by commodity prices. During the quarter, realized prices in January 2020 and February 2020 were higher than realized prices in March 2020. Since the impacts of the current economic environment are not reflected within the results for the entire quarter, results in first quarter 2020 may not be indicative of future results in the near-term.
During firstsecond quarter 2020, 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) | Average Rigs Operated | | Wells Completed (1) | | Wells Brought Online | | Average Sales Volumes (MBoe/d) |
DJ Basin | 2.5 | | 36 | | 29 | | 156 | 1 | | 4 | | 16 | | 144 |
Delaware Basin | 2 | | 23 | | 22 | | 67 | 0.5 | | 2 | | 6 | | 63 |
Eagle Ford Shale | — | | — | | — | | 46 | — | | — | | — | | 41 |
Total | 4.5 | | 59 | | 51 | | 269 | 1.5 | | 6 | | 22 | | 248 |
| |
(1) | The number of wells drilled refersRefers to the number of wells completed, regardless of when drilling was initiated. |
DJ Basin During firstsecond quarter 2020, our activities were primarily focused in the Mustang area, where we ran one drilling rig. During the quarter, we set record low drilling times and Wells Ranch areas. We currently havecosts, averaging $57 per total foot drilled, a decrease of 15% from the 2019 average.
In addition, our operational personnel performed a strategic review of our producing wells and implemented voluntary curtailments averaging approximately 355 approved24 MBoe/d in response to commodity prices and remaining drilling permits, primarily in our Mustang Comprehensive Drilling Plan (CDP).supply and demand dynamics. The vast majority of these permits have six-year terms. In addition,curtailed production came back online in March 2020 our Wells Ranch CDP application, which covers approximately 41,000 net acres and allows for upJuly 2020. Immaterial amounts of production related to 250 additional drilling permits, was unanimously approved by the Colorado Oil and Gas Conservation Commission, with terms subject to the adoption of new rules which currently propose five-year terms. We can apply for an additional five-year term on any permits left undrilled at the end of the original five-year term.older, less economic vertical wells will be permanently shut-in.
Delaware Basin (Permian Basin) During firstsecond quarter 2020, our activities were primarilyoperational personnel set a new drilling record with a spud to rig release date of approximately 10 days. In addition, we focused on the safe and strategic ramp down of certain activity as we reduced our capital spend and activity levels. During second quarter 2020, we voluntarily curtailed production averaging 6 MBoe/d due to commodity prices and supply and demand dynamics. This reduced activity and lower production did not impact our ability to meet any transportation, processing or sales commitments and the majority of curtailed production came back online in the northern and central areas of our acreage position where we continued to assess completion designs to further drive operational and economic efficiencies, including testing of water intensity and number of stages per completion.July 2020.
Eagle Ford Shale During firstsecond quarter 2020, we focused on maximizing cash flows from existing production and continued to evaluate and assess our development plan for the area. There was no material curtailment impact during second quarter 2020 on production from the Eagle Ford Shale.
International
By January 15,In the Eastern Mediterranean, we continue to focus on reliably supplying the region with natural gas from our Leviathan and Tamar fields. During the quarter, we commenced commissioning of turbo expanders to bring the Leviathan platform to maximum production capacity of 1.2 Bcf/d, with expected completion in August 2020. We continued increasing reliability of the Leviathan platform as commissioning continues with June uptime almost 100%. Additionally, installation of compression equipment onshore at the Ashkelon metering station in Israel progressed during second quarter 2020 and commissioning was finalized in July, enabling increased volumes from Leviathan and the start of supply from Tamar into Egypt via the EMG Pipeline.
In June 2020, we were selling natural gas fromawarded concessions on two exploration blocks offshore the Leviathan field, offshore Israel, to customersWestern Desert area of Egypt. See Exploration Program Update in Israel, EgyptExecutive Overview and Jordan. Our Tamar asset continues to reliably supply natural gas to customers in Israel and Jordan. Most of our Eastern Mediterranean natural gas sales and purchase agreements include fixed minimum volumes and fixed base prices. As a result, natural gas revenues in the region have historically been less susceptible to commodity price volatility.Operating Outlook.
Our West Africa segment continues to benefit from reliable operations at Aseng, Alen and Alba fields. We remain committed tofurther progressed the Alen gas monetizationGas Monetization project, which we expect will create a regional natural gas hub able to supply a number of markets with LNG. During the quarter, we progressed marketing activities for the sale of future LNG cargoes with first production anticipated in early 2021.
Results of Operations
FirstSecond Quarter 2020 Significant E&P Highlights:
by January 15th, we were selling natural gas from the Leviathan field to customers in Israel, Egypt and Jordan;
organic capital expenditures of $392$95 million, compared to $648$596 million in firstsecond quarter 2019;
US onshore average sales volumes of 248 MBoe/d, reflecting curtailment of 30 MBoe/d, primarily in the DJ and Delaware Basins;
total production expense per BOE, gross of $7.77, a reductionintersegment eliminations, of nearly 23% from first$8.88 for second quarter 2020, compared to $9.54 in second quarter 2019;
increased total consolidated average dailyoffshore Israel sales volumes by 17%of 1.1 Bcfe/d, gross; and
impairment expense of $51 million related to 385 MBoe/d, net;the Felicita discovery, Block O, offshore Equatorial Guinea.
increased average daily sales volumes for crude oil by 11%;
finalized commercial LNG sales agreements for Alen natural gas monetization, securing sales to a large multi-national LNG trader; and
| |
• | recorded certain asset impairments of $2.7 billion and undeveloped leasehold exploration expense of $1.5 billion.
|
The following is a summarized statement of operations for our E&P business: | | | Three Months Ended March 31, | Three Months Ended June 30, | Six Months Ended June 30, |
(millions) | 2020 | | 2019 | 2020 | | 2019 | 2020 | | 2019 |
Oil, NGL and Gas Sales to Third Parties | $ | 894 |
| | $ | 937 |
| $ | 493 |
| | $ | 954 |
| $ | 1,387 |
| | $ | 1,891 |
|
Sales of Purchased Oil and Gas | 25 |
| | 14 |
| 4 |
| | 28 |
| 29 |
| | 42 |
|
(Loss) Income from Equity Method Investments and Other | (19 | ) | | 15 |
| |
Income (Loss) from Equity Method Investments and Other | | 6 |
| | 18 |
| (13 | ) | | 33 |
|
Total Revenues | 900 |
|
| 966 |
| 503 |
|
| 1,000 |
| 1,403 |
|
| 1,966 |
|
Production Expense | 341 |
| | 351 |
| 278 |
| | 298 |
| 619 |
| | 649 |
|
Exploration Expense | 1,504 |
| | 24 |
| 15 |
| | 33 |
| 1,519 |
| | 57 |
|
Depreciation, Depletion and Amortization | 462 |
| | 475 |
| 290 |
| | 493 |
| 752 |
| | 968 |
|
Cost of Purchased Oil and Gas | 28 |
| | 14 |
| 4 |
| | 28 |
| 32 |
| | 42 |
|
Asset Impairments | 2,703 |
| | — |
| 51 |
| | — |
| 2,754 |
| | — |
|
(Gain) Loss on Commodity Derivative Instruments | (389 | ) | | 212 |
| |
Loss Before Income Taxes | (3,768 | ) | | (168 | ) | |
Loss (Gain) on Commodity Derivative Instruments | | 158 |
| | (60 | ) | (231 | ) | | 152 |
|
(Loss) Income Before Income Taxes | | (351 | ) | | 179 |
| (4,119 | ) | | 11 |
|
Average Oil, NGL and Gas Sales Volumes and Prices Average daily sales volumes from our share of production and average realized sales prices were as follows: | | | Average Sales Volumes (1) | | Average Realized Sales Prices (1) | 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) | 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 March 31, 2020 | |
Three Months Ended June 30, 2020 | | Three Months Ended June 30, 2020 |
United States | 117 |
| | 66 |
| | 516 |
| | 269 |
| | $ | 46.10 |
| | $ | 10.30 |
| | $ | 1.27 |
| 113 |
| | 59 |
| | 457 |
| | 248 |
| | $ | 22.30 |
| | $ | 7.51 |
| | $ | 1.16 |
|
Eastern Mediterranean | 1 |
| | — |
| | 390 |
| | 66 |
| | 25.20 |
| | — |
| | 5.36 |
| 1 |
| | — |
| | 307 |
| | 52 |
| | N/M |
| | — |
| | 5.00 |
|
West Africa (2) | 20 |
| | — |
| | 178 |
| | 50 |
| | 47.35 |
| | — |
| | 0.27 |
| 14 |
| | — |
| | 178 |
| | 44 |
| | 23.87 |
| | — |
| | 0.27 |
|
Total Consolidated Operations | 138 |
| | 66 |
| | 1,084 |
| | 385 |
| | 46.21 |
| | 10.30 |
| | 2.58 |
| 128 |
| | 59 |
| | 942 |
| | 344 |
| | 22.36 |
| | 7.51 |
| | 2.24 |
|
Equity Investments (3) | 1 |
| | 4 |
| | — |
| | 5 |
| | 53.65 |
| | 28.69 |
| | — |
| 2 |
| | 4 |
| | — |
| | 6 |
| | 22.77 |
| | 21.02 |
| | — |
|
Total(4) | 139 |
| | 70 |
| | 1,084 |
| | 390 |
| | $ | 46.27 |
| | $ | 11.43 |
| | $ | 2.58 |
| 130 |
| | 63 |
| | 942 |
| | 350 |
| | $ | 22.36 |
| | $ | 8.40 |
| | $ | 2.24 |
|
Three Months Ended March 31, 2019 | |
Three Months Ended June 30, 2019 | | Three Months Ended June 30, 2019 |
United States | 113 |
| | 59 |
| | 483 |
| | 253 |
| | $ | 53.46 |
| | $ | 17.86 |
| | $ | 2.49 |
| 117 |
| | 64 |
| | 495 |
| | 263 |
| | $ | 58.13 |
| | $ | 14.54 |
| | $ | 1.61 |
|
Eastern Mediterranean | — |
| | — |
| | 233 |
| | 39 |
| | — |
| | — |
| | 5.57 |
| — |
| | — |
| | 209 |
| | 35 |
| | — |
| | — |
| | 5.53 |
|
West Africa (2) | 12 |
| | — |
| | 168 |
| | 40 |
| | 61.01 |
| | — |
| | 0.27 |
| 11 |
| | — |
| | 199 |
| | 45 |
| | 66.61 |
| | — |
| | 0.27 |
|
Total Consolidated Operations (4) | 126 |
| | 59 |
| | 884 |
| | 332 |
| | 54.19 |
| | 17.86 |
| | 2.88 |
| |
Total Consolidated Operations | | 128 |
| | 64 |
| | 903 |
| | 343 |
| | 58.88 |
| | 14.54 |
| | 2.22 |
|
Equity Investments (3) | 1 |
| | 4 |
| | — |
| | 5 |
| | 53.01 |
| | 36.81 |
| | — |
| 2 |
| | 4 |
| | — |
| | 6 |
| | 65.75 |
| | 31.22 |
| | — |
|
Total (4) | 127 |
| | 63 |
| | 884 |
| | 337 |
| | $ | 54.18 |
| | $ | 19.09 |
| | $ | 2.88 |
| 130 |
| | 68 |
| | 903 |
| | 349 |
| | $ | 58.98 |
| | $ | 15.47 |
| | $ | 2.22 |
|
Six Months Ended June 30, 2020 | | Six Months Ended June 30, 2020 |
United States | | 115 |
| | 63 |
| | 487 |
| | 259 |
| | $ | 34.40 |
| | $ | 8.99 |
| | $ | 1.22 |
|
Eastern Mediterranean | | 1 |
| | — |
| | 348 |
| | 59 |
| | N/M |
| | — |
| | 5.20 |
|
West Africa (2) | | 16 |
| | — |
| | 178 |
| | 46 |
| | 37.42 |
| | — |
| | 0.27 |
|
Total Consolidated Operations | | 132 |
| | 63 |
| | 1,013 |
| | 364 |
| | 34.68 |
| | 8.99 |
| | 2.43 |
|
Equity Investments (3) | | 2 |
| | 4 |
| | — |
| | 6 |
| | 34.91 |
| | 24.95 |
| | — |
|
Total (4) | | 134 |
| | 67 |
| | 1,013 |
| | 370 |
| | $ | 34.68 |
| | $ | 10.00 |
| | $ | 2.43 |
|
Six Months Ended June 30, 2019 | | Six Months Ended June 30, 2019 |
United States | | 115 |
| | 62 |
| | 489 |
| | 258 |
| | $ | 55.84 |
| | $ | 16.12 |
| | $ | 2.04 |
|
Eastern Mediterranean | | — |
| | — |
| | 220 |
| | 37 |
| | — |
| | — |
| | 5.55 |
|
West Africa (2) | | 11 |
| | — |
| | 184 |
| | 42 |
| | 63.74 |
| | — |
| | 0.27 |
|
Total Consolidated Operations | | 126 |
| | 62 |
| | 893 |
| | 337 |
| | 56.57 |
| | 16.12 |
| | 2.55 |
|
Equity Investments (3) | | 2 |
| | 4 |
| | — |
| | 6 |
| | 61.02 |
| | 34.11 |
| | — |
|
Total (4) | | 128 |
| | 66 |
| | 893 |
| | 343 |
| | $ | 56.62 |
| | $ | 17.21 |
| | $ | 2.55 |
|
N/M amount is not meaningful.
| |
(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) | Volumes represent sales of condensate and LPG from the LPG plant in Equatorial Guinea. See Income (Loss)Income from Equity Method Investments, below. |
| |
(4) | Includes an immaterial amount of condensate sales from offshore Israel assets. |
An analysis of revenues from sales of crude oil, NGLs and natural gas is as follows: | | (millions) | Crude Oil & Condensate | | NGLs | | Natural Gas | | Total | Crude Oil & Condensate | | NGLs | | Natural Gas | | Total |
Three Months Ended March 31, 2019 | $ | 612 |
| | $ | 96 |
| | $ | 229 |
| | $ | 937 |
| |
Three Months Ended June 30, 2019 | | $ | 688 |
| | $ | 84 |
| | $ | 182 |
| | $ | 954 |
|
Changes due to | | | | | | | | |
(Decrease) Increase in Sales Volumes | | (9 | ) | | (8 | ) | | 38 |
| | 21 |
|
Decrease in Sales Prices (1) | | (418 | ) | | (36 | ) | | (28 | ) | | (482 | ) |
Three Months Ended June 30, 2020 | | $ | 261 |
| | $ | 40 |
| | $ | 192 |
| | $ | 493 |
|
| | | | | | | | |
Six Months Ended June 30, 2019 | | $ | 1,300 |
| | $ | 180 |
| | $ | 411 |
| | $ | 1,891 |
|
Changes due to | | | | | | | | | | | | | | |
Increase in Sales Volumes | 69 |
| | 11 |
| | 87 |
| | 167 |
| 52 |
| | 1 |
| | 122 |
| | 175 |
|
Decrease in Sales Prices (1) | (103 | ) | | (45 | ) | | (62 | ) | | (210 | ) | (513 | ) | | (79 | ) | | (87 | ) | | (679 | ) |
Three Months Ended March 31, 2020 | $ | 578 |
| | $ | 62 |
| | $ | 254 |
| | $ | 894 |
| |
Six Months Ended June 30, 2020 | | $ | 839 |
| | $ | 102 |
| | $ | 446 |
| | $ | 1,387 |
|
Crude Oil and Condensate Sales Revenues Revenues from crude oil and condensate sales decreased in firstsecond quarter 2020 as compared with second quarter 2019 primarily due to the following:
voluntary curtailment of approximately 11 MBbl/d as DJ and Delaware Basin production was temporarily shut-in in response to the low commodity price environment; and
lower volumes in the Eagle Ford Shale due to reduced activity and natural field decline;
partially offset by:
higher pre-curtailment production rates in the DJ and Delaware Basins due to increased development activity that had occurred prior to the commodity price decline; and
higher West Africa sales volumes of 8 MBbl/d for first quarter 2020 compared to first quarter 2019 due to Aseng 6P coming online in fourth quarter 2019 and timing of liftings;liftings.
Revenues from crude oil and
higher US onshore sales volumes of 4 MBbl/d for first quarter 2020 compared to first quarter 2019 primarily due to an increase in development activity in the DJ and Delaware Basins.
NGL Sales RevenuesRevenuesfrom NGL condensate sales decreased infor the first quartersix months of 2020 as compared with the first six months of 2019 primarily due to the following:
voluntary curtailment of approximately 5 MBbl/d, as DJ and Delaware Basin production was temporarily shut-in in response to the low commodity price environment;
lower volumes in the Eagle Ford Shale due to reduced activity and natural field decline;
partially offset by:
higher US onshore sales volumes of 7 MBbl/d for first quarter 2020 compared to first quarter 2019 primarily due to an increase in development activitysales volume increases in the DJ and Delaware Basins.Basins due to increased development activity; and
higher West Africa sales volumes due to Aseng 6P coming online in fourth quarter 2019 and timing of liftings.
Natural GasNGL Sales Revenues Revenuesfrom natural gasNGL sales increaseddecreased in firstsecond quarter 2020 as compared with second quarter 2019 primarily due to the following:
higher Israel sales volumes of 157 MMcf/d for first quarter 2020 compared to first quarter 2019 primarily due to Leviathan commencing production late December 2019; and
higher sales volumes in the DJ and Delaware Basins of 50 MMcf/d for first quarter 2020 compared to first quarter 2019 due to an increase in development activities;
partially offset by:
voluntary curtailment of approximately 8 MBbl/d as DJ and Delaware Basin production was temporarily shut-in in response to the low commodity price environment; and
reduced activity and natural field decline in the Eagle Ford Shale;
partially offset by:
higher pre-curtailment production rates in the DJ and Delaware Basins due to increased development activity that had occurred prior to the commodity price decline.
Revenues from NGL sales decreased for the first six months of 2020 as compared with the first six months of 2019 primarily due to the following:
voluntary curtailment of approximately 4 MBbl/d as DJ and Delaware Basin production was temporarily shut-in in response to the low commodity price environment; and
lower volumes in the Eagle Ford Shale due to reduced activity and natural field decline;
partially offset by:
first quarter 2020 sales volume increases in the DJ and Delaware Basin due to increased development activity.
Natural Gas Sales RevenuesRevenues from natural gas sales increased in second quarter 2020 as compared with second quarter 2019 primarily due to the following:
higher sales volumes of 98 MMcf/d offshore Israel primarily due to the commencement of production from the Leviathan field in late December 2019; and
higher pre-curtailment production rates in the DJ and Delaware Basins due to increased development activity that had occurred prior to the commodity price decline;
partially offset by:
voluntary curtailment of approximately 70 MMcf/d as DJ and Delaware Basin production was temporarily shut-in in response to the low commodity price environment; and
lower Eagle Ford Shale sales volumes of 1735 MMcf/d due to reduced activity and natural field decline.
Revenues from natural gas sales increased for the first six months of 2020 as compared with the first six months of 2019 primarily due to the following:
higher sales volumes of 128 MMcf/d offshore Israel primarily due to the commencement of production from the Leviathan field in late December 2019; and
higher sales volumes in the DJ and Delaware Basins of 26 MMcf/d for the first six months of 2020, primarily driven by higher first quarter 2020 comparedvolumes in both basins due to first quarter 2019increased development activities;
partially offset by:
voluntary curtailment of approximately 34 MMcf/d in the DJ and Delaware Basins; and
lower Eagle Ford Shale sales volumes of 25 MMcf/d due to reduced activity and natural field decline.
Sales and Cost of Purchased Oil and Gas Sales and purchases of crude oil increaseddecreased in second quarter and the first quartersix months of 2020 as compared with 2019 primarily due to lower prices for crude oil and reduced sales and purchases in the Delaware Basinpurchase activity related to meet firm sales agreements, which did not occur in 2019. This increase was partially offset by decreases in sales and purchasesbuild of crude oilshipper history in the DJ Basin as compared to first quarter 2019.Basin.
Income (Loss) Income from Equity Method Investments and Other Income (loss) from equity method investments and other decreased in second quarter and the first quartersix months of 2020 as compared with 2019. The decrease includes a $31impacts of approximately $30 million decrease from the first quarter 2020 turnaround at Atlantic Methanol Production Company, LLC (AMPCO), our methanol investment, primarily due to planned turnaround activities andas well as the impact of lower methanol prices, and a $1prices. These losses were partially offset by income of $12 million decreasefor the first six months of 2020 from Alba Plant, our LPG investment.
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 | Total per BOE (1)(2) | | Total | | United States (2) | | Eastern Mediterranean | | West Africa |
Three Months Ended March 31, 2020 | | | | | | | | | | |
Three Months Ended June 30, 2020 | | | | | | | | | | |
Lease Operating Expense (3) | $ | 4.32 |
| | $ | 151 |
| | $ | 108 |
| | $ | 13 |
| | $ | 30 |
| $ | 3.70 |
| | $ | 116 |
| | $ | 81 |
| | $ | 15 |
| | $ | 20 |
|
Production and Ad Valorem Taxes | 1.06 |
| | 37 |
| | 37 |
| | — |
| | — |
| 0.73 |
| | 23 |
| | 23 |
| | — |
| | — |
|
Gathering, Transportation and Processing | 4.26 |
| | 149 |
| | 146 |
| | 3 |
| | — |
| 4.35 |
| | 136 |
| | 133 |
| | 3 |
| | — |
|
Other Royalty Expense | 0.11 |
| | 4 |
| | 4 |
| | — |
| | — |
| 0.10 |
| | 3 |
| | 3 |
| | — |
| | — |
|
Total Production Expense | $ | 9.75 |
| | $ | 341 |
| | $ | 295 |
| | $ | 16 |
| | $ | 30 |
| $ | 8.88 |
| | $ | 278 |
| | $ | 240 |
| | $ | 18 |
| | $ | 20 |
|
Total Production Expense per BOE | | | $ | 9.75 |
| | $ | 12.03 |
| | $ | 2.69 |
| | $ | 6.68 |
| | | $ | 8.88 |
| | $ | 10.63 |
| | $ | 3.82 |
| | $ | 4.98 |
|
Three Months Ended March 31, 2019 | |
| | |
| | |
| | |
| | |
| |
Three Months Ended June 30, 2019 | | |
| | |
| | |
| | |
| | |
|
Lease Operating Expense (3) | $ | 5.32 |
| | $ | 159 |
| | $ | 125 |
| | $ | 10 |
| | $ | 24 |
| $ | 4.26 |
| | $ | 133 |
| | $ | 114 |
| | $ | 9 |
| | $ | 10 |
|
Production and Ad Valorem Taxes | 1.57 |
| | 47 |
| | 47 |
| | — |
| | — |
| 1.28 |
| | 40 |
| | 40 |
| | — |
| | — |
|
Gathering, Transportation and Processing | 4.75 |
| | 142 |
| | 142 |
| | — |
| | — |
| 3.97 |
| | 124 |
| | 124 |
| | — |
| | — |
|
Other Royalty Expense | 0.10 |
| | 3 |
| | 3 |
| | — |
| | — |
| 0.03 |
| | 1 |
| | 1 |
| | — |
| | — |
|
Total Production Expense | $ | 11.74 |
| | $ | 351 |
| | $ | 317 |
| | $ | 10 |
| | $ | 24 |
| $ | 9.54 |
| | $ | 298 |
| | $ | 279 |
| | $ | 9 |
| | $ | 10 |
|
Total Production Expense per BOE | | | $ | 11.74 |
| | $ | 13.91 |
| | $ | 2.84 |
| | $ | 6.67 |
| | | $ | 9.54 |
| | $ | 11.64 |
| | $ | 2.82 |
| | $ | 2.47 |
|
Six Months Ended June 30, 2020 | | | | | | | | | | |
Lease Operating Expense (3) | | $ | 4.03 |
| | $ | 267 |
| | $ | 189 |
| | $ | 28 |
| | $ | 50 |
|
Production and Ad Valorem Taxes | | 0.90 |
| | 60 |
| | 60 |
| | — |
| | — |
|
Gathering, Transportation and Processing | | 4.30 |
| | 285 |
| | 279 |
| | 6 |
| | — |
|
Other Royalty Expense | | 0.11 |
| | 7 |
| | 7 |
| | — |
| | — |
|
Total Production Expense | | $ | 9.34 |
| | $ | 619 |
| | $ | 535 |
| | $ | 34 |
| | $ | 50 |
|
Total Production Expense per BOE | | | | $ | 9.34 |
| | $ | 11.36 |
| | $ | 3.19 |
| | $ | 5.88 |
|
Six Months Ended June 30, 2019 | | |
| | |
| | |
| | |
| | |
|
Lease Operating Expense (3) | | $ | 4.78 |
| | $ | 292 |
| | $ | 239 |
| | $ | 19 |
| | $ | 34 |
|
Production and Ad Valorem Taxes | | 1.42 |
| | 87 |
| | 87 |
| | — |
| | — |
|
Gathering, Transportation and Processing | | 4.35 |
| | 266 |
| | 266 |
| | — |
| | — |
|
Other Royalty Expense | | 0.07 |
| | 4 |
| | 4 |
| | — |
| | — |
|
Total Production Expense | | $ | 10.62 |
| | $ | 649 |
| | $ | 596 |
| | $ | 19 |
| | $ | 34 |
|
Total Production Expense per BOE | | | | $ | 10.62 |
| | $ | 12.75 |
| | $ | 2.83 |
| | $ | 4.44 |
|
| |
(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 second quarter and the first quartersix months of 2020 decreased as compared with 2019, primarily due to the following:
decrease in US onshore due to production curtailments, as discussed further above;
decrease in US onshore lease operating expense (LOE) due to reductions in leased assets and lower labor and workover costs;costs based on lower activity levels; and
decrease in US onshore production and ad valorem taxes due to lower commodity price realizations and assessed taxes in March 2020;taxes;
partially offset by:
increase in West Africa LOE due to an increase in sales volumes;volumes and timing of expenses;
increase in LOE and gathering, transportation and processing expenses in Eastern Mediterranean due to Leviathan commencing production in late December 2019.2019; and
increase in US onshore GTP due to second quarter 2020 costs relating to minimum processing fees not associated with minimum volume commitments in the DJ Basin.
The unit rate per BOE decreased for second quarter and the first quartersix months of 2020 as compared with 2019 primarily due to the decrease in production expenses and anthe total increase in volumes from US onshore, Eastern Mediterranean and West Africa.sales volumes.
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 | Total | | United States | | Eastern Mediterranean | | West Africa |
Three Months Ended March 31, 2020 | | | | | | | | | | |
Three Months Ended June 30, 2020 | | | | | | | | |
DD&A Expense | $ | 462 |
| | $ | 419 |
| | $ | 19 |
| | $ | 24 |
| | $ | — |
| $ | 290 |
| | $ | 252 |
| | $ | 16 |
| | $ | 22 |
|
Unit Rate per BOE (1) | $ | 13.22 |
| | $ | 17.09 |
| | $ | 3.19 |
| | $ | 5.34 |
| | $ | — |
| $ | 9.26 |
| | $ | 11.16 |
| | $ | 3.39 |
| | $ | 5.48 |
|
Three Months Ended March 31, 2019 | | | | | | | | | | |
Three Months Ended June 30, 2019 | | | | | | | | |
DD&A Expense | $ | 475 |
| | $ | 439 |
| | $ | 16 |
| | $ | 20 |
| | $ | — |
| $ | 493 |
| | $ | 457 |
| | $ | 17 |
| | $ | 19 |
|
Unit Rate per BOE (1) | $ | 15.89 |
| | $ | 19.27 |
| | $ | 4.55 |
| | $ | 5.56 |
| | $ | — |
| $ | 15.80 |
| | $ | 19.07 |
| | $ | 5.33 |
| | $ | 4.69 |
|
Six Months Ended June 30, 2020 | | | | | | | | |
DD&A Expense | | $ | 752 |
| | $ | 671 |
| | $ | 35 |
| | $ | 46 |
|
Unit Rate per BOE (1) | | $ | 11.35 |
| | $ | 14.25 |
| | $ | 3.28 |
| | $ | 5.41 |
|
Six Months Ended June 30, 2019 | | | | | | | | |
DD&A Expense | | $ | 968 |
| | $ | 896 |
| | $ | 33 |
| | $ | 39 |
|
Unit Rate per BOE (1) | | $ | 15.84 |
| | $ | 19.17 |
| | $ | 4.92 |
| | $ | 5.10 |
|
| |
(1) | Consolidated unit rates exclude sales volumes and expenses attributable to equity method investments. |
DD&A expense for second quarter and the first quartersix months of 2020 decreased as compared with 2019, primarily due to the following:
decreases in the Delaware Basin due to the first quarter 2020 impairment of proved properties;
decreases in the DJ Basin primarily due to year-end 2019 reserves additions and capital efficiencies; and
decreases in the Eagle Ford Shale due to the fourth quarter 2019 impairment of proved properties.properties;
partially offset by:
increases in Eastern Mediterranean as the Leviathan field commenced production in late December 2019; and
increases in West Africa due to higher sales volumes.
The unit rate per BOE for second quarter and the first quartersix months of 2020 decreased as compared with 2019, primarily due to the decrease in total DD&A expense and an increase in volumes from US onshore, Eastern Mediterranean and West Africa.total sales volumes.
Loss (Gain)/Loss on Commodity Derivative Instruments We incurred a gain on commodity derivative instruments for the first quartersix months of 2020 as compared with a loss on commodity derivative instruments infor the first six months of 2019.
For the first quartersix months of 2020, gain on commodity derivative instruments included:
net cash receipts of $208$314 million; and
net non-cash increase of $181 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 first quarter 2019, loss on commodity derivative instruments included:
net cash settlement receipts of $14 million; and
net non-cash decrease of $226$83 million in the fair value of our net commodity derivative liability, primarily driven by changes in the forward commodity price curves for both crude oiloil.
For the first six month of 2019, loss on commodity derivative instruments included:
net cash settlement receipts of $15 million; and natural gas.
net non-cash decrease of $167 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 results of operations outlined below are significantly impacted by commodity prices. Since the impacts of the current economic environment are not reflected within the results for the entire quarter, results in first quarter 2020 may not be indicative of future results in the near-term.
FirstSecond Quarter 2020 Significant Midstream Highlights:
exercisetotal revenues of Black Diamond's option to acquire a 20% ownership interest in Saddlehorn, which owns a crude oil pipeline,$144 million, as compared with $161 million for $87 million, net, to Noble Midstream Partners;second quarter 2019;
commissioning ofcommenced full service on the EPIC crude oil pipeline;
total revenuesbegan transition to full NGL service on EPIC Y-Grade; and
commenced crude oil service on Delaware Crossing.
| |
• | recorded goodwill impairment of $110 million.
|
The following is a summarized statement of operations for our Midstream segment: | | | Three Months Ended March 31, | Three Months Ended June 30, | Six Months Ended June 30, |
(millions) | 2020 | | 2019 | 2020 | | 2019 | 2020 | | 2019 |
Midstream Services Revenues – Third Party | $ | 25 |
| | $ | 24 |
| $ | 26 |
| | $ | 20 |
| $ | 51 |
| | $ | 44 |
|
Sales of Purchased Oil and Gas | 83 |
| | 33 |
| 29 |
| | 52 |
| 112 |
| | 85 |
|
(Loss) Income from Equity Method Investments | (5 | ) | | 2 |
| |
Loss from Equity Method Investments | | (3 | ) | | (2 | ) | (8 | ) | | — |
|
Intersegment Revenues | 115 |
| | 106 |
| 92 |
| | 91 |
| 207 |
| | 197 |
|
Total Revenues | 218 |
| | 165 |
| 144 |
| | 161 |
| 362 |
| | 326 |
|
Operating Costs and Expenses | 33 |
| | 36 |
| 31 |
| | 41 |
| 64 |
| | 77 |
|
Depreciation, Depletion and Amortization | 26 |
| | 25 |
| 26 |
| | 26 |
| 52 |
| | 51 |
|
Cost of Purchased Oil and Gas | 80 |
| | 31 |
| 29 |
| | 48 |
| 109 |
| | 79 |
|
Goodwill Impairment | 110 |
| | — |
| — |
| | — |
| 110 |
| | — |
|
Total Expense | 249 |
| | 92 |
| 86 |
| | 115 |
| 335 |
| | 207 |
|
(Loss) Income Before Income Taxes | $ | (31 | ) | | $ | 73 |
| |
Income Before Income Taxes | | $ | 58 |
| | $ | 46 |
| $ | 27 |
| | $ | 119 |
|
Midstream Services Revenues – Third Party The amountMidstream services revenues - third party are generated from Noble Midstream Partners' gathering and processing and fresh water delivery services provided to third parties. Amounts in 2020 exceed those of revenue2019 due to an increase in throughput volumes from additional well connections in the DJ and Delaware Basins.
Intersegment revenues generated by the Midstream segment dependsdepend 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.business. 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. We anticipate these volumes will decrease in the near-term due to impacts of COVID-19 and the current commodity price environment.
Sales and Costs of Purchased Oil and Gas Sales and costs of purchased oil for first quarterthe six months ended June 30, 2020 increased as compared with 2019 due to an increase in throughput volumes driven by additional well connections.connections in first quarter 2020 as compared to 2019. Sales and costs of purchased oil for the three months ended June 30, 2020 decreased as compared to 2019 due to the significant drop in oil prices in second quarter 2020.
(Loss) IncomeOperating Costs and ExpensesOperating costs and expenses are lower in 2020 as compared to 2019 as a result of cost reduction initiatives, particularly for the three months ended June 30, 2020.
Loss from Equity Method Investments (Loss) IncomeLoss from equity method investments decreased for first quarter 2020 as compared with 2019, primarilyall periods presented are due to operating losses incurred by certain of Noble Midstream Partners' equity method investments that have yetprior to the projects fully commence commercial operations,coming online. These losses, which primarily relate to EPIC crude oil pipeline and EPIC Y-Grade, are partially offset by earnings forincome from the Saddlehorn Pipeline beginning in first quarter 2020 and earnings from Advantage Pipeline.Pipeline for both 2020 and 2019.
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, corporate restructurings and certain costs associated with mitigating the effects of our retained Marcellus Shale transportation agreements, are recorded at the Corporate level.
The impacts of the current environment, including changes to our workforce and borrowings under our Revolving Credit Facility in late March 2020, were not yet fully reflected within G&A and interest expense, respectively, in first quarter 2020. As such, results in first quarter 2020 may not be indicative of future results.
Transportation Exit Cost Revenues and expenses associated with retained Marcellus Shale transportation contracts were as follows: | | | Three Months Ended March 31, | Three Months Ended June 30, | | Six Months Ended June 30, |
(millions) | 2020 | | 2019 | 2020 | | 2019 | | 2020 | | 2019 |
Sales of Purchased Gas (1) | $ | 17 |
| | $ | 27 |
| $ | 16 |
| | $ | 23 |
| | $ | 33 |
| | $ | 50 |
|
Cost of Purchased Gas (1) | 31 |
| | 42 |
| 30 |
| | 37 |
| | 61 |
| | 79 |
|
Firm Transportation Exit Cost (2) | — |
| | 92 |
| — |
| | — |
| | — |
| | 92 |
|
| |
(1) | Relates to third party mitigation activities we engage in to utilize a portion of our Marcellus Shale transportation commitment.commitments. Cost of purchased gas includes utilized and unutilized transportation expense. Decreases in sales and cost of purchased gas related to lower natural gas prices in first quarter 2020 as compared to first quarter 2019. |
| |
(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 March 31, | Three Months Ended June 30, | Six Months Ended June 30, |
(millions, except unit rate) | 2020 | | 2019 | 2020 | | 2019 | 2020 | | 2019 |
G&A Expense | $ | 85 |
| | $ | 102 |
| $ | 63 |
| | $ | 105 |
| $ | 148 |
| | $ | 207 |
|
Unit Rate per BOE (1) | $ | 2.43 |
| | $ | 3.41 |
| $ | 2.01 |
| | $ | 3.36 |
| $ | 2.23 |
| | $ | 3.39 |
|
| |
(1) | Consolidated unit rates exclude sales volumes and expenses attributable to equity method investments. |
DueThe significant decrease in G&A expense in 2020 compared to our focus on overall G&A cost reductions, expense for first quarter 2020 decreased approximately 17% as compared with first quarter 2019. Decreases were2019 primarily duerelates to reduced employee costs, as well as a reduction in travel, office expenses and travel expenses.contractor costs. The unit rate per BOE for second quarter and the first quartersix months of 2020 also decreased as compared with 2019 due to the reduction in G&A expense and the increase in the total sales volumes.
Other Operating Expense, Net Other operating expense, net includes $40 million of impairment expense for a finance lease right-of-use asset relating to a corporate real estate lease. See Item 1. Financial Statements – Note 4. Impairments. Additionally, other operating expense, net, includes $30 million of corporate restructuring costs including cash severance, termination benefits and acceleration of stock-based compensation for workforce reductions. Interest Expense and Capitalized Interest Interest expense and capitalized interest were as follows: | | | Three Months Ended March 31, | Three Months Ended June 30, | | Six Months Ended June 30, |
(millions, except unit rate) | 2020 | | 2019 | 2020 | | 2019 | | 2020 | | 2019 |
Interest Expense, Gross | $ | 91 |
| | $ | 87 |
| $ | 90 |
| | $ | 90 |
| | $ | 181 |
| | $ | 177 |
|
Capitalized Interest | (10 | ) | | (21 | ) | (3 | ) | | (27 | ) | | (13 | ) | | (48 | ) |
Interest Expense, Net | $ | 81 |
| | $ | 66 |
| $ | 87 |
| | $ | 63 |
| | $ | 168 |
| | $ | 129 |
|
Unit Rate per BOE (1) | $ | 2.32 |
| | $ | 2.21 |
| $ | 2.78 |
| | $ | 2.02 |
| | $ | 2.54 |
| | $ | 2.11 |
|
| |
(1) | Consolidated unit rates exclude sales volumes and expenses attributable to equity method investments. |
Interest expense, gross, for second quarter and the first quartersix months of 2020 remained relatively flat as compared with 2019. See Item 1. Financial Statements – Note 8. Debt. Capitalized interest for second quarter and the first quartersix months of 2020 decreased as compared with 2019, primarily due to lower work in progress amounts with Leviathan commencing production late December 2019, partially offset by additions to equity method investments engaged in construction activities.2019. The unit rate per BOE for second quarter and the first quartersix months of 2020 increased as compared with 2019, primarily due to the increase in net interest expense partially offset by the increase in total sales volumes.
LIQUIDITY AND CAPITAL RESOURCES
Impact of Commodity Price Environment and COVID-19
Recent events, as further described in Management's Discussion & Analysis - Executive Overview and Operating Outlook, have significantly impacted our financing strategy. The magnitude of the recent drop inlower commodity prices, combined with thecontinued global uncertainty surrounding the COVID-19 pandemic, is unprecedented. Additionally, on July 20, 2020, the Chevron Merger Agreement was announced. See Management's Discussion & Analysis - Executive Overview and Operating Outlook. Our capital structure and financing strategy are designedDue to provide sufficient liquidity to fund development of our discovered hydrocarbons through commodity price cycles. In the current commodity price environment, the duration of which could be prolonged, we have delayed certain development projects and exploration activities in order to preserve our financial liquidity. Additionally, we have adjusted our shareholder return initiatives, including our dividend, when determining how to best allocate our capital and cash resources to maintain maximum liquidity. TheIn April 2020, we announced a reduction of our quarterly dividend to $0.02 per Noble Energy common share, which is expected to preserve approximately $195 million in annualized cash flow.
Our liquidity is also impacted by our credit rating which along with our competitors in the oil and gas industry is periodically reviewed by the various credit rating agencies. Given current market conditions, credit rating agencies have increased the frequency and number of negative outlooks and/or downgrades to companies in our industry. We expect the rating agencies will continue to review our credit ratings in light of the current economic environment and our indebtedness levels, and we can provide no assurance that we will not be downgraded from investment grade or other by one or more agencies in the future. A downgrade in our credit rating below investment grade could, among other things, restrict our access to the commercial paper market, increase the interest rate and fees we pay on our $4.0 billion Revolving Credit Facility, and increase the costs of future borrowings. Further, a downgrade could limit the size and availability of future borrowings and those borrowings could include much more restrictive terms than our previous borrowings, such as posting of collateral, cash or other security. A credit rating downgrade could impact the counterparties with which we can transact, including current and potential partners with which we develop long-term projects. See Item 1A. Risk Factors.
Our liquidity could also be impacted by counterparty credit risk. We closely monitor the credit worthiness of all counterparties with whom we do business. When considered necessary, we obtain letters of credit or other credit enhancements to mitigate risks associated with certain counterparties.
Additionally, our liquidity is impacted by the amount of distributions we receive from Noble Midstream Partners. In March 2020, Noble Midstream Partners announced a reduction in their quarterly distribution to $0.1875 per unit which will reducereduced cash received from distributions beginning in second quarter 2020.
Our focus on liquidity is allowing us to address current volatility and risk. During the first quartersix months of 2020, our primary sources of liquidity were cash flows from operations, cash on hand and borrowings under our Revolving Credit Facility, which does not mature until 2023. Cash flows from operations include $208includes $314 million of cash received in the settlement of derivative instruments. Weinstruments, which we utilize derivative instruments to protect liquidity, provide risk mitigation and support cash flow predictability.
During March 2020, the instability in the global economy disrupted the commercial paper market. Therefore, instead of borrowing under our commercial paper program, inIn March 2020, we borrowed $1.0 billion, net, on our $4.0 billion Revolving Credit Facility, leaving $3.0 billion of available borrowing capacity. The first quarter 2020 borrowing on our $4.0 billion Revolving Credit Facility wasFacility. These borrowings were used to increase our cash on hand balance in an abundance of caution to mitigate potential future issues in the global financial system. In June 2020, we repaid $675 million, net, of borrowings under the Revolving Credit Facility, leaving $325 million outstanding at June 30, 2020. As of March 31,June 30, 2020, we are in compliance with the financial covenant contained in our Revolving Credit Facility which provides that our total debt to capitalization ratio, as defined in the Revolving Credit Facility agreement, may not exceed 65% at any time. As of March 31,June 30, 2020, our total debt to capitalization ratio was below 40%.
A few of our commercial agreements contain the obligation to provide assurances in the event certain financial triggers are met. Potential collateral requirements could be triggered by a downgrade of our credit rating to non-investment grade or other financial triggers. We anticipate meeting any collateral obligations through bi-lateral letters of credit facilities and/or our Revolving Credit Facility. We have sufficient capacity under such facilities to meet potential collateral obligations. Posting of collateral through the use of our bilateral facilities and other instruments would not impact our available borrowing capacity under our Revolving Credit Facility, while issuance of letters of credit under our Revolving Credit Facility would reduce available borrowing capacity by an equivalent amount.
Our credit rating, as well asSubject to certain limitations under the credit ratings of our competitors in the oil and gas industry, are periodically reviewed by the various credit rating agencies. Credit rating downgrades, particularly below investment grade, or other negative rating actions could restrict our access to the commercial paper market, increase the interest rate and feesChevron Merger Agreement, we pay on our $4.0 billion Revolving Credit Facility, and increase the costs of future borrowings.
We will continue to consider strategic farm-out arrangements of our working interests for reimbursement of our capital spending. Additionally, we consider repatriations of foreign cash to increase our financial flexibility and fund our capital investment program.
We believe these factors position us to have sufficient liquidity to address the current downturn in commodity prices. However, we are unable to predict how long commodity demand and prices will continue to be depressed, nor are we able to predict whether prices will continue to decline. Our financing strategy in future periods could include further reductions to capital spending, additional borrowings under our $4.0 billion Revolving Credit Facility, further changes to our dividend, proceeds from asset divestitures, or issuance of new debt or equity securities and/or extension of debt maturities, among others. 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 requirements and other factors.
These actions to our financing strategy are subject to certain limitations under the Chevron Merger Agreement.
Available Liquidity
The following table summarizes our cash, debt balances and available liquidity: | | | March 31, 2020 | | December 31, 2019 | June 30, 2020 | | December 31, 2019 |
(millions, except percentages) | Noble Energy Excluding Noble Midstream Partners | | Noble Midstream Partners | | Total | | Noble Energy Excluding Noble Midstream Partners | | Noble Midstream Partners | | Total | Noble Energy Excluding Noble Midstream Partners | | Noble Midstream Partners | | Total | | Noble Energy Excluding Noble Midstream Partners | | Noble Midstream Partners | | Total |
Cash and Cash Equivalents | $ | 1,379 |
| | $ | 18 |
| | $ | 1,397 |
| | $ | 471 |
| | $ | 13 |
| | $ | 484 |
| $ | 311 |
| | $ | 13 |
| | $ | 324 |
| | $ | 471 |
| | $ | 13 |
| | $ | 484 |
|
Amounts Available for Borrowing (1) | 3,000 |
| | — |
| | 3,000 |
| | 4,000 |
| | — |
| | 4,000 |
| 3,675 |
| | — |
| | 3,675 |
| | 4,000 |
| | — |
| | 4,000 |
|
Total Liquidity (1) | $ | 4,379 |
| | $ | 18 |
| | $ | 4,397 |
| | $ | 4,471 |
| | $ | 13 |
| | $ | 4,484 |
| $ | 3,986 |
| | $ | 13 |
| | $ | 3,999 |
| | $ | 4,471 |
| | $ | 13 |
| | $ | 4,484 |
|
| | | | | | | | | | | | | | | | | | | | | | |
Total Debt (2) | $ | 7,087 |
| | $ | 1,650 |
| | $ | 8,737 |
| | $ | 6,089 |
| | $ | 1,495 |
| | $ | 7,584 |
| $ | 6,402 |
| | $ | 1,635 |
| | $ | 8,037 |
| | $ | 6,089 |
| | $ | 1,495 |
| | $ | 7,584 |
|
Noble Energy Share of Equity | | | | | $ | 4,397 |
| | | | | | $ | 8,410 |
| | | | | $ | 4,003 |
| | | | | | $ | 8,410 |
|
Ratio of Debt-to-Book Capital (3) | | | | | 67 | % | | | | | | 47 | % | | | | | 67 | % | | | | | | 47 | % |
| |
(1) | Excludes $400$415 million available for borrowing under the Noble Midstream Services Revolving Credit Facility, which is not available to Noble Energy for general corporate purposes. |
| |
(3) | 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. This ratio is not used in determining compliance with the financial covenant in our $4.0 billion Revolving Credit Facility. As of March 31,June 30, 2020, we are in compliance with the financial covenant contained in our Revolving Credit Facility which provides that our total debt to capitalization ratio, as defined in the Revolving Credit Facility agreement, may not exceed 65% at any time. As of March 31,June 30, 2020, our total debt to capitalization ratio, as defined in the Revolving Credit Facility agreement, was below 40%. See Impact of Commodity Price Environment and COVID-19, above. |
Cash and Cash Equivalents We had approximately $1.4 billion$324 million in cash and cash equivalents at March 31,June 30, 2020, primarily denominated in US dollars and invested in money market funds and short-term deposits with major financial institutions. Approximately $330$272 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 Noble Energy's $4.0 billion Revolving Credit Facility and the Noble Midstream Services Revolving Credit Facility of nearly $1.2 billion both mature in 2023. These committed facilities are used to fund capital investment programs, acquisitions and amounts for working capital purposes.
At March 31,June 30, 2020, $1.0 billion$325 million was outstanding under the Noble Energy Revolving Credit Facility, leaving $3.0$3.7 billion available for borrowing. At March 31, 2020, $750borrowing, and $735 million was outstanding under the Noble Midstream Services Revolving Credit Facility, leaving $400$415 million available for borrowing.
Cash Flows
The following table summarizes our total cash provided by (used in) operating, investing and financing activities: | | | Three Months Ended March 31, | Six Months Ended June 30, |
(millions) | 2020 | | 2019 | 2020 | | 2019 |
Operating Activities | $ | 482 |
| | $ | 528 |
| $ | 400 |
| | $ | 1,092 |
|
Investing Activities | (696 | ) | | (911 | ) | (965 | ) | | (1,697 | ) |
Financing Activities | 1,127 |
| | 194 |
| 405 |
| | 488 |
|
Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash | $ | 913 |
| | $ | (189 | ) | |
Decrease in Cash, Cash Equivalents and Restricted Cash | | $ | (160 | ) | | $ | (117 | ) |
Operating Activities Cash provided by operating activities for the first quartersix month of 2020 decreased $46$692 million as compared with 2019. The decrease was primarily driven by a decreasereductions in revenues driven by loweras a result of the current commodity prices,price environment. These impacts were partially offset by cash received for settlements of commodity derivatives of $208$314 million, as compared with cash receipts of $14$15 million in the prior year. Working capital was impacted by a decrease in accounts receivables due to lower average realized prices.
Investing Activities Cash used in investing activities decreased approximately $215$732 million for the first quartersix months of 2020 as compared with 2019, primarily due to decreases of $284$681 million in capital spending for property, plant and equipment due to reduced
capital spend for Leviathan, which came online late December 2019, and reduced spending primarily in our US onshore business.business as a result of the current commodity price environment and the COVID-19 pandemic. During the quarter,first six months of 2020, cash used for additions to equity method investments was $45$187 million lower than in the first quarter 2020.six months of 2019. These decreases were partially offset by reductions in proceeds from divestitures, as we had $17$18 million of proceeds in the first quartersix months of 2020 as compared to $123 million in the prior year.
Financing Activities Our financing activities during the first quartersix months of 2020 primarily included net borrowings of $1.0 billion$325 million under our $4.0 billion Revolving Credit Facility and net borrowings of $155$140 million on the Noble Midstream Services Revolving Credit Facility. Additionally, we received contributions from noncontrolling interest owners of $78$81 million, which primarily related to external funding received for Noble Midstream Partners' investment in Saddlehorn. During the first quartersix months of 2020, we paid $58$68 million of cash dividends to Noble Energy shareholders.
Our financing activities during the first quartersix months of 2019 included net borrowings of $170$240 million under the commercial paper program, net borrowings of $310 million on the Noble Midstream Services Revolving Credit Facility and the receipt of $99 million of preferred equity, net of offering costs. In addition, we paid $53$111 million of cash dividends to Noble Energy shareholders.
Capital Expenditure Activities
Our capital expenditures (on an accrual basis) were as follows: | | | Three Months Ended March 31, | Three Months Ended June 30, | | Six Months Ended June 30, |
(millions) | 2020 | | 2019 | 2020 | | 2019 | | 2020 | | 2019 |
Unproved Property Acquisition (1) | $ | — |
| | $ | 35 |
| $ | — |
| | $ | 4 |
| | $ | — |
| | $ | 39 |
|
Proved Property Acquisition (1) | 6 |
| | 4 |
| 1 |
| | — |
| | 7 |
| | 4 |
|
Exploration | 12 |
| | 14 |
| 3 |
| | 4 |
| | 15 |
| | 18 |
|
Development | 340 |
| | 614 |
| 91 |
| | 578 |
| | 431 |
| | 1,192 |
|
Midstream | 43 |
| | 66 |
| 5 |
| | 52 |
| | 48 |
| | 118 |
|
Corporate | 7 |
| | 8 |
| 4 |
| | 9 |
| | 11 |
| | 18 |
|
Other (2) | 40 |
| | 10 |
| |
Other Exploration & Production(2) | | 3 |
| | 4 |
| | 43 |
| | 13 |
|
Total | $ | 448 |
| | $ | 751 |
| $ | 107 |
| | $ | 651 |
| | $ | 555 |
| | $ | 1,402 |
|
| | | | | | | | | | |
Additions to Equity Method Investments | | | | | | | | | | |
Saddlehorn Pipeline (3) | $ | 87 |
| | $ | — |
| $ | — |
| | $ | — |
| | $ | 87 |
| | $ | — |
|
EPIC Y-Grade | 14 |
| | 123 |
| — |
| | 28 |
| | 14 |
| | 151 |
|
EPIC Crude Holdings | 33 |
| | 104 |
| — |
| | 114 |
| | 33 |
| | 218 |
|
Delaware Crossing | 17 |
| | 38 |
| — |
| | 1 |
| | 17 |
| | 39 |
|
Other | 2 |
| | 6 |
| 3 |
| | 1 |
| | 4 |
| | 7 |
|
Total Additions to Equity Method Investments (4) | $ | 153 |
| | $ | 271 |
| $ | 3 |
| | $ | 144 |
| | $ | 155 |
| | $ | 415 |
|
| | | | | | | | | | |
Increase in Finance Lease Obligations | $ | 8 |
| | $ | 2 |
| $ | 2 |
| | $ | 1 |
| | $ | 10 |
| | $ | 3 |
|
| |
(1) | Costs relate to US onshore leasehold activity. |
| |
(2) | 2020 amount includes $34 million of linefill purchased in first quarter 2020 for start-up of the EPIC crude oil and Delaware Crossing pipelines. This amount is included within our US onshore segment. |
| |
(3) | Represents amount contributed by Noble Midstream Partners and excludes $73 million of externally funded capital. |
Development costs decreased significantly compared to 2019 primarily due to decreased capital spend for the Leviathan project, which commenced production in late December 2019, as well as decreases in our continued focus on US onshore capital efficiencies. Developmentspending in response to the current commodity price environment and impacts from the COVID-19 pandemic. For the six months ended June 30, 2020, development costs included approximately $319$384 million for US onshore, prior to intersegment eliminations, $29$41 million for Eastern Mediterranean and $16$34 million for West Africa.
Capital spending by our Midstream segment in first quarter 2020also decreased as compared with 2019, primarily due to reduced spend on gathering activities.
in response to the commodity price environment and COVID-19 pandemic.
Dividends
In AprilJuly 2020, our Board of Directors declared a quarterly cash dividend of $0.02 per Noble Energy common share, which will be paid on May 26,August 24, 2020 to shareholders of record on May 11,August 10, 2020. 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
At March 31,June 30, 2020, our open commodity derivative instruments were in a net assetliability position with a fair value of $159$105 million. Based on the March 31,June 30, 2020 published commodity futures price curves for the underlying commodities, a hypothetical price increase of 10% per Bbl for both crude oil and NGLs and 10% per MMBtu for natural gas would decreaseincrease the fair value of our net commodity derivative assetliability by approximately $64$84 million. Even with certain hedging arrangements in place to mitigate
the risk of commodity price volatility, our 2020 revenues and results of operations will be adversely affected if commodity prices continue to decline. See Item 1. Financial Statements – Note 11. Derivative Instruments and Hedging Activities. Interest Rate Risk
Changes in interest rates affect the amount of interest we pay on certain of our borrowings. Outstanding borrowings under the Noble Revolving Credit Facility, Noble Midstream Services Revolving Credit Facility, and Noble Midstream Services Term Loan Credit Facilities, which as of March 31,June 30, 2020 total nearly $2.7$2.0 billion and have a weighted average interest rate of 1.98%1.44%, 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 March 31,June 30, 2020, we may invest in such instruments in the future in order to mitigate interest rate risk.
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:
our growth strategies;
our future results of operations;
our liquidity and ability to finance our exploration and development activities;
our ability to successfully and economically explore for and develop crude oil, NGL and natural gas resources;
anticipated trends in our business;
market conditions in the oil and gas industry;
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;
our ability to make and integrate acquisitions or execute divestitures;
access to resources; and
the potential adverse impact of the COVID-19 pandemic on our business, financial condition and results of operations, and the markets and communities in which we operate.operate; and
the completion of the Chevron Merger Agreement.
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, and we undertake no obligation to publicly update or revise any forward-looking statements to reflect events or circumstances that may arise after the date of this report. 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, 2019 and in thisthe quarterly report on Form 10-Q for the quarter ended March 31, 2020 and in this quarterly report on Form 10-Q for the quarter ended June 30, 2020, 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, 2019 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.
Part II. Other Information
Item 1. Legal Proceedings
See discussion of legal proceedings in Part I. Financial Information, Item 1. Financial Statements – Note 9. Commitments and Contingencies of this Form 10-Q, which is incorporated by reference into this Part II. Item 1, as well as discussion in Item 3. Legal Proceedings, of our Annual Report on Form 10-K for the year ended December 31, 2019. Item 1A. Risk Factors
ThereDue to the Company’s proposed Chevron Merger, and due to the current environment, there have been no material changes fromto the risk factors disclosed inincluded under Part I, Item 1A. Risk Factors1A of ourthe Company’s Annual Report on Form 10-K for the year ended December 31, 2019. For a complete discussion of the Company’s risk factors, refer to the risk factors included under Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2019 and the following risk factors:
We will be subject to business uncertainties while the Chevron Merger is pending, which could adversely affect our businesses.
Uncertainty about the effect of the Chevron Merger on employees and those that do business with us may have an adverse effect on Noble Energy. These uncertainties may impair our ability to attract, retain and motivate key personnel until the Chevron Merger is completed and for a period of time thereafter, and could cause those that transact with us to seek to change their existing business relationships with us. Employee retention at Noble Energy may be challenging during the pendency of the Chevron Merger, as employees may experience uncertainty about their roles. In addition, the Chevron Merger Agreement restricts us from entering into certain corporate transactions, entering into certain material contracts, making certain changes to our capital budget, incurring certain indebtedness and taking other specified actions without the consent of Chevron, and generally requires us to continue our operations in the ordinary course of business during the pendency of the Chevron Merger. These restrictions may prevent us from pursuing attractive business opportunities or adjusting our capital plan prior to the completion of the Chevron Merger.
We may be subject to lawsuits relating to the Chevron Merger, which could adversely affect our business, financial condition and operating results.
Noble Energy, Chevron and/or their respective directors and officers may be subject to lawsuits relating to the Chevron Merger. Such litigation is very common in connection with acquisitions of public companies, regardless of any merits related to the underlying acquisition. While we will evaluate and defend against any actions vigorously, the costs of the defense of such lawsuits and other effects of such litigation could have an adverse effect on our business, financial condition and operating results.
Completion of the Chevron Merger is subject to a number of conditions, and if these conditions are not satisfied or waived, the Chevron Merger will not be completed. Failure to complete, or significant delays in completing, the Chevron Merger could negatively affect the trading prices of our common stock and our future business and financial results.
Completion of the Chevron Merger is subject to satisfaction or waiver of certain closing conditions, including (1) the adoption of the Chevron Merger Agreement by Noble Energy stockholders, (2) the expiration or termination of the waiting period under the Hart-Scott-Rodino Act, as amended, applicable to the Chevron Merger and the receipt of other applicable customary regulatory approvals, (3) the absence of any order or law prohibiting consummation of the Chevron Merger, (4) the effectiveness of the Registration Statement on Form S-4 to be filed by Chevron pursuant to which the shares of Chevron common stock to be issued in connection with the Chevron Merger will be registered with the Securities and Exchange Commission and (5) the authorization for listing on the New York Stock Exchange of the shares of Chevron common stock to be issued in connection with the Chevron Merger. There can be no assurance that the conditions to the completion of the Chevron Merger will be satisfied or waived or that the Chevron Merger will be completed.
If the Chevron Merger is not completed, or if there are significant delays in completing the Chevron Merger, the trading prices of our common stock and our future business and financial results could be negatively affected, and we may be subject to several risks, including the following:
the requirement that we pay Chevron a termination fee of approximately $176 million under certain circumstances provided in the Chevron Merger Agreement;
negative reactions from the financial markets, including declines in the prices of our common stock due to the fact that current prices may reflect a market assumption that the Chevron Merger will be completed;
having to pay certain significant costs relating to the Chevron Merger; and
the attention of our management will have been diverted to the Chevron Merger rather than our own operations and pursuit of other opportunities that could have been beneficial to us.
The Chevron Merger Agreement limits our ability to pursue alternatives to the Chevron Merger.
The Chevron Merger Agreement contains provisions that may discourage a third party from submitting a competing proposal that might result in greater value to our stockholders than the following:Chevron Merger, or may result in a potential competing acquirer of the Company proposing to pay a lower per share price to acquire us than it might otherwise have proposed to pay. These provisions include a general prohibition on us from soliciting or, subject to certain exceptions relating to the exercise of fiduciary duties by our Board, entering into discussions with any third party regarding any competing proposal or offer for a competing transaction.
Because the exchange ratio in the Chevron Merger Agreement is fixed and because the market price of Chevron common stock will fluctuate prior to the completion of the Chevron Merger, our stockholders cannot be sure of the market value of the Chevron common stock they will receive as consideration in the Chevron Merger.
Under the terms of the Chevron Merger Agreement, our stockholders will receive consideration consisting of 0.1191 of a share of Chevron common stock for each share of Noble Energy common stock, based on the closing price of Chevron common stock on July 17, 2020, the last trading day prior to the announcement of the Chevron Merger. The exchange ratio for the stock component of the merger consideration is fixed, and there will be no adjustment to the merger consideration for changes in the market price of Chevron common stock or our common stock prior to the completion of the Chevron Merger.
If the Chevron Merger is completed, there will be a time lapse between the date of signing of the Chevron Merger Agreement and the date on which our stockholders who are entitled to receive the merger consideration actually receive the merger consideration. The respective market values of Chevron common stock and our common stock have fluctuated and may continue to fluctuate during this period as a result of a variety of factors, including general market and economic conditions, changes in each company’s business, operations and prospects, commodity prices, regulatory considerations, and the market’s assessment of Chevron’s business and the Chevron Merger. Such factors are difficult to predict and in many cases may be beyond the control of Chevron and us. The actual value of the stock component of any merger consideration received by our stockholders at the completion of the Chevron Merger will depend on the market value of Chevron common stock at that time. This market value may differ, possibly materially, from the market value of Chevron common stock at the time the Chevron Merger Agreement was entered into or at any other time.
Our level of indebtedness, combined with the COVID-19 pandemic and recent developments in the global crude oil markets, may make us increasingly vulnerable to a downgrade in our credit rating. A downgrade in our credit rating below investment grade could have a material adverse impact on our financial condition, results of operations and cash flows.
From time to time, we have relied on access to capital markets for funding of certain of our operations. A downgrade in our credit rating could increase our cost of borrowings under our existing Revolving Credit Facility, limit access to our commercial paper program and limit access to private and public markets to raise debt.
A downgrade in our credit rating below investment grade could impact our access to, and terms available to us, with regards to future revolving credit facilities. For example, a downgrade in our credit rating could reduce the size of future revolving credit facilities and could require additional covenants, collateral requirements, and/or a number of other terms that are more restrictive than those currently included within our $4.0 billion Revolving Credit Facility.
These factors could significantly impact our ability to access capital markets, making it more difficult for us to fund our capital exploration and development programs, especially those related to our longer-term offshore projects.
Additionally, credit ratings are often analyzed by suppliers and other counterparties when they seek to engage in various transactions with us. A downgrade below investment grade may require us to post collateral, letters of credit, cash, and/or other forms of security as financial assurance of our performance under various contractual arrangements. A downgrade in our credit
rating could limit counterparties willing to transact with us in the short-term, as well as counterparties willing to partner with us in development of long-term projects.
The occurrence of any of the foregoing could have a material adverse impact on our financial condition, results of operations and cash flows.
The COVID-19 pandemic and recent developments in the global crude oil markets have had, and may continue to have, material adverse consequences for the global economy, which have impacted our planned operational activities, and have had, and may continue to have, a material adverse impact on our financial condition, results of operations and cash flows.
The responses of governmental authorities and companies across the world to reduce the spread of the COVID-19 pandemic have significantly reduced global economic activity. VariousOngoing containment measures, which have included business closures, work stoppages, shuttering of public spaces and events and/or severe restrictions of global and regional travel, among others, while aiding in the prevention of further spread of the virus, have resulted in the slowing of economic growth, reduced demand for crude oil and natural gas and the disruption of global manufacturing supply chains. While certain containment measures have been relaxed, the remaining risks and uncertainty surrounding resurgence and reinstitution of more severe containment measures continue to reduce demand for crude oil and natural gas commodities. The longevity and severity of the impact of COVID-19 on the oil and gas industry, including the reduced demand for crude oil and natural gas commodities and its resulting impact on commodity prices, may continue until a vaccine or alternative treatment is made widely available across the globe. We are unable to predict when, and if, an effective vaccine for COVID-19 will become available.
Additionally, in March 2020, OPEC and non-OPEC producers failed to agree to production cuts, causing a significant drop in crude oil prices. Also, Saudi Arabia recently reduced its export prices to certain markets, while increasing its prices in others. Subsequently, in April 2020, members of OPEC and certain non-OPEC producers agreed to production cuts through first quarter 2022. While these production cuts are expected to reduce excess global crude oil inventories in 2021, they are unlikely to be sufficient to offset the sharp demand decreases caused by COVID-19 in the near-term.
Collectively, these factors have contributed to significant negative global economic impacts, including a significant drop in demand for hydrocarbon products, potentially causingproducts. In second quarter 2020, experts concluded that the US and other global economies to fallUnited States fell into a recession thatbeginning in first quarter 2020. Currently, estimates as to the duration of these impacts to the equity markets and global economy vary widely. These impacts could extend throughout 2020 and beyond. A recession could likely extend the time for the current crude oil markets to absorb excess supplies, resulting in suppressed crude oil prices for a number of future quarters.
Our profitability has been and will likely continue to be significantly affected by this decreased demand and lower commodity price environment. The decline in commodity prices and our future estimated production levels could lead to additional material impairments of our long-lived assets, intangible assets, equity method investments and right-of-use assets. It is likely additional impairments could be triggered if the COVID-19 pandemic leads to a continued and sustained reduction in global economic activity and demand for energy.
The COVID-19 pandemic and impact of lower commodity prices have also caused disruptions in our distribution networks, including, among other things, storage and pipeline constraints and decreased demand from downstream consumers. These have the potential to result in claims of force majeure from transportation, processing, or other downstream service providers, as well as customers and other entities with which we conduct business. Prolonged constraints to the distribution chain could lead to additionalrepeated shut-ins and/or increasedother production curtailment from certain of our US onshore wells in the future, further preventing us from producing our proved reserves. Additionally, these supply and demand dynamics have, and could again in the future, lead to negative commodity prices in the US, such as was the case with the May 2020 futures contracts whereby NYMEX WTI crude oil futures pricing was negative for one day in April 2020 driven by the contracts trading deadline with a physical settlement and buyers with available crude oil storage capacity being limited. In response to the current environment, certain domestic state regulators and commissions are considering measures that could, among other things, enforce state-wide limitations on crude oil production. Our future production levels could be negatively impacted if state or federal governments were to implement such production limitations in the future.
Additionally, reduced demand and increased commodity price volatility have contributed to increased short-term competition amongst fuel alternatives in the Eastern Mediterranean, where spot coal and spot LNG prices could temporarily behave recently traded below prices in our long-term natural gas sales and purchase agreements.
Our future access to capital, as well as that of our partners and contractors, could be limited due to tightening capital markets that could delay or inhibit development of our property interests. Some of our longer-term projects require significant investment and, as a result of the current commodity price environment, we have delayed the majority of expenditures under our exploration program. If commodity prices do not improve, our long-term projects may be further delayed due to capital constraints. In addition to the delay of certain projects, if commodity prices do not improve, we could choose not to develop certain of our reserves, even in areas where reserves are known to exist.
The COVID-19 pandemic could potentially further impact our global workforce and operations. The infection of key personnel, and/or the infection of a significant portion of our workforce, could result in business continuity and productivity disruptions. In addition, certain of our personnel and contractors work in field or remote locations, including offshore platforms and facilities. An outbreak of COVID-19 at one of these locations, such as on an offshore platform or facility, could result in the cessation of operations to protect personnel and assets. Any such events could have a material adverse impact on our business, financial condition and results of operations.
The majority of our workforce is workingcontinues to work remotely until the risks of COVID-19 are minimized. Additionally, in response to reduced development and activity levels stemming from the commodity price environment, we have placed a number of employees on furlough or part-time work programs. A remote workforce, combined with employee workforce reduction programs, could introduce risks to achieving business objectives and/or the ability to maintain our controls and procedures.
Further, containment measures have been implemented to mitigate the spread of COVID-19, there is the risk that reduced demand could continue should there be wide-spread and sustained adoption of certain behavioral changes, such as reduced travel and work from home policies, among others. Such behavioral changes, and perceived benefits to the environment, have recently been cited by groups opposing the oil and gas industry as cause for future long-term global adoption. We could be negatively impacted should there be wide-spread and sustained changes in consumer behavioral patterns that result in reduced demand for and consumption of energy commodities.
The impacts of COVID-19 and the significant drop in commodity prices have had an unprecedented impact on the global economy and our business. Impacts of the COVID-19 pandemic and/or any worsening of the global business and economic environment, may heighten or exacerbate many of the other risks disclosed in Item 1A. Risk Factors of our Annual Report on Form 10-K for the year ended December 31, 2019. We are unable to predict all potential impacts to our business, the severity of such impacts or the duration. These risks could have a material adverse impact on our financial position, results of operations and cash flows.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
The following table sets forth, for the periods indicated, our share repurchase activity: |
| | | | | | | | | | | | | |
Period | Total Number of Shares Purchased(1) | | Average Price Paid Per Share | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(2) | | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs |
| | | | | | | (millions) |
1/1/2020 - 1/31/2020 | — |
| | $ | — |
| | — |
| | |
2/1/2020 - 2/29/2020 | 450,814 |
| | 19.81 |
| | — |
| | |
3/1/2020 - 3/31/2020 | 4,211 |
| | 10.74 |
| | — |
| | |
Total | 455,025 |
| | $ | 19.73 |
| | — |
| | $ | 455 |
|
|
| | | | | | | | | | | | | |
Period | Total Number of Shares Purchased(1) | | Average Price Paid Per Share | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(2) | | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs |
| | | | | | | (millions) |
4/1/2020 - 4/30/2020 | 16,799 |
| | $ | 9.52 |
| | — |
| | |
5/1/2020 - 5/31/2020 | 3,143 |
| | 8.80 |
| | — |
| | |
6/1/2020 - 6/30/2020 | — |
| | — |
| | — |
| | |
Total | 19,942 |
| | $ | 9.40 |
| | — |
| | $ | 455 |
|
| |
(1) | Stock repurchases during the period related to common stock received by us from employees for the payment of withholding taxes due on shares of common stock issued under stock-based compensation plans. |
| |
(2) | During firstsecond quarter 2020, we did not repurchase shares under the $750 million share repurchase program, authorized by the Board of Directors and announced on February 15, 2018, which expires December 31, 2020. |
Item 3. Defaults Upon Senior Securities
None.
Item 4. Mine Safety Disclosures
Not applicable.
Item 5. Other Information
None.
|
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Exhibit Number | | Exhibit |
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2.1 | | |
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3.1 | | |
| | |
3.2 | | |
| | |
10.1* | | |
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10.2* | |
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| | |
10.3* | |
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10.4* | | |
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31.1 | | |
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31.2 | | |
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32.1 | | |
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32.2 | | |
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101 | | The following materials from Noble Energy, Inc.'s Quarterly Report on Form 10-Q for the quarter ended March 31,June 30, 2020 formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Statements of Operations and Comprehensive Loss; (ii) Consolidated Balance Sheets; (iii) Consolidated Statements of Cash Flows; (iv) Consolidated Statements of Equity; and (v) Notes to Consolidated Financial Statements. |
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104 | | Cover Page Interactive Data File (formatted in iXBRL and contained in Exhibit 101). |
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* | Management contract or compensatory plan or arrangement required to be filed as an exhibit hereto. |
Signatures
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
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| | | | NOBLE ENERGY, INC. |
| | | | (Registrant) |
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Date | | May 8,August 3, 2020 | | By: /s/ Kenneth M. Fisher |
| | | | Kenneth M. Fisher Executive Vice President, Chief Financial Officer |