UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 20172018
OR
o 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 (Registrant’s telephone number, including area code) |
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 ý No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files).
Yes ý No o
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 x | Accelerated filer o | Non-accelerated filer o | Smaller reporting company o | Emerging growth company o |
| | | (Do not check if a smaller reporting 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. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o No ý
As of June 30, 2017,2018, there were 486,545,041483,118,790 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 LossIncome
(millions, except per share amounts)
(unaudited) |
| | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| | 2018 | | 2017 | | 2018 | | 2017 |
| Revenues | | | | | | | |
| Oil, NGL and Gas Sales | $ | 1,100 |
| | $ | 1,017 |
| | $ | 2,273 |
| | $ | 2,011 |
|
| Income from Equity Method Investees and Other | 130 |
| | 42 |
| | 243 |
| | 84 |
|
| Total | 1,230 |
| | 1,059 |
| | 2,516 |
| | 2,095 |
|
| Costs and Expenses | |
| | |
| | | | |
| Production Expense | 292 |
| | 283 |
| | 613 |
| | 586 |
|
| Exploration Expense | 29 |
| | 30 |
| | 64 |
| | 72 |
|
| Depreciation, Depletion and Amortization | 465 |
| | 503 |
| | 933 |
| | 1,031 |
|
| Loss on Marcellus Shale Upstream Divestiture | — |
| | 2,322 |
| | — |
| | 2,322 |
|
| Gain on Divestitures, Net | (78 | ) | | — |
| | (666 | ) | | — |
|
| Asset Impairments | — |
| | — |
| | 168 |
| | — |
|
| General and Administrative | 105 |
| | 103 |
| | 209 |
| | 202 |
|
| Other Operating Expense, Net | 74 |
| | 118 |
| | 144 |
| | 147 |
|
| Total | 887 |
| | 3,359 |
| | 1,465 |
| | 4,360 |
|
| Operating Income (Loss) | 343 |
| | (2,300 | ) | | 1,051 |
| | (2,265 | ) |
| Other (Income) Expense | |
| | |
| | | | |
| Loss (Gain) on Commodity Derivative Instruments | 249 |
| | (57 | ) | | 328 |
| | (167 | ) |
| Interest, Net of Amount Capitalized | 73 |
| | 96 |
| | 146 |
| | 183 |
|
| Other Non-Operating Expense (Income), Net | 11 |
| | (5 | ) | | 24 |
| | (6 | ) |
| Total | 333 |
| | 34 |
| | 498 |
| | 10 |
|
| Income (Loss) Before Income Taxes | 10 |
| | (2,334 | ) | | 553 |
| | (2,275 | ) |
| Income Tax Expense (Benefit) | 16 |
| | (836 | ) | | (15 | ) | | (824 | ) |
| Net (Loss) Income and Comprehensive (Loss) Income Including Noncontrolling Interests | (6 | ) | | (1,498 | ) | | 568 |
| | (1,451 | ) |
| Less: Net Income and Comprehensive Income Attributable to Noncontrolling Interests | 17 |
| | 14 |
| | 37 |
| | 25 |
|
| Net (Loss) Income and Comprehensive Income (Loss) Attributable to Noble Energy | $ | (23 | ) | | $ | (1,512 | ) | | $ | 531 |
| | $ | (1,476 | ) |
| | | | | | | | |
| Net (Loss) Income Attributable to Noble Energy per Common Share | | | | | | | |
| Basic | $ | (0.05 | ) | | $ | (3.20 | ) | | $ | 1.09 |
| | $ | (3.27 | ) |
| Diluted | $ | (0.05 | ) | | $ | (3.20 | ) | | $ | 1.09 |
| | $ | (3.27 | ) |
| Weighted Average Number of Common Shares Outstanding | | | | | | | |
| Basic | 484 |
| | 472 |
| | 485 |
| | 452 |
|
| Diluted | 484 |
| | 472 |
| | 487 |
| | 452 |
|
|
| | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| Revenues | | | | | | | |
| Oil, NGL and Gas Sales | $ | 1,017 |
| | $ | 823 |
| | $ | 2,011 |
| | $ | 1,528 |
|
| Income from Equity Method Investees and Other | 42 |
| | 24 |
| | 84 |
| | 43 |
|
| Total | 1,059 |
| | 847 |
| | 2,095 |
| | 1,571 |
|
| Costs and Expenses | |
| | |
| | | | |
| Production Expense | 283 |
| | 280 |
| | 586 |
| | 556 |
|
| Exploration Expense | 30 |
| | 89 |
| | 72 |
| | 252 |
|
| Depreciation, Depletion and Amortization | 503 |
| | 622 |
| | 1,031 |
| | 1,239 |
|
| Loss on Marcellus Shale Upstream Divestiture | 2,322 |
| | — |
| | 2,322 |
| | — |
|
| General and Administrative | 103 |
| | 107 |
| | 202 |
| | 198 |
|
| Other Operating Expense, Net | 118 |
| | 11 |
| | 147 |
| | 10 |
|
| Total | 3,359 |
| | 1,109 |
| | 4,360 |
| | 2,255 |
|
| Operating Loss | (2,300 | ) | | (262 | ) | | (2,265 | ) | | (684 | ) |
| Other Expense (Income) | |
| | |
| | | | |
| (Gain) Loss on Commodity Derivative Instruments | (57 | ) | | 151 |
| | (167 | ) | | 107 |
|
| Interest, Net of Amount Capitalized | 96 |
| | 78 |
| | 183 |
| | 157 |
|
| Other Non-Operating (Income) Expense, Net | (5 | ) | | 7 |
| | (6 | ) | | 3 |
|
| Total | 34 |
| | 236 |
| | 10 |
| | 267 |
|
| Loss Before Income Taxes | (2,334 | ) | | (498 | ) | | (2,275 | ) | | (951 | ) |
| Income Tax Benefit | (836 | ) | | (183 | ) | | (824 | ) | | (349 | ) |
| Net Loss and Comprehensive Loss Including Noncontrolling Interests | (1,498 | ) | | (315 | ) | | (1,451 | ) | | (602 | ) |
| Less: Net Income and Comprehensive Income Attributable to Noncontrolling Interests | 14 |
| | — |
| | 25 |
| | — |
|
| Net Loss and Comprehensive Loss Attributable to Noble Energy | $ | (1,512 | ) | | $ | (315 | ) | | $ | (1,476 | ) | | $ | (602 | ) |
| | | | | | | | |
| Net Loss Attributable to Noble Energy per Common Share | | | | | | | |
| Basic and Diluted | $ | (3.20 | ) | | $ | (0.73 | ) | | $ | (3.27 | ) | | $ | (1.40 | ) |
| | | | | | | | |
| Weighted Average Number of Common Shares Outstanding | | | | | | | |
| Basic and Diluted | 472 |
| | 430 |
| | 452 |
| | 429 |
|
The accompanying notes are an integral part of these financial statements.
Noble Energy, Inc.
Consolidated Balance Sheets
(millions)
(unaudited)
|
| | | | | | | |
| | June 30,
2017 | | December 31,
2016 |
| ASSETS | | | |
| Current Assets | | | |
| Cash and Cash Equivalents | $ | 540 |
| | $ | 1,180 |
|
| Accounts Receivable, Net | 699 |
| | 615 |
|
| Other Current Assets | 338 |
| | 160 |
|
| Total Current Assets | 1,577 |
| | 1,955 |
|
| Property, Plant and Equipment | |
| | |
|
| Oil and Gas Properties (Successful Efforts Method of Accounting) | 29,928 |
| | 30,355 |
|
| Property, Plant and Equipment, Other | 911 |
| | 909 |
|
| Total Property, Plant and Equipment, Gross | 30,839 |
| | 31,264 |
|
| Accumulated Depreciation, Depletion and Amortization | (12,563 | ) | | (12,716 | ) |
| Total Property, Plant and Equipment, Net | 18,276 |
| | 18,548 |
|
| Goodwill | 1,289 |
| | — |
|
| Other Noncurrent Assets | 432 |
| | 508 |
|
| Total Assets | $ | 21,574 |
| | $ | 21,011 |
|
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | |
| Current Liabilities | | | |
|
| Accounts Payable - Trade | $ | 1,086 |
| | $ | 736 |
|
| Other Current Liabilities | 509 |
| | 742 |
|
| Total Current Liabilities | 1,595 |
| | 1,478 |
|
| Long-Term Debt | 7,133 |
| | 7,011 |
|
| Deferred Income Taxes | 1,469 |
| | 1,819 |
|
| Other Noncurrent Liabilities | 1,279 |
| | 1,103 |
|
| Total Liabilities | 11,476 |
| | 11,411 |
|
| Commitments and Contingencies |
| |
|
|
| Shareholders’ Equity | |
| | |
|
| Preferred Stock - Par Value $1.00 per share; 4 Million Shares Authorized; None Issued | — |
| | — |
|
| Common Stock - Par Value $0.01 per share; 1 Billion Shares Authorized; 529 Million and 471 Million Shares Issued, respectively | 5 |
| | 5 |
|
| Additional Paid in Capital | 8,399 |
| | 6,450 |
|
| Accumulated Other Comprehensive Loss | (30 | ) | | (31 | ) |
| Treasury Stock, at Cost; 39 Million and 38 Million Shares, respectively | (727 | ) | | (692 | ) |
| Retained Earnings | 1,988 |
| | 3,556 |
|
| Noble Energy Share of Equity | 9,635 |
| | 9,288 |
|
| Noncontrolling Interests | 463 |
| | 312 |
|
| Total Equity | 10,098 |
| | 9,600 |
|
| Total Liabilities and Equity | $ | 21,574 |
| | $ | 21,011 |
|
The accompanying notes are an integral part of these financial statements.
Noble Energy, Inc.
Consolidated Balance Sheets
(millions)
(unaudited)
|
| | | | | | | |
| | June 30,
2018 | | December 31,
2017 |
| ASSETS | | | |
| Current Assets | | | |
| Cash and Cash Equivalents | $ | 621 |
| | $ | 675 |
|
| Accounts Receivable, Net | 743 |
| | 748 |
|
| Other Current Assets | 187 |
| | 780 |
|
| Total Current Assets | 1,551 |
| | 2,203 |
|
| Property, Plant and Equipment | |
| | |
|
| Oil and Gas Properties (Successful Efforts Method of Accounting) | 28,334 |
| | 29,678 |
|
| Property, Plant and Equipment, Other | 896 |
| | 879 |
|
| Total Property, Plant and Equipment, Gross | 29,230 |
| | 30,557 |
|
| Accumulated Depreciation, Depletion and Amortization | (11,313 | ) | | (13,055 | ) |
| Total Property, Plant and Equipment, Net | 17,917 |
| | 17,502 |
|
| Other Noncurrent Assets | 984 |
| | 461 |
|
| Goodwill | 1,402 |
| | 1,310 |
|
| Total Assets | $ | 21,854 |
| | $ | 21,476 |
|
| LIABILITIES AND EQUITY | | | |
| Current Liabilities | | | |
|
| Accounts Payable – Trade | $ | 1,308 |
| | $ | 1,161 |
|
| Other Current Liabilities | 745 |
| | 578 |
|
| Total Current Liabilities | 2,053 |
| | 1,739 |
|
| Long-Term Debt | 6,555 |
| | 6,746 |
|
| Deferred Income Taxes | 970 |
| | 1,127 |
|
| Other Noncurrent Liabilities | 995 |
| | 1,245 |
|
| Total Liabilities | 10,573 |
| | 10,857 |
|
| Commitments and Contingencies |
| |
|
|
| Shareholders’ Equity | |
| | |
|
| Preferred Stock - Par Value $1.00 per share; 4 Million Shares Authorized; None Issued | — |
| | — |
|
| Common Stock - Par Value $0.01 per share; 1 Billion Shares Authorized; 526 Million and 529 Million Shares Issued, respectively | 5 |
| | 5 |
|
| Additional Paid in Capital | 8,329 |
| | 8,438 |
|
| Accumulated Other Comprehensive Loss | (28 | ) | | (30 | ) |
| Treasury Stock, at Cost; 39 Million Shares | (731 | ) | | (725 | ) |
| Retained Earnings | 2,677 |
| | 2,248 |
|
| Noble Energy Share of Equity | 10,252 |
| | 9,936 |
|
| Noncontrolling Interests | 1,029 |
| | 683 |
|
| Total Equity | 11,281 |
| | 10,619 |
|
| Total Liabilities and Equity | $ | 21,854 |
| | $ | 21,476 |
|
The accompanying notes are an integral part of these financial statements.
Noble Energy, Inc.
Consolidated Statements of Cash Flows
(millions)
(unaudited)
| | | | Six Months Ended June 30, | Six Months Ended June 30, |
| | 2017 | | 2016 | 2018 | | 2017 |
| Cash Flows From Operating Activities | | | | | | |
| Net Loss Including Noncontrolling Interests | $ | (1,451 | ) | | $ | (602 | ) | |
| Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities | | | | |
| Net Income (Loss) Including Noncontrolling Interests | | $ | 568 |
| | $ | (1,451 | ) |
| Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities | | | | |
| Depreciation, Depletion and Amortization | 1,031 |
| | 1,239 |
| 933 |
| | 1,031 |
|
| Loss on Marcellus Shale Upstream Divestiture | 2,322 |
| | — |
| — |
| | 2,322 |
|
| Gain on Divestitures, Net | | (666 | ) | | — |
|
| Asset Impairments | | 168 |
| | — |
|
| Deferred Income Tax Benefit | (873 | ) | | (414 | ) | (164 | ) | | (873 | ) |
| Dry Hole Cost | — |
| | 114 |
| |
| Gain on Extinguishment of Debt | — |
| | (80 | ) | |
| (Gain) Loss on Commodity Derivative Instruments | (167 | ) | | 107 |
| |
| Net Cash Received in Settlement of Commodity Derivative Instruments | 14 |
| | 322 |
| |
| Loss (Gain) on Commodity Derivative Instruments | | 328 |
| | (167 | ) |
| Net Cash (Paid) Received in Settlement of Commodity Derivative Instruments | | (93 | ) | | 14 |
|
| Stock Based Compensation | 67 |
| | 40 |
| 35 |
| | 67 |
|
| Other Adjustments for Noncash Items Included in Income | 33 |
| | 95 |
| |
| Other Adjustments for Noncash Items Included in Income (Loss) | | 22 |
| | 33 |
|
| Changes in Operating Assets and Liabilities | | | | | | |
| Increase in Accounts Receivable | (123 | ) | | (6 | ) | |
| Increase (Decrease) in Accounts Payable | 120 |
| | (232 | ) | |
| Decrease (Increase) in Accounts Receivable | | 76 |
| | (123 | ) |
| (Decrease) Increase in Accounts Payable | | (24 | ) | | 120 |
|
| Decrease in Current Income Taxes Payable | (42 | ) | | (51 | ) | 3 |
| | (42 | ) |
| Other Current Assets and Liabilities, Net | (42 | ) | | (51 | ) | (58 | ) | | (42 | ) |
| Other Operating Assets and Liabilities, Net | (12 | ) | | (41 | ) | (49 | ) | | (12 | ) |
| Net Cash Provided by Operating Activities | 877 |
|
| 440 |
| 1,079 |
|
| 877 |
|
| Cash Flows From Investing Activities |
|
| |
|
| | | |
| Additions to Property, Plant and Equipment | (1,215 | ) | | (812 | ) | (1,782 | ) | | (1,215 | ) |
| Proceeds from Sale of 7.5% Interest in Tamar Field | | 484 |
| | — |
|
| Proceeds from Sale of CONE Gathering LLC and CNX Midstream Partners Common Units | | 443 |
| | — |
|
| Proceeds from Gulf of Mexico Divestiture | | 383 |
| | — |
|
| Proceeds from Marcellus Shale Upstream Divestiture | 1,028 |
| | — |
| — |
| | 1,028 |
|
| Clayton Williams Energy Acquisition | (616 | ) | | — |
| — |
| | (616 | ) |
| Other Acquisitions | (321 | ) | | — |
| |
| Acquisitions, Net of Cash Acquired | | (650 | ) | | (351 | ) |
| Proceeds from Other Divestitures | | 72 |
| | 101 |
|
| Additions to Equity Method Investments | (68 | ) | | (6 | ) | — |
| | (68 | ) |
| Proceeds from Divestitures and Other | 101 |
| | 767 |
| |
| Other | | — |
| | — |
|
| Net Cash Used in Investing Activities | (1,091 | ) |
| (51 | ) | (1,050 | ) |
| (1,121 | ) |
| Cash Flows From Financing Activities | | | | | | |
| Dividends Paid, Common Stock | (92 | ) | | (86 | ) | (102 | ) | | (92 | ) |
| Purchase and Retirement of Common Stock | | (130 | ) | | — |
|
| Proceeds from Noble Midstream Services Revolving Credit Facility | 195 |
| | — |
| 610 |
| | 195 |
|
| Repayment of Noble Midstream Services Revolving Credit Facility | (5 | ) | | — |
| (165 | ) | | (5 | ) |
| Proceeds from Term Loan Facility | — |
| | 1,400 |
| |
| Contributions from Noncontrolling Interest Owners | | 331 |
| | — |
|
| Issuance of Noble Midstream Partners Common Units, Net of Offering Costs | 138 |
| | — |
| — |
| | 138 |
|
| Proceeds from Revolving Credit Facility | 1,310 |
| | — |
| 905 |
| | 1,310 |
|
| Repayment of Revolving Credit Facility | (1,310 | ) | | — |
| (1,135 | ) | | (1,310 | ) |
| Repayment of Clayton Williams Energy Long-term Debt | (595 | ) | | — |
| — |
| | (595 | ) |
| Repayment of Senior Notes | — |
| | (1,383 | ) | (384 | ) | | — |
|
| Other | (67 | ) | | (48 | ) | (51 | ) | | (67 | ) |
| Net Cash Used in Financing Activities | (426 | ) |
| (117 | ) | (121 | ) |
| (426 | ) |
| (Decrease) Increase in Cash and Cash Equivalents | (640 | ) |
| 272 |
| |
| Cash and Cash Equivalents at Beginning of Period | 1,180 |
| | 1,028 |
| |
| Cash and Cash Equivalents at End of Period | $ | 540 |
| | $ | 1,300 |
| |
| Decrease in Cash, Cash Equivalents, and Restricted Cash | | (92 | ) |
| (670 | ) |
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | | 713 |
| | 1,210 |
|
| Cash, Cash Equivalents, and Restricted Cash at End of Period | | $ | 621 |
| | $ | 540 |
|
The accompanying notes are an integral part of these financial statements.
Noble Energy, Inc.
Consolidated Statements of Equity
(millions)
(unaudited)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Attributable to Noble Energy | | | | |
| | Common Stock | | Additional Paid in Capital | | Accumulated Other Comprehensive Loss | | Treasury Stock at Cost | | Retained Earnings | | Non- controlling Interests | | Total Equity |
| December 31, 2017 | $ | 5 |
| | $ | 8,438 |
| | $ | (30 | ) | | $ | (725 | ) | | $ | 2,248 |
| | $ | 683 |
| | $ | 10,619 |
|
| Net Income | — |
| | — |
| | — |
| | — |
| | 531 |
| | 37 |
| | 568 |
|
| Stock-based Compensation | — |
| | 46 |
| | — |
| | — |
| | — |
| | — |
| | 46 |
|
| Dividends (21 cents per share) | — |
| | — |
| | — |
| | — |
| | (102 | ) | | — |
| | (102 | ) |
| Purchase and Retirement of Common Stock | — |
| | (130 | ) | | — |
| | — |
| | — |
| | — |
| | (130 | ) |
| Clayton Williams Energy Acquisition | — |
| | (25 | ) | | — |
| | — |
| | — |
| | — |
| | (25 | ) |
| Distributions to Noncontrolling Interest Owners | — |
| | — |
| | — |
| | — |
| | — |
| | (22 | ) | | (22 | ) |
| Contributions from Noncontrolling Interest Owners | — |
| | — |
| | — |
| | — |
| | — |
| | 331 |
| | 331 |
|
| Other | — |
| | — |
| | 2 |
| | (6 | ) | | — |
| | — |
| | (4 | ) |
| June 30, 2018 | $ | 5 |
| | $ | 8,329 |
| | $ | (28 | ) | | $ | (731 | ) | | $ | 2,677 |
| | $ | 1,029 |
| | $ | 11,281 |
|
| | | | | | | | | | | | | | |
| December 31, 2016 | $ | 5 |
| | $ | 6,450 |
| | $ | (31 | ) | | $ | (692 | ) | | $ | 3,556 |
| | $ | 312 |
| | $ | 9,600 |
|
| Net (Loss) Income | — |
| | — |
| | — |
| | — |
| | (1,476 | ) | | 25 |
| | (1,451 | ) |
| Clayton Williams Energy Acquisition | — |
| | 1,876 |
| | — |
| | (25 | ) | | — |
| | — |
| | 1,851 |
|
| Stock-based Compensation | — |
| | 65 |
| | — |
| | — |
| | — |
| | — |
| | 65 |
|
| Dividends (20 cents per share) | — |
| | — |
| | — |
| | — |
| | (92 | ) | | — |
| | (92 | ) |
| Issuance of Noble Midstream Partners Common Units, Net of Offering Costs | — |
| | — |
| | — |
| | — |
| | — |
| | 138 |
| | 138 |
|
| Distributions to Noncontrolling Interest Owners | — |
| | — |
| | — |
| | — |
| | — |
| | (12 | ) | | (12 | ) |
| Other | — |
| | 8 |
| | 1 |
| | (10 | ) | | — |
| | — |
| | (1 | ) |
| June 30, 2017 | $ | 5 |
| | $ | 8,399 |
| | $ | (30 | ) | | $ | (727 | ) | | $ | 1,988 |
| | $ | 463 |
| | $ | 10,098 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Attributable to Noble Energy | | | | |
| | Common Stock | | Additional Paid in Capital | | Accumulated Other Comprehensive Loss | | Treasury Stock at Cost | | Retained Earnings | | Non- controlling Interests | | Total Equity |
| December 31, 2016 | $ | 5 |
| | $ | 6,450 |
| | $ | (31 | ) | | $ | (692 | ) | | $ | 3,556 |
| | $ | 312 |
| | $ | 9,600 |
|
| Net (Loss) Income | — |
| | — |
| | — |
| | — |
| | (1,476 | ) | | 25 |
| | (1,451 | ) |
| Clayton Williams Energy Acquisition | — |
| | 1,876 |
| | — |
| | (25 | ) | | — |
| | — |
| | 1,851 |
|
| Stock-based Compensation | — |
| | 65 |
| | — |
| | — |
| | — |
| | — |
| | 65 |
|
| Dividends (20 cents per share) | — |
| | — |
| | — |
| | — |
| | (92 | ) | | — |
| | (92 | ) |
| Issuance of Noble Midstream Partners Common Units, Net of Offering Costs | — |
| | — |
| | — |
| | — |
| | — |
|
| 138 |
| | 138 |
|
| Distributions to Noncontrolling Interest Owners | — |
| | — |
| | — |
| | — |
| | — |
| | (12 | ) | | (12 | ) |
| Other | — |
| | 8 |
| | 1 |
| | (10 | ) | | — |
| | — |
| | (1 | ) |
| June 30, 2017 | $ | 5 |
| | $ | 8,399 |
| | $ | (30 | ) | | $ | (727 | ) | | $ | 1,988 |
| | $ | 463 |
| | $ | 10,098 |
|
| | | | | | | | | | | | | | |
| December 31, 2015 | $ | 5 |
| | $ | 6,360 |
| | $ | (33 | ) | | $ | (688 | ) | | $ | 4,726 |
| | $ | — |
| | $ | 10,370 |
|
| Net Loss | — |
| | — |
| | — |
| | — |
| | (602 | ) | | — |
| | (602 | ) |
| Stock-based Compensation | — |
| | 36 |
| | — |
| | — |
| | — |
| | — |
| | 36 |
|
| Dividends (20 cents per share) | — |
| | — |
| | — |
| | — |
| | (86 | ) | | — |
| | (86 | ) |
| Other | — |
| | 2 |
| | 1 |
| | (8 | ) | | — |
| | — |
| | (5 | ) |
| June 30, 2016 | $ | 5 |
| | $ | 6,398 |
| | $ | (32 | ) | | $ | (696 | ) | | $ | 4,038 |
| | $ | — |
| | $ | 9,713 |
|
The accompanying notes are an integral part of these 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 DJ Basin, Delaware Basin, Eagle Ford Shale and Marcellus Shale (until June 2017); US offshore Gulf of Mexico;Mexico (until April 2018); Eastern Mediterranean; and West Africa. Our Midstream segment owns, operates, develops and acquires domestic midstream infrastructure assets with current focus areas being the DJ and Delaware Basins.
Note 2. Basis of Presentation
Presentation The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the US (US GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and notes required by US GAAP for complete financial statements. The accompanying consolidated financial statements at June 30, 20172018 and December 31, 20162017 and for the three and six months ended June 30, 20172018 and 20162017 contain all normally recurring adjustments considered necessary for a fair presentation of our financial position, results of operations, cash flows and shareholders’ equity for such periods. For the periods presented, activity within other comprehensive income or loss was de minimis; therefore, net income or loss is materially consistent with comprehensive income or loss.
In Note 11. Segment Information, we report a new Midstream segment, established second quarter 2017, and present prior period amounts on a comparable basis. Certain other prior-period amounts have been reclassified to conform to the current period presentation.Operating results for the three and six months ended June 30, 20172018 are not necessarily indicative of the results that may be expected for the year ending December 31, 2017.2018.
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, 2016.2017.
ConsolidationOur consolidated financial statements include our accounts, the accounts of subsidiaries which Noble Energy wholly owns, and the accounts of Noble Midstream Partners, which is considered a variable interest entity (VIE) for which Noble Energy is the primary beneficiary. In addition, we use the equity method of accounting for investments in entities that we do not control, but over which we exert significant influence. All significant intercompany balances and transactions have been eliminated upon consolidation.
Consolidated VIENoble Energy has determined that the partners with equity at risk in Noble Midstream Partners LP (NYSE: NBLX) (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 VIE. 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.
Goodwill As of June 30, 2017, our consolidated balance sheet includes goodwill of $1.3 billion. This goodwill resulted from the acquisition (Clayton Williams Energy Acquisition) of Clayton Williams Energy, Inc. (Clayton Williams Energy) completed on April 24, 2017, and represents the excess of the consideration paid for Clayton Williams Energy over the net amounts assigned to identifiable assets acquired and liabilities assumed. See Note 3. Clayton Williams Energy Acquisition.Goodwill is not amortized to earnings but is qualitatively assessed for impairment. We assess goodwill for impairment annually during the third quarter, or more frequently as circumstances require, at the reporting unit level. If, based on our qualitative procedures, it is more likely than not that the fair value of the reporting unit is less than its carrying amount, we perform the two-step goodwill impairment test. The two-step goodwill impairment test is also performed whenever events or changes in circumstances indicate that the carrying value may not be recoverable. It is possible that goodwill could become impaired in the future if commodity prices or other economic factors decline. See Recently Issued Accounting Standards – Intangibles – Goodwill and Other: Simplifying the Test for Goodwill Impairment, below.
If, in the future, we dispose of a reporting unit or a portion of a reporting unit that constitutes a business, we will include goodwill associated with that business in the carrying amount of the business in order to determine the gain or loss on disposal. The amount of goodwill allocated to the carrying amount of a business can significantly impact the amount of gain or loss recognized on the sale of that business. The amount of goodwill to be included in that carrying amount will be based on the relative fair value of the business to be disposed of and the portion of the reporting unit that will be retained.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Exit CostsWe recognize the fair value of a liability for an exit cost in the period in which a liability is incurred. Our exit costs for second quarter 2017 relate primarily to estimated costs associated with a retained Marcellus Shale firm transportation contract, for which we accrued an exit liability at June 30, 2017.
The recognition and fair value estimation of a liability requires that management take into account certain estimates and assumptions such as: the determination of whether a cease-use date has occurred (defined as the date the entity ceases using the right conveyed by the contract, for example, the right to use a leased property or to receive future goods or services); the amount, if any, of economic benefit that is expected to be obtained from a contract through partial use or release; and our estimate of costs that will continue to be incurred under the contract. We record the liability at estimated fair value, based on expected future cash outflows required to satisfy the obligation, net of estimated recoveries, and discounted. After initial recording, the liability increases for the passage of time. Exit costs, and associated accretion expense, are included in operating expense in our consolidated statements of operations. See Note 4. Acquisitions and Divestitures and Note 12. Commitments and Contingencies.EstimatesThe preparation of consolidated financial statements in conformity with US GAAP requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ significantly from those estimates. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment.
Reserves Estimates Estimated quantitiesInvestment in Shares of crude oil, natural gasTamar Petroleum We account for our investment in shares of Tamar Petroleum Ltd. at fair value and natural gas liquids (NGL) reserves arerecord changes in fair value in other non-operating expense (income), net in our consolidated statements of operations. See Note 3. Acquisitions and Divestitures and Note 6. Fair Value Measurements and Disclosures.Intangible Assets Intangible assets consist of customer contracts and relationships acquired by Noble Midstream Partners in its acquisition of Saddle Butte Rockies Midstream, LLC and affiliates (collectively, Saddle Butte). We recorded the most significantintangible assets at their estimated fair values at the date of our estimates. There are numerous uncertainties inherentacquisition. Amortization is calculated using the straight-line method, which reflects the pattern in estimating quantities of proved crude oil, natural gas and NGL reserves. The accuracy of any reserves estimatewhich the estimated economic benefit is a functionexpected to be received over the estimated useful life of the qualityintangible asset, which is currently over periods of available engineering and geoscience information and also interpretationseven to 13 years. As of June 30, 2018, the gross book value of the provided data. Asintangible asset was $340 million. Amortization expense of $9 million and $14 million for the three and six months ended June 30, 2018, respectively, is included in depreciation, depletion and amortization expense in our consolidated statements of operations. Intangible assets with finite useful lives are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. See Note 3. Acquisitions and Divestitures. Stock Repurchase Program On February 15, 2018, we announced that the Company's Board of Directors authorized a result, reserves estimates$750 million share repurchase program which expires December 31, 2020. All purchases will be made from time to time in the open market or private transactions, depending on market conditions, and may be different from the quantities of crude oil, natural gas and NGLs that are ultimately recovered.
discontinued at any time. During second quarter 2017, we recorded the following significant changes in our proved reserves estimates:
Leviathan Field We recorded proved undeveloped reserves of 551 MMBoe, net, for the Leviathan field, offshore Israel, upon approval and sanction of the first phasesix months of development,2018, we repurchased and are expecting to initiate natural gas production by the endretired 1.8 million shares and 4.0 million shares of 2019.
common stock at an average purchase price of $35.15 per share and $32.41 per share, respectively.Delaware Basin We recorded net proved reserves of approximately 86 MMBoe, of which approximately 17 MMBoe are proved developed reserves and 69 MMBoe are proved undeveloped reserves as of June 30, 2017 related to the Clayton Williams Energy Acquisition.
Marcellus Shale The Marcellus Shale upstream divestiture resulted in a decrease in net proved reserves of approximately 241 MMBoe as of June 30, 2017, of which approximately 190 MMBoe were proved developed reserves and 51 MMBoe were proved undeveloped reserves.
Recently Issued Accounting Standards
Revenue RecognitionIn May 2014, the FASB issued Accounting Standards Update No. 2014-09 (ASU 2014-09), which creates TopicASC 606, Revenue from Contracts with Customers. In summary,Our revenue recognition would occur upon the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Additionally, ASU 2014-09 requires enhanced financial statement disclosures over revenue recognition.
The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. We are performing an initial review of contracts for each of our revenue streams and developing accounting policies to address the provisions of the ASU. Currently, we do not have any contracts that would require a changederived from the entitlements method, historically used for certain domesticsale of crude oil, NGL and natural gas sales,production primarily to the sales method of accounting.crude oil refining companies, midstream marketing companies, marketers, industrial companies, electric utility companies, independent power producers and cogeneration facilities, among others. We continue to evaluate the impact of ASU on our accounting policies, internal controls, and consolidated financial statements and related disclosures. Whileaccount for revenue in accordance with ASC 606, Revenue from Contracts with Customers (ASC 606), which we have not concluded on the application of this standard, we do not expect a material impact, if any. We will adopt the new standardadopted on January 1, 2018 using the modified retrospective approach with a cumulative adjustment to retained earnings as necessary.
Compensation – Stock Compensation (Topic 718): Scope of Modification Accounting In May 2017, the FASB issued Accounting Standards Update No. 2017-09 (ASU 2017-09) Compensation – Stock Compensation (Topic 718). The purpose of this update is to provide clarity as to which modifications of awards require modification accounting under Topic 718, whereas previously issued guidance frequently resulted in varying interpretations and a diversity of practice. An entity should employ modification accounting unless the following are met: (1) the fair value of the award is the same immediately before and after
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
the award is modified; (2) the vesting conditionsmodified retrospective method. Under ASC 606, performance obligations are the same under both the modified awardunit of account and generally represent distinct goods or services that are promised to customers. For sales of crude oil, NGLs and natural gas, each unit sold is generally considered a distinct good and the original award;related performance obligation is generally satisfied at a point in time. We recognize our sales revenues at a point in time and (3)upon delivery to a customer at the classificationcontractually stated price and for the quantity of product delivered. In Israel, because our contracts are long-term arrangements, we recognize revenues from the sale of natural gas over the life of the modified awardcontract based on the quantity of natural gas delivered.
ASC 606 provides additional clarification related to principal versus agent considerations. Under this guidance, we record revenue on a gross basis if we control a promised good or service before transferring it to a customer. For example, gathering, processing, transportation and fractionation costs incurred before transfer of control to the customer at the tailgate of a plant are accounted for as fulfillment costs and are presented as a component of gathering, transportation and processing expense in our consolidated statements of operations. On the other hand, we record revenue on a net basis if our role is to arrange for another entity to provide the goods or services. For example, costs incurred after control over the product has transferred to the customer, such as at the wellhead or inlet of a plant, are recorded as a reduction of the transaction price received within revenue.
Certain of our contracts for the sale of commodities contain embedded derivatives. We have elected the normal purchases and normal sales scope exception as provided by ASC 815, Derivatives and Hedging, and will account for such contracts in accordance with ASC 606.
In the US, we enter into marketing agreements with our non-operating partners to market and sell their share of production to third parties. We have determined that we act as an agent in such arrangements and account for such arrangements on a net basis.
ASC 606 adoption did not have an impact on the opening balance of retained earnings. The adoption resulted in de minimis increases of $2 million and $7 million to both revenues and expenses for second quarter and the first six months of 2018, respectively, but did not affect operating or net income or operating cash flows. The comparative information for the prior period has not been recast and continues to be reported under the accounting standards in effect for the period. Adoption of the new standard did not impact our financial position, and we do not expect that it will do so going forward.
Changes to the presentation of commodity sales revenue and production expense resulted from our assessment of certain contractual arrangements under principal versus agent guidance and assessment of control under ASC 606. In particular, we have determined that the processor is our customer with regard to the sale of natural gas at the wellhead or the sale of NGLs at the tailgate. This is a change from previous conclusions reached under principal versus agent guidance per ASC 605, Revenue Recognition, where we previously retained control over our production until the sale to the end customer in the downstream markets. As such, effective January 1, 2018, revenues and expenses are presented on a net basis within revenues in our consolidated statements of operations at the time control over production is transferred to the processor under these arrangements.
Following the control model in ASC 606, we determined that we remain the principal in arrangements with the end customers, such as when we take product in-kind at the tailgate and when we are directly responsible for the transportation and marketing of our production in the downstream markets. In such arrangements, we record NGL and natural gas sales and production expense on a gross basis.
Our commodity sale contracts in the US are index-based and, thus, include variable consideration. In accordance with ASC 606, we allocate variable consideration (market price) to the distinct commodities transferred in the period, but not to the future obligations to deliver production. Such allocation represents the amount of consideration to which we are entitled for deliveries of our commodities to-date and represents the value of product delivered to the customer. Therefore, our revenue is recognized at the time of delivery and is the product of the volume delivered and the index-based price for the period.
The following is a summary of our types of revenue arrangements by commodity and geographic location.
EXPLORATION AND PRODUCTION (E&P) REVENUE ARRANGEMENTS
Crude Oil Sale Arrangements – USWe sell the majority of our US crude oil productionunder short-term contracts at market-based prices, adjusted for location, quality and transportation charges. Market-based pricing is based on the price index applicable for the location of the sale.
We sell our crude oil production either at the lease location or in downstream markets. Crude oil production at the lease location is sold through netback arrangements, under which we sell crude oil net of transportation costs incurred by the purchaser. We record revenue, net, at the lease location when the customer receives delivery of the product.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
When we move our crude oil production from the lease location to the downstream markets in the US, we incur gathering and transportation costs, which we consider contract fulfillment activities. Such costs are reported as expense within gathering, transportation and processing expense in the consolidated statements of operations. Revenue from the sale of crude oil in downstream markets is recognized upon delivery, as specified in the contract, when control of the product has transferred to the customer.
In second quarter 2018, we entered into a long-term contract to sell firm quantities of crude oil under index-based prices adjusted by applicable fees, including transportation, insurance, and marketing.
Crude Oil Buy/Sell Transactions – US We enter into buy/sell arrangements that effect a change in location and/or grade with required repurchase of crude oil at a delivery point. The sale and repurchase of crude oil is settled at the same contractually fixed price (before application of transportation and grade deductions) on a net basis. We account for these transactions on a net basis, in accordance with ASC 845, Nonmonetary Transactions. We record the residual transportation fee as transportation expense within gathering, transportation and processing expense in the original award, either equityconsolidated statements of operations.
Crude Oil Sale Arrangements – West AfricaOur share of crude oil and condensate from the Aseng, Alen and Alba fields is sold at market-based prices to Glencore Energy UK Ltd (Glencore Energy). Crude oil is priced at a Dated Brent FOB net realized price achieved by Glencore Energy and is adjusted by applicable fees, including transportation, insurance, and marketing. We recognize revenue on the sale of crude oil to Glencore Energy at the time crude oil cargo is loaded onto the tanker and control transfers to Glencore Energy. We record revenue at the realized price received from Glencore Energy, net of applicable fees.
Natural Gas and NGLs Sale Arrangements – US Certain of our commodity contracts in the US are for the sale of natural gas to processors at prevailing market prices. We evaluate the contract terms of these arrangements to determine whether the processor is a service provider or liability. Regardlessa customer on a contract by contract basis. In arrangements where we determine that we sold our product to the processor, we record revenue when the processor takes physical possession of whether modification accountingthe natural gas and NGLs and in the amount of proceeds expected to be received, net of any fees or deductions charged by the processor.
In other natural gas processing arrangements, we receive natural gas and NGL products "in-kind" after processing at the tailgate of the plant. In these arrangements, we are responsible for the transportation, fractionation and marketing costs of our production. In such cases, we record the sale of natural gas and NGLs and applicable gathering, processing, transportation and fractionation fees on a gross basis at the time the product is utilized, award disclosure requirementsdelivered to the end customer.
Natural Gas Purchase and Sale Arrangements – USWeenter into purchase transactions and separate sale transactions with third parties at prevailing market prices to mitigate unutilized pipeline transportation commitments, primarily related to retained Marcellus Shale firm transportation agreements. Revenues and expenses from the sales and purchases are recorded on a gross basis, as we act as a principal in these transactions by assuming control of the purchased commodity before it is transferred to the customer.
Natural Gas Sale Arrangements – West Africa We sell our share of natural gas production from the Alba field under Topic 718 remain unchanged. ASU 2017-09a long-term contract for $0.25 per MMBtu to a methanol plant, a liquefied petroleum gas (LPG) plant, a liquefied natural gas (LNG) plant and a power generation plant. We recognize revenue upon transfer of control of product to these processors.
Natural Gas Sale Arrangements – Israel Our natural gas sales in Israel are primarily based on long-term contracts with fixed volume commitments over the life of the arrangements. Our performance obligations for the sale of natural gas are satisfied over time using production output to measure progress. The nature of these contracts gives rise to several types of variable consideration, including index-based annual price escalations, commodity-based index pricing, tiered pricing and sales price discounts in periods of volume deficiencies. Additionally, the majority of our sales contracts contain take-or-pay provisions where the customers are required to purchase a contractual minimum over varying time periods. Where the variable consideration is related to market-based pricing or index-based escalations of a fixed base price, we have elected the variable consideration allocation exception pursuant to ASC 606. We record revenue related to the volumes delivered at the contract price at the time of delivery. To date, there have been no impacts of variability in consideration due to tiered pricing, take-or-pay provisions and/or volume deficiency discounts. We believe that any variability due to future sales price adjustments associated with potential volume deficiencies will be effective for annual or any interim periods beginning after December 15, 2017. We do not believe adoption of ASU 2017-09 will have a materialsignificant impact on our financial statements.position or results of operations.
Transaction Price Allocated to Remaining Performance Obligations – Israel Remaining performance obligations represent the transaction price of firm sales arrangements for which volumes have not been delivered. Pursuant to ASC 606, short and long-term interruptible contracts, and long-term dedicated production agreements, are excluded from the disclosure due to uncertainty associated with estimating future production volumes and future market prices. However, certain of our natural gas sales contracts in Israel have fixed annual sales volumes and fixed base pricing with annual index escalations. The following table includes estimated revenues based upon those certain agreements with fixed minimum take-or-pay sales volumes. Our actual future sales volumes under these agreements may exceed future minimum volume commitments.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
|
| | | | | | | | | | | | |
| (millions) | July - Dec 2018 | 2019 | 2020 | Total |
Natural Gas Revenues (1) | $ | 107 |
| $ | 137 |
| $ | 169 |
| $ | 413 |
|
(1) The remaining performance obligations are estimated utilizing the contractual base or floor price provision in effect. Our future revenues from the sale of natural gas under these associated contracts will vary from the amounts presented above due to components of variable consideration above the contractual base or floor provision, such as index-based escalations and market price changes.
MIDSTREAM REVENUE ARRANGEMENTS
Our Midstream segment revenues are derived from fixed fee contract arrangements for gathering, transportation and storage services. We will adopthave determined that our performance obligations for the new standardprovision of such services are satisfied over time using volumes delivered as the measure of progress. ASC 606 adoption did not have an impact on the effective daterecognition, measurement and presentation of January 1, 2018.our midstream revenues and expenses.
Business Combinations: ClarifyingCrude Oil Purchase and Sale Arrangements – USAs part of the DefinitionSaddle Butte acquisition in first quarter 2018, we acquired a pipeline and associated third party contracts which include transactions for the purchase and sale of crude oil with varying counterparties. Revenues and expenses from the sales and purchases are recorded on a BusinessIn January 2017,gross basis as we act as a principal in these transactions by assuming control of the FASB issued Accounting Standards Update No. 2017-01 (ASU 2017-01): Business Combinations – Clarifying the Definition of a Business, that assists in determining whether certain transactions should be accounted for as acquisitions or dispositions of assets or businesses. The amendment provides a screen to be appliedpurchased commodity before it is transferred to the fair valuecustomer. The purchases and sales of an acquisition or disposal to evaluate whethercrude oil are at the assets in question are simply assets or if they meet the requirements of a business. If the screen is not met, no further evaluation is needed. If the screen is met, certain steps are subsequently taken to make the determination. This ASU is designed to reduce the number of transactions to be accounted for as business transactions, which take more time and cost more to analyze than asset transactions. This ASU is effective for annual and interim periods beginning after December 15, 2017 and is required to be applied prospectively. Our current Clayton Williams Energy Acquisition is not impacted by this guidance and we will apply the new guidance to applicable and qualifying transactions after our adoption on January 1, 2018.prevailing market prices.
Statement of Cash Flows: Restricted CashIn November 2016, the FASB issuedRecently Issued Accounting Standards Update No. 2016-18 (ASU 2016-18): Statement of Cash Flows – Restricted Cash, which requires amounts generally described as restricted cash and restricted cash equivalents be included with cash and cash equivalents when reconciling the total beginning and ending amounts for the periods shown on the statement of cash flows. This ASU will be effective for annual and interim periods beginning after December 15, 2017, with earlier application permitted. We do not believe adoption of ASU 2016-18 will have a material impact on our statement of cash flows and related disclosures. We will adopt the new standard on the effective date of January 1, 2018.
Statement of Cash Flows: Classification of Certain Cash Receipts and Cash PaymentsIn August 2016, the FASB issued Accounting Standards Update No. 2016-15 (ASU 2016-15): Statement of Cash Flows – Classification of Certain Cash Receipts and Cash Payments, to clarify how eight specific cash receipt and cash payment transactions should be presented in the statement of cash flows. ASU 2016-15 will be effective for annual and interim periods beginning after December 15, 2017, with earlier application permitted. We do not believe adoption of ASU 2016-15 will have a material impact on our statement of cash flows and related disclosures as this update pertains to classification of items and is not a change in accounting principle. We will adopt the new standard on the effective date of January 1, 2018.
LeasesIn February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2016-02 (ASU 2016-02): Leases. The guidancestandard requires lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by leases with terms of more than 12 months. This ASU 2016-02 also requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB issued Accounting Standards Update No. 2018-01 (ASU 2018-01): Land Easement Practical Expedient for Transition to Topic 842, to provide an optional practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under Topic 840. In July 2018, the FASB issued Accounting Standards Update No. 2018-10 (ASU 2018-10): Codification Improvements to Topic 842, Leases, to clarify application of certain aspects of the standard and to remove inconsistencies within the guidance. Furthermore, in July 2018, the FASB issued Accounting Standards Update No. 2018-11 (ASU 2018-11): Leases (Topic 842): Targeted Improvements, which provides for another transition method, in addition to the existing transition method, by allowing entities to initially apply the new leases standard at the adoption date (such as January 1, 2019) and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption (i.e. comparative periods presented in the financial statements will continue to be in accordance with current GAAP (Topic 840, Leases)). The standard will be effective for annual and interim periods beginning after December 15, 2018, with earlier application permitted.
In the normal course of business, we enter into capital and operating lease agreements to support our exploration and development operations and lease assets such as drilling rigs, platforms, storage facilities, field services and well equipment, pipeline capacity, office space and other assets. At this time, we cannot reasonably estimate the financial impact this ASU will have on our financial statements; however, we believe adoption and implementation of this ASU will have a material impact on our balance sheet resulting from an increase in both assets and liabilities relating to our leasing activities. As part of our assessment to date, we have formed an implementation work team, prepared educational and training materials pertinent to this ASU and have begun contract review and documentation. We will adopt the new standard on the effective date of January 1, 2019. Although we continue to assess the impact of the standard on our consolidated financial statements, we believe adoption and implementation will result in an increase in assets and liabilities as well as additional disclosures. We do not expect a material impact on our consolidated statement of operations. We have developed and are executing a project plan, which includes contract review and assessment, as well as evaluation of our systems, processes and internal controls. In addition, we plan to implement new lease accounting software.
Accumulated Other Comprehensive Income In February 2018, the FASB issued Accounting Standards Update No. 2018-02 (ASU 2018-02): Income Statement – Reporting Comprehensive Income, to allow reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act. ASU 2018-02 will be effective for annual and interim periods beginning after December 15, 2018, with earlier application permitted. As of June 30, 2018, we have a disproportionate tax effect of approximately $7 million stranded in accumulated other comprehensive income. We are currently evaluating the provisions of this standard.
Intangibles – Goodwill and Other: Simplifying the Test for Goodwill Impairment In January 2017, the FASB issued Accounting Standards Update No. 2017-04 (ASU 2017-04): Intangibles – Goodwill and Other – Simplifying the Test for Goodwill Impairment, to simplify how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. Under the new guidance, an entitystandard, we will perform its annual, or interim,our goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount, with an impairment charge being recognized for the
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
amount by which the carrying amount exceeds the reporting unit’s fair value. ASU 2017-04 will be effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019, with early adoption permitted. We are currently evaluating the provisions of ASU 2017-04 and have not yet determined if we will early adopt.2017-04.
Financial Instruments: Credit Losses In June 2016, the FASB issued Accounting Standards Update No. 2016-13 (ASU 2016-13): Financial Instruments – Credit Losses, which replaces the incurred loss impairment methodology in current US GAAP with a methodology that reflects expected credit losses. The update is intended to provide financial statement users with
Noble Energy, Inc.
Notes to Consolidated Financial Statements
more useful information about expected credit losses. The amended guidancestandard is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. From evaluation of our current credit portfolio, which includes receivables for commodity sales, joint interest billings due from partners and other receivables, historical credit losses have been de minimis and we believe that our expected future credit losses would not be significant. As such, we do not believe adoption of the standard will have a material impact on our financial statements.
Derivatives and Hedging – Targeted Improvements to Accounting for Hedging Activities In August 2017, the FASB issued Accounting Standards Update No. 2017-12 (ASU 2017-12): Derivatives and Hedging – Targeted Improvements to Accounting for Hedging Activities. The update is intended to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition to that main objective, ASU 2017-12 makes certain targeted improvements to simplify the application of the hedge accounting guidance in current US GAAP. The amended standard is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. We are currently evaluating the effect, if any, that the guidance will have on our consolidated financial statements and related disclosures. We will adopt the new standard on the effective dateprovisions of January 1, 2020.ASU 2017-12.
Statements of Operations InformationOther statements of operations information is as follows: |
| | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| (millions) | 2018 | | 2017 | | 2018 | | 2017 |
| Income From Equity Method Investees and Other | |
| | |
| | | | |
| Income from Equity Method Investees | $ | 49 |
| | $ | 38 |
| | $ | 96 |
| | $ | 80 |
|
Sales of Purchased Oil and Gas (1) | 66 |
| | — |
| | 119 |
| | — |
|
| Midstream Services Revenues – Third Party | 15 |
| | 4 |
| | 28 |
| | 4 |
|
| Total | $ | 130 |
| | $ | 42 |
| | $ | 243 |
| | $ | 84 |
|
| Production Expense | |
| | |
| | | | |
| Lease Operating Expense | $ | 132 |
| | $ | 124 |
| | $ | 287 |
| | $ | 263 |
|
| Production and Ad Valorem Taxes | 50 |
| | 32 |
| | 104 |
| | 73 |
|
| Gathering, Transportation and Processing Expense | 100 |
| | 121 |
| | 195 |
| | 240 |
|
| Other Royalty Expense | 10 |
| | 6 |
| | 27 |
| | 10 |
|
| Total | $ | 292 |
| | $ | 283 |
| | $ | 613 |
| | $ | 586 |
|
| Exploration Expense | | | | | | | |
| Leasehold Impairment and Amortization | $ | — |
| | $ | — |
| | $ | — |
| | $ | 18 |
|
| Seismic, Geological and Geophysical | 2 |
| | 8 |
| | 13 |
| | 13 |
|
| Staff Expense | 13 |
| | 16 |
| | 27 |
| | 29 |
|
| Other | 14 |
| | 6 |
| | 24 |
| | 12 |
|
| Total | $ | 29 |
| | $ | 30 |
| | $ | 64 |
| | $ | 72 |
|
| Other Operating Expense, Net | | | | | | | |
Marketing Expense (2) | $ | 7 |
| | $ | 14 |
| | $ | 12 |
| | $ | 33 |
|
Purchased Oil and Gas (1) | 71 |
| | — |
| | 128 |
| | — |
|
| Clayton Williams Energy Acquisition Expenses | — |
| | 90 |
| | — |
| | 94 |
|
| Other, Net | (4 | ) | | 14 |
| | 4 |
| | 20 |
|
| Total | $ | 74 |
| | $ | 118 |
| | $ | 144 |
| | $ | 147 |
|
| Other Non-Operating Expense (Income), Net | | | | | | | |
Loss on Investment in Shares of Tamar Petroleum Ltd., Net (3) | $ | 11 |
| | $ | — |
| | $ | 26 |
| | $ | — |
|
| Other | — |
| | (5 | ) | | (2 | ) | | (6 | ) |
| Total | $ | 11 |
| | $ | (5 | ) | | $ | 24 |
| | $ | (6 | ) |
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
|
| | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| (millions) | 2017 | | 2016 | | 2017 | | 2016 |
| Production Expense | |
| | |
| | | | |
| Lease Operating Expense | $ | 124 |
| | $ | 119 |
| | $ | 263 |
| | $ | 281 |
|
| Production and Ad Valorem Taxes | 38 |
| | 40 |
| | 83 |
| | 43 |
|
Gathering, Transportation and Processing Expense (1) | 121 |
| | 121 |
| | 240 |
| | 232 |
|
| Total | $ | 283 |
| | $ | 280 |
| | $ | 586 |
| | $ | 556 |
|
Loss on Marcellus Shale Upstream Divestiture (2) | | | | | | | |
| Loss on Sale | $ | 2,270 |
| | $ | — |
| | $ | 2,270 |
| | $ | — |
|
Firm Transportation Commitment (3) | 41 |
| | — |
| | 41 |
| | — |
|
Other (4) | 11 |
| | — |
| | 11 |
| | — |
|
| Total | $ | 2,322 |
| | $ | — |
| | $ | 2,322 |
| | $ | — |
|
| Other Operating (Income) Expense, Net | | | | | | | |
Marketing Expense (5) | $ | 14 |
| | $ | 9 |
| | $ | 33 |
| | $ | 27 |
|
Clayton Williams Energy Acquisition Expenses (6) | 90 |
| | — |
| | 94 |
| | — |
|
Gain on Extinguishment of Debt (7) | — |
| | — |
| | — |
| | (80 | ) |
Loss on Asset Due to Terminated Contract (8) | — |
| | 5 |
| | 4 |
| | 47 |
|
| Other, Net | 14 |
| | (3 | ) | | 16 |
| | 16 |
|
| Total | $ | 118 |
| | $ | 11 |
| | $ | 147 |
| | $ | 10 |
|
| |
(1) | CertainAs part of the Saddle Butte acquisition in first quarter 2018, we acquired certain contracts which include the purchase and sale of crude oil with third parties. In addition, we have entered into certain transactions beginning in first quarter 2018 for the purchase of third party natural gas and the subsequent sale of natural gas to other third parties. The natural gas is transported through firm transportation capacity we retained following the Marcellus Shale upstream divestiture in second quarter 2017 and is part of our processingmitigation efforts to utilize capacity and reduce our financial commitment. The cost to purchase natural gas includes transportation expense was historically presented as a componentincurred of other operating expense, net, in our consolidated statements of operations. Beginning in 2017, we have changed our presentation to reflect processing expense as a component of production expense. These costs are now included within gathering, transportation and processing expense. For the three and six months ended June 30, 2017, these costs totaled $2 million and $5 million respectively. For the three and six months ended June 30, 2016, these costs totaled $6 million and $10$11 million respectively,for second quarter and have been reclassified from marketing expense to conform to the current presentation. |
| |
(2)
| first six months of 2018, respectively. SeeNote 4. Acquisitions11. Segment Information and Divestitures.Note 12. Commitments and Contingencies. |
| |
(3)(2)
| Amount represents expense relatedExpense relates to an unutilized firm transportation commitment associated with a Marcellus Shale firm transportation contract. See Note 12. Commitments and Contingencies. |
| |
(4)
| Amount includes costs for legal and advisory services and employee severance charges. |
| |
(5)
| Amounts represent expense for unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments. |
| |
(6)(3)
| See Note 3. Clayton Williams Energy Acquisition. |
| |
(7)
| Amount relatesAmounts for second quarter and the first six months of 2018 include losses of $11 million and $40 million, respectively, related to the tenderingchange in fair value. The loss for the six months ended June 30, 2018 is partially offset by dividend income of senior notes. See Note 6. Debt. |
| |
(8)
| Amounts relate to the termination and final settlement of a rig contract for offshore Falkland Islands as a result of a supplier's non-performance. |
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
Balance Sheet InformationOther balance sheet information is as follows:
| | | (millions) | June 30,
2017 | | December 31,
2016 | June 30,
2018 | | December 31,
2017 |
| Accounts Receivable, Net | | | | | | |
| Commodity Sales | $ | 408 |
| | $ | 403 |
| $ | 460 |
| | $ | 455 |
|
| Joint Interest Billings | 198 |
| | 106 |
| 210 |
| | 207 |
|
Proceeds Receivable (1) | — |
| | 40 |
| |
| Other | 112 |
| | 86 |
| 89 |
| | 103 |
|
| Allowance for Doubtful Accounts | (19 | ) | | (20 | ) | (16 | ) | | (17 | ) |
| Total | $ | 699 |
| | $ | 615 |
| $ | 743 |
| | $ | 748 |
|
| Other Current Assets | |
| | |
| |
| | |
|
| Inventories, Materials and Supplies | $ | 65 |
| | $ | 71 |
| $ | 46 |
| | $ | 66 |
|
| Inventories, Crude Oil | 23 |
| | 18 |
| 27 |
| | 16 |
|
| Commodity Derivative Assets | | 29 |
| | 2 |
|
Assets Held for Sale (2)(1) | 191 |
| | 18 |
| 40 |
| | 629 |
|
Restricted Cash (3)(2) | — |
| | 30 |
| — |
| | 38 |
|
| Prepaid Expenses and Other Current Assets | 59 |
| | 23 |
| 45 |
| | 29 |
|
| Total | $ | 338 |
| | $ | 160 |
| $ | 187 |
| | $ | 780 |
|
| Other Noncurrent Assets | |
| | |
| |
| | |
|
Equity Method Investments | $ | 286 |
| | $ | 400 |
| $ | 357 |
| | $ | 305 |
|
Customer-Related Intangible Assets (4) | | 326 |
| | — |
|
Investment in Shares of Tamar Petroleum Ltd. (5) | | 150 |
| | — |
|
| Mutual Fund Investments | 67 |
| | 71 |
| 57 |
| | 57 |
|
| Net Deferred Income Tax Asset | | 25 |
| | 25 |
|
| Other Assets, Noncurrent | 79 |
| | 37 |
| 69 |
| | 74 |
|
| Total | $ | 432 |
| | $ | 508 |
| $ | 984 |
| | $ | 461 |
|
| Other Current Liabilities | |
| | |
| |
| | |
|
| Production and Ad Valorem Taxes | $ | 113 |
| | $ | 115 |
| $ | 111 |
| | $ | 84 |
|
| Commodity Derivative Liabilities | — |
| | 102 |
| 250 |
| | 58 |
|
| Income Taxes Payable | 11 |
| | 53 |
| 5 |
| | 18 |
|
Asset Retirement Obligations (4) | 50 |
| | 160 |
| |
| Asset Retirement Obligations | | 92 |
| | 51 |
|
| Interest Payable | 75 |
| | 76 |
| 64 |
| | 67 |
|
| Current Portion of Capital Lease Obligations | 64 |
| | 63 |
| 47 |
| | 61 |
|
Other Liabilities, Current (5) | 196 |
| | 173 |
| |
Liabilities Associated with Assets Held for Sale (1) | | — |
| | 55 |
|
| Compensation and Benefits Payable | | 66 |
| | 98 |
|
| Other Liabilities, Current | | 110 |
| | 86 |
|
| Total | $ | 509 |
| | $ | 742 |
| $ | 745 |
| | $ | 578 |
|
| Other Noncurrent Liabilities | |
| | |
| |
| | |
|
| Deferred Compensation Liabilities | $ | 216 |
| | $ | 218 |
| $ | 180 |
| | $ | 197 |
|
Asset Retirement Obligations (4) | 943 |
| | 775 |
| |
| Asset Retirement Obligations | | 543 |
| | 824 |
|
Marcellus Shale Firm Transportation Commitment (6) | 33 |
| | — |
| 71 |
| | 76 |
|
| Production and Ad Valorem Taxes | 32 |
| | 47 |
| 39 |
| | 69 |
|
| Commodity Derivative Liabilities | | 85 |
| | 15 |
|
| Other Liabilities, Noncurrent | 55 |
| | 63 |
| 77 |
| | 64 |
|
| Total | $ | 1,279 |
| | $ | 1,103 |
| $ | 995 |
| | $ | 1,245 |
|
| |
(1) | Assets held for sale at June 30, 2018 include assets in the Greeley Crescent area of the DJ Basin. Assets held for sale at December 31, 2017 include assets in the Greeley Crescent area of the DJ Basin, a 7.5% interest in the Tamar field, offshore Israel, our interest in Southwest Royalties, Inc. acquired in the Clayton Williams Energy Acquisition, and the CONE investments. Liabilities associated with |
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
assets held for sale primarily represent asset retirement obligations and other liabilities to be assumed by the purchaser. See Note 3. Acquisitions and Divestitures. | |
(2) | Balance at December 31, 2016 related to2017 represents amount held in escrow pending closing of the farm-out of a 35% interest in Block 12 offshore Cyprus; proceeds were received in January 2017.Saddle Butte acquisition. See Note 4.3. Acquisitions and Divestitures. |
| |
(2)(3)
| Balance at June 30, 2017 primarily includesIncludes $49 million for our equity investment in CONE Gathering, LLC.shares of CNX Midstream Partners LP. At December 31, 2017, this investment was included in assets held for sale. See Note 4.3. Acquisitions and Divestitures and Note 6. Fair Value Measurements and Disclosures. |
| |
(3)(4)
| Balance at December 31, 2016 represented amount heldAmount relates to intangible assets acquired in escrow for the purchaseSaddle Butte acquisition and is net of certain Delaware Basin properties. The transaction closed in first quarter 2017.$14 million of accumulated amortization. See Note 4.3. Acquisitions and Divestitures.Divestitures. |
| |
(4)(5)
| Reclassification from currentAmount relates to noncurrent is driven primarily by a changeour investment in expected timingshares of abandonment activities in the Gulf of Mexico. Tamar Petroleum Ltd. See Note 9. Asset Retirement Obligations3. Acquisitions and Divestitures and Note 6. Fair Value Measurements and Disclosures. |
| |
(5)(6)
| Balance atAmounts relate to the long-term portion of retained firm transportation agreements. At June 30, 2018 and December 31, 2017, includes $8we recorded $12 million and $14 million, respectively, associated with the current portion of the Marcellus Shale firm transportation commitment. See Note 12. Commitments and Contingencies. |
| |
(6)
| See Note 12. Commitments and Contingencies. |
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 3. Clayton Williams Energy Acquisition
In January 2017, we announced the Clayton Williams Energy Acquisition, which was approved by Clayton Williams Energy stockholdersReconciliation of Total Cash We define total cash as cash, cash equivalents and closed on April 24, 2017. Acquired assets include 71,000 highly contiguous net acres in the core of the Delaware Basin adjacent to our Reeves County holdings in Texas, and an additional 100,000 net acres in other areas of the Permian and Midland Basins. In total, the acquisition increased our Delaware Basin position to approximately 118,000 net acres.
We recorded net proved reserves of approximately 86 MMBoe, of which approximately 17 MMBoe are proved developed reserves and 69 MMBoe are proved undeveloped reserves, as of June 30, 2017. In addition, upon closing of the acquisition, approximately 64,000 net acres in Reeves County, Texas were dedicated to Noble Midstream Partners for infield crude oil, natural gas and produced water gathering.
The acquisition was effected through the issuance of approximately 56 million shares of Noble Energy common stock, with a fair value of approximately $1.9 billion, and cash consideration of $637 million, for total consideration of approximately $2.5 billion, in exchange for all outstanding Clayton Williams Energy shares, including options, restricted stock awards and warrants. The closing price of our stock on the New York Stock Exchange (NYSE) was $34.17 on April 24, 2017. In connection with the transaction, we borrowed $1.3 billion under our Revolving Credit Facility (defined below) to fund the cash portion of the acquisition consideration, redeem outstanding Clayton Williams Energy debt, pay associated make-whole premiums and pay related fees and expenses. See Note 6. Debt.In connection with the Clayton Williams Energy Acquisition, we have incurred acquisition-related costs of approximately $94 million to date, including $60 million of severance, consulting, investment, advisory, legal and other merger-related fees, and $34 million of noncash share-based compensation expense, all of which were expensed and are included in other operating expense, net in our consolidated statements of operations. In addition, we received approximately 720,000 shares of common stock from Clayton Williams Energy shareholders for the payment of withholding taxes due on the vesting of their restricted shares and options pursuant to the purchase and sale agreement, resulting in a $25 million increase in our treasury stock balance.
Purchase Price Allocation The transaction has been accounted for as a business combination, using the acquisition method.cash. The following table represents the preliminary allocationprovides a reconciliation of the total purchase price of Clayton Williams Energy to the identifiable assets acquired and the liabilities assumed based on the fair values at the acquisition date, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill. Any value assigned to goodwill is not expected to be deductible for income tax purposes.cash: |
| | | | | | | |
| | Six Months Ended June 30, |
| (millions) | 2018 | | 2017 |
| Cash and Cash Equivalents at Beginning of Period | $ | 675 |
| | $ | 1,180 |
|
| Restricted Cash at Beginning of Period | 38 |
| | 30 |
|
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | $ | 713 |
| | $ | 1,210 |
|
| Cash and Cash Equivalents at End of Period | $ | 621 |
| | $ | 540 |
|
| Restricted Cash at End of Period | — |
| | — |
|
| Cash, Cash Equivalents, and Restricted Cash at End of Period | $ | 621 |
| | $ | 540 |
|
Certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, valuation of pre-merger contingencies, final tax returns that provide the underlying tax basis of Clayton Williams Energy's assets and liabilities, and final appraisals of assets acquired and liabilities assumed. We expect to complete the purchase price allocation during the 12-month period following the acquisition date, during which time the value of the assets and liabilities, including any goodwill, may be revised as appropriate.
The following table sets forth our preliminary purchase price allocation: |
| | | |
| (millions, except per share amounts) | |
| Fair Value of Common Stock Issued | $ | 1,876 |
|
| Plus: Cash Consideration Paid to Clayton Williams Energy Stockholders | 637 |
|
| Total Purchase Price | $ | 2,513 |
|
| Plus Liabilities Assumed by Noble Energy: | |
| Accounts Payable | 68 |
|
| Other Current Liabilities | 38 |
|
| Long-Term Deferred Tax Liability | 522 |
|
| Long-Term Debt | 595 |
|
| Asset Retirement Obligations | 59 |
|
| Total Purchase Price Plus Liabilities Assumed | $ | 3,795 |
|
Noble Energy, Inc.
Notes to Consolidated Financial Statements
The fair value of Clayton Williams Energy's identifiable assets is as follows: |
| | | |
| (millions) | |
| Cash and Cash Equivalents | $ | 21 |
|
| Other Current Assets | 37 |
|
| Oil and Gas Properties: | |
| Proved Reserves | 724 |
|
| Undeveloped Leasehold Cost | 1,581 |
|
| Gathering and Processing Assets | 49 |
|
| Asset Retirement Costs | 59 |
|
| Other Property Plant and Equipment | 18 |
|
| Other Noncurrent Assets | 17 |
|
| Implied Goodwill | 1,289 |
|
| Total Asset Value | $ | 3,795 |
|
In connection with the acquisition, we assumed, and then subsequently retired, $595 million of Clayton Williams Energy long-term debt. The fair value measurements of long-term debt were estimated based on the early redemption prices and represent Level 1 inputs.
The fair value measurements of crude oil and natural gas properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of crude oil and natural gas properties included estimates of: (i) recoverable reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average cost of capital rate. These inputs required significant judgments and estimates by management at the time of the valuation and are the most sensitive and may be subject to change.
The results of operations attributable to Clayton Williams Energy are included in our consolidated statements of operations beginning on April 24, 2017. We generated revenues of $25 million and a de minimis loss from the Clayton Williams Energy assets during the period April 24, 2017 to June 30, 2017.
Proforma Financial InformationThe following pro forma condensed combined financial information was derived from the historical financial statements of Noble Energy and Clayton Williams Energy and gives effect to the acquisition as if it had occurred on January 1, 2016. The below information reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including (i) Noble Energy's common stock and equity awards issued to convert Clayton Williams Energy's outstanding shares of common stock and equity awards and conversion of warrants as of the closing date of the acquisition, (ii) depletion of Clayton Williams Energy's fair-valued proved crude oil and natural gas properties, and (iii) the estimated tax impacts of the pro forma adjustments.
Additionally, pro forma earnings for the three and six months ended June 30, 2017 were adjusted to exclude acquisition-related costs of $90 million and $94 million, respectively, incurred by Noble Energy and $26 million, incurred by Clayton Williams Energy in second quarter 2017. The pro forma results of operations do not include any cost savings or other synergies that may result from the Clayton Williams Energy Acquisition or any estimated costs that have been or will be incurred by us to integrate the Clayton Williams Energy assets. The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Clayton Williams Energy Acquisition taken place on January 1, 2016; furthermore, the financial information is not intended to be a projection of future results. |
| | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| (millions, except per share amounts) | 2017 | | 2016 | | 2017 | | 2016 |
| Revenues | $ | 1,070 |
| | $ | 888 |
| | $ | 2,141 |
| | $ | 1,641 |
|
| Net Loss and Comprehensive Loss Attributable to Noble Energy | (1,354 | ) | | (316 | ) | | (1,324 | ) | | (649 | ) |
| | | | | | | | |
| Net Loss Attributable to Noble Energy per Common Share | | | | | | | |
| Basic and Diluted | $ | (2.77 | ) | | $ | (0.65 | ) | | $ | (2.71 | ) | | $ | (1.34 | ) |
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Note 4.3. Acquisitions and Divestitures
2018 Asset Transactions
Divestiture of Gulf of Mexico Assets On February 15, 2018, we announced that we had signed a definitive agreement to sell our Gulf of Mexico assets, including all of our interests in producing properties and undeveloped acreage, for cash consideration of $480 million, along with the assumption, by the purchaser, of all abandonment obligations associated with the properties. As a result, we recorded impairment expense of $168 million during first quarter 2018.
In second quarter 2018, we closed the transaction with an effective date of January 1, 2018. After consideration of customary closing adjustments, we received net proceeds of $383 million and recorded an additional loss of $19 million.
In addition, a cumulative contingent payment of up to $100 million is payable to us in the period after the closing of the transaction, beginning third quarter 2018, through the end of 2022, determined quarterly, at a rate of $2 per barrel produced by these assets when the average purchase price for Light Louisiana Sweet (LLS) crude oil exceeds $63 per barrel, and if produced crude oil volumes exceed certain minimum thresholds. As of June 30, 2018, no amounts have been accrued related to the contingent payment.
Proved reserves associated with these properties totaled approximately 23 MMBoe as of December 31, 2017.
Divestiture of 7.5% Interest in Tamar Field On March 14, 2018, we closed the sale of a 7.5% working interest in the Tamar field to Tamar Petroleum Ltd. (Tamar Petroleum), a publicly traded entity on the Tel Aviv Stock Exchange (TASE: TMRP). Total consideration included cash and 38.5 million shares of Tamar Petroleum that had a publicly traded value of $224 million. The transaction had an effective date of January 1, 2018 and after consideration of closing adjustments and before consideration of taxes, we received $484 million of cash.
Our shares of Tamar Petroleum are currently subject to certain temporary lock-up provisions and have no voting rights. Upon subsequent sale of the shares to a third party, the voting rights will be restored and granted to the third party. Due to the lock-up provisions associated with the Tamar Petroleum shares, we initially attributed $190 million of fair value to the shares, or 15% lower than the publicly traded value on the TASE. These shares are currently being accounted for at fair value. See Note 6. Fair Value Measurements and Disclosures. Total consideration received was applied to the field's basis and resulted in the recognition of a pre-tax gain of $376 million. In connection with the transaction, we incurred tax expense of $86 million.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
The sale is in accordance with the terms of the Israel Natural Gas Framework (Framework) that requires us to reduce our ownership interest in the Tamar field from 32.5% to 25% by year-end 2021. We expect to sell the Tamar Petroleum shares before year-end 2021. Proved reserves related to the 7.5% interest totaled approximately 84 MMBoe as of December 31, 2017.
Divestiture of Southwest Royalties In January 2018, we closed the sale of our interest in Southwest Royalties, Inc. (Southwest Royalties), a subsidiary of Clayton Williams Energy, Inc. (Clayton Williams Energy), which we acquired in the acquisition of Clayton Williams Energy (Clayton Williams Energy Acquisition) in 2017. We received proceeds of $60 million, resulting in no gain or loss recognition on the sale of these assets.
Divestiture of Marcellus Shale CONE Gathering In January 2018, we closed the sale of our 50% interest in CONE Gathering LLC (CONE Gathering) to CNX Resources Corporation. CONE Gathering owns the general partner of CNX Midstream Partners LP (CNX Midstream Partners, NYSE: CNXM). We received proceeds of $308 million in cash and recognized a pre-tax gain of $196 million.
After the sale, we continued to hold 21.7 million common units, representing a 34.1% limited partner interest, in CNX Midstream Partners. During second quarter 2018, we sold 7.5 million of the common units, receiving net proceeds of approximately $135 million, net of underwriting fees, and recognized a gain of $109 million. As of June 30, 2018, we continue to hold 14.2 million common units, representing a 22.3% limited partner interest, in CNX Midstream Partners and account for the investment under equity method accounting.
Noble Midstream Partners Saddle Butte Acquisition On January 31, 2018, Black Diamond Gathering LLC (Black Diamond), an entity formed by Black Diamond Gathering Holdings LLC, a wholly-owned subsidiary of Noble Midstream Partners, and Greenfield Midstream, LLC (Greenfield), completed the acquisition of Saddle Butte Rockies Midstream, LLC and affiliates (collectively, Saddle Butte) from Saddle Butte Pipeline II, LLC. Saddle Butte owned a large-scale integrated gathering system, located in the DJ Basin, which we subsequently renamed the Black Diamond gathering system.
Consideration totaled $681 million, which included $663 million of cash and assumption of $18 million of liabilities. Greenfield funded approximately $343 million of the purchase price, which is reflected as a contribution from noncontrolling interest within our consolidated statement of equity, and Noble Midstream Partners funded the remainder. We consolidate Black Diamond and reflect the third-party ownership within noncontrolling interest within our consolidated statement of equity.
We accounted for the transaction as a business combination using the acquisition method. The total purchase price was allocated to assets acquired and liabilities assumed based on the fair value at the acquisition date. We have recognized goodwill for the amount of the purchase price exceeding the fair value of the assets acquired. Allocated fair value included: $206 million to property, plant and equipment; $340 million to customer-related intangible assets (acquired customer contracts); and $111 million to implied goodwill. The purchase price allocation is preliminary as certain data necessary to complete the purchase price allocation is not yet available, such as analysis of the final appraisals of assets acquired and liabilities assumed. We expect to complete the purchase price allocation during the 12-month period following the acquisition date, during which time the value of the assets and liabilities, including any goodwill, may be revised as appropriate.
Other Divestitures During the first six months of 2018, we also closed the sale of certain other smaller US onshore properties and received total cash consideration of $12 million, recording a gain of $4 million.
2017 Asset Transactions
Delaware Basin Acquisition During the first six months of 2017, we engagedclosed a bolt-on acquisition in the Delaware Basin for $301 million, approximately $246 million of which was allocated to undeveloped leasehold costs. The acquisition included interests in seven producing wells, four of which are operated by us.
Clayton Williams Energy Acquisition On April 24, 2017, we completed the Clayton Williams Energy Acquisition. The acquisition was effected through the issuance of 56 million shares of Noble Energy common stock, with a fair value of $1.9 billion, and cash consideration of $637 million, for total consideration of $2.5 billion, in exchange for all of the outstanding Clayton Williams Energy shares, including stock options, restricted stock awards and warrants.
The transaction was accounted for as a business combination using the acquisition method. The following table represents the final allocation of the total purchase price of Clayton Williams Energy to the assets acquired and liabilities assumed, based on the fair value at the acquisition date, with any excess of the purchase price over the estimated fair value of the identifiable ne
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
t assets acquired recorded as goodwill. |
| | | |
| (millions) | |
| Fair Value of Common Stock Issued | $ | 1,851 |
|
| Plus: Cash Consideration Paid to Clayton Williams Energy Stockholders | 637 |
|
| Total Purchase Price | $ | 2,488 |
|
| Plus Liabilities Assumed by Noble Energy: | |
| Accounts Payable | 99 |
|
| Other Current Liabilities | 38 |
|
| Long-Term Deferred Tax Liability | 515 |
|
| Long-Term Debt | 595 |
|
| Asset Retirement Obligations | 63 |
|
| Total Purchase Price Plus Liabilities Assumed | $ | 3,798 |
|
The fair value of Clayton Williams Energy's identifiable assets was as follows: |
| | | |
| (millions) | |
| Cash and Cash Equivalents | $ | 21 |
|
| Other Current Assets | 70 |
|
| Oil and Gas Properties: | |
| Proved Reserves | 722 |
|
| Undeveloped Leasehold Costs | 1,571 |
|
| Gathering and Processing Assets | 48 |
|
| Asset Retirement Costs | 63 |
|
| Other Noncurrent Assets | 12 |
|
| Implied Goodwill | 1,291 |
|
| Total Asset Value | $ | 3,798 |
|
In connection with the acquisition, we assumed, and then subsequently retired in second quarter 2017, all of Clayton Williams Energy's long-term debt at a cost of $595 million. The fair value measurements of long-term debt were estimated based on the early redemption prices and represent Level 1 inputs.
The fair value measurements of crude oil and natural gas properties and asset transactions.retirement obligations were based on inputs that are not observable in the market and, therefore, represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert expected future cash flows to a single discounted amount. Significant inputs to the valuation of crude oil and natural gas properties included estimates of: (i) proved, possible and probable reserves; (ii) production rates and related development timing; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average cost of capital rate. These inputs required significant judgments and estimates by management at the time of the valuation and were the most sensitive.
Based upon the final purchase price allocation, we recognized $1.3 billion of goodwill, all of which is assigned to the Texas reporting unit.
The following pro forma condensed combined financial information was derived from the historical financial statements of Noble Energy and Clayton Williams Energy and gives effect to the acquisition as if it had occurred on January 1, 2017. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including: (i) Noble Energy's common stock and equity awards issued to convert Clayton Williams Energy's outstanding shares of common stock and equity awards and conversion of warrants as of the closing date of the acquisition, (ii) depletion of Clayton Williams Energy's fair-valued proved crude oil and natural gas properties, and (iii) the estimated tax impacts of the pro forma adjustments.
The pro forma results of operations do not include any cost savings or other synergies that we expect to realize from the Clayton Williams Energy Acquisition or any estimated costs that have been or will be incurred by us to integrate the Clayton Williams Energy assets. The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Clayton Williams Energy Acquisitio
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
n taken place on January 1, 2017; furthermore, the financial information is not intended to be a projection of future results. |
| | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| (millions, except per share amounts) | 2018 (1) | | 2017 | | 2018 (1) | | 2017 |
| Revenues | $ | 1,230 |
| | $ | 1,070 |
| | $ | 2,516 |
| | $ | 2,141 |
|
| Net (Loss) Income and Comprehensive (Loss) Income Attributable to Noble Energy | (23 | ) | | (1,354 | ) | | 531 |
| | (1,324 | ) |
| | | | | | | | |
| Net (Loss) Income Attributable to Noble Energy per Common Share | | | | | | | |
| Basic | $ | (0.05 | ) | | $ | (2.77 | ) | | $ | 1.09 |
| | $ | (2.71 | ) |
| Diluted | $ | (0.05 | ) | | $ | (2.77 | ) | | $ | 1.09 |
| | $ | (2.71 | ) |
| |
(1) | No pro forma adjustments were made for the period as Clayton Williams Energy operations are included in our historical results. |
Marcellus Shale Upstream DivestitureOn June 28, 2017, we closed the sale of all of our Marcellus Shale upstream assets, which arewere primarily natural gas properties. The purchase price totaled $1.2 billion, and we received $1.0 billion of net cash proceeds, after consideration of customary adjustments, at closing. The purchase price includes additional contingent consideration of up to $100 million structured as three separate payments of $33.3 million each. The contingent payments are in effect should the average annual price of the Appalachia Dominion, South Point index exceed $3.30 per MMBtu in the individual annual periods from 2018 through 2020. No amounts have been accrued related to the contingent consideration. Proceeds from the transaction were used to repay borrowings resulting from the Clayton Williams Energy Acquisition. See Note 5. Debt6. Debt. In second quarter 2017, we recognized a total loss of $2.3 billion, or $1.5 billion after-tax, on this transaction. The aggregate net book value of the properties prior to the sale was approximately $3.4 billion, which included approximately $883 million of undeveloped leasehold cost.
As part of the total loss, we recorded a charge of $41 million, discounted, relating to a retained transportation contract where the pipeline project is currently in service. We no longer have production to satisfy this commitment and do not plan to utilize this capacity in the future. As such, we recorded a charge in accordance with accounting for exit or disposal activities under ASC 420 - Exit or Disposal Cost Obligations. In addition, we have retained other Marcellus Shale firm transportation contracts, relating to pipeline projects which are not yet commercially available to us. These projects are either under construction or have not yet been approved by the Federal Energy Regulatory Commission (FERC). As these projects become commercially available to us, we will assess, based upon the facts and circumstances, the recognition of any potential exit cost liabilities. We expect to incur additional firm transportation, as well as other restructuring or personnel costs, associated with this exit activity in the future.contract. See Note 2. Basis of Presentation and Note 12. Commitments and Contingencies. For the three and six months ended June 30, 2017, our consolidated statements of operations include a pre-tax loss of $2.3 billion for the respective periods associated with the divested Marcellus Shale upstream assets, driven by the loss on sale. For the three and six months ended June 30, 2016, our consolidated statements of operations include a pre-tax loss of $91 million and $167 million, respectively.
During second quarter 2017, production from the Marcellus Shale upstream assets totaled 393 MMcfe/d. With the closing of the sale, we recorded a decrease in net proved reserves of approximately 241 MMBoe, of which approximately 190 MMBoe were proved developed reserves and 51 MMBoe were proved undeveloped reserves.
Marcellus Shale CONE Gathering Divestiture On May 18, 2017, we announced the signing of a definitive agreement to divest an affiliate that holds the 50% interest in CONE Gathering, LLC (CONE Gathering) and 21.7 million common and subordinated limited partnership units in CONE Midstream Partners LP (NYSE:CNNX) (CONE Midstream), for total cash consideration of $765 million. CONE Gathering owns the general partner of CONE Midstream, and the limited partnership units represent a 33.5% ownership interest in CONE Midstream. CONE Midstream constructs, owns and operates natural gas gathering and other midstream energy assets in support of Marcellus Shale activities.
We expect closing to occur in second half 2017, subject to customary closing conditions and adjustments, and have classified these assets as held for sale at June 30, 2017. The other 50% owner of CONE Gathering is pursuing litigation in response to our sale. At this time, we expect this matter to be resolved prior to closing. Going forward, our midstream efforts are focused on Noble Midstream Partners supporting our DJ Basin and Delaware Basin growth areas.
Assets Held for Sale At June 30, 2017, assets held for sale included $173 million related to our investment in CONE Gathering and $18 million related to other onshore properties.
Delaware Basin Acquisition In first quarter 2017, we closed a bolt-on acquisition in the Delaware Basin for $301 million, approximately $246 million of which was allocated to undeveloped leasehold cost. The acquisition included seven producing wells, of which four are operated by us.
Noble Midstream Partners
Asset ContributionOn June 26, 2017, Noble Midstream Partners acquired an additional 15% limited partner interest in Blanco River DevCo LP (Blanco River DevCo), increasing its ownership to 40% of the Blanco River DevCo LP, and acquired the remaining 20% limited partner interest in Colorado River DevCo LP (Colorado River DevCo) from Noble Energy for $270 million.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
Blanco River DevCo holds Noble Midstream Partners’ Delaware Basin in-field gathering dedications for crude oil and produced water gathering services on approximately 111,000 net acres, with substantially all of the acreage also dedicated for natural gas gathering. Colorado River DevCo consists of gathering systems across Noble Energy’s Wells Ranch and East Pony development areas in the DJ Basin.
The $270 million consideration consisted of $245 million in cash and 562,430 common units representing limited partner interests in Noble Midstream Partners. Noble Midstream Partners funded the cash consideration with approximately $138 million of net proceeds from a concurrent private placement of common units and $90 million of borrowings under the Noble Midstream Services Revolving Credit Facility (defined below) and the remainder from cash on hand.
Noble Midstream Partners Advantage Acquisition On April 3, 2017, Noble Midstream Partners and Plains Pipeline, L.P., a wholly owned subsidiary of Plains All American Pipeline, L.P., acquired Advantage Pipeline, L.L.C. (Advantage Pipeline) for $133 million through a newly formed 50/50 joint venture (Advantage Joint Venture). Noble Midstream Partners contributed $66.5 million of cash to the joint venture, funded by available cash on hand and the Noble Midstream Services Revolving Credit Facility. The Advantage Joint Venture is accounted for under the equity method and is included within our Midstream segment.
Noble Midstream Partners serves as the operator of the Advantage Pipeline system, which includes a 70-mile crude oil pipeline in the Delaware Basin from Reeves County, Texas to Crane County, Texas with 150,000 barrels per day of shipping capacity (expandableTexas.
Noble Energy, Inc.
Notes to over 200,000 barrels per day) and 490,000 barrels of storage capacity.Consolidated Financial Statements (Unaudited)
2016 Asset Transactions
During the first six months of 2016, we engaged in the following asset transactions.
US Onshore Properties We entered into the following transactions for which we:
closed the divestiture of our Bowdoin property in northern Montana, generating proceeds of $43 million, and recognized a $23 million loss on sale;
sold certain other US onshore properties, generating net proceeds of $20 million, which were primarily applied to the DJ Basin depletable field, with no recognition of gain or loss;
entered into a purchase and sale agreement for the divestiture of certain producing and undeveloped interests covering approximately 33,100 net acres in the DJ Basin for $505 million, subject to customary closing adjustments. We received proceeds of $486 million during second quarter 2016, which were primarily applied to the DJ Basin depletable field, with no recognition of gain or loss. We expect to close the sale of the remaining properties, which are classified as held for sale, in the second half of 2017; and
entered into an acreage exchange agreement receiving approximately 11,700 net acres within our Wells Ranch development area in exchange for approximately 13,500 net acres primarily from our Bronco area, located southwest of Wells Ranch, with no recognition of gain or loss.
Cyprus Project (Offshore Cyprus) In first quarter 2017, we received the remaining $40 million consideration for the farm-out of a 35% interest in Block 12, which includes the Aphrodite natural gas discovery. Proceeds received, including $131 million in first quarter 2016, were applied to the Cyprus project asset with no gain or loss recognized.
Offshore Israel Assets In first quarter 2016, we closed the divestment of our 47% interest in the Alon A and Alon C licenses, which include the Karish and Tanin fields, for a total sales price of $73 million ($67 million for asset consideration and $6 million for cost adjustments). Proceeds were applied to reduce field basis with no recognition of gain or loss.
Note 5.4. Derivative Instruments and Hedging Activities
Objective and Strategies for Using Derivative Instruments We are exposed to fluctuations in crude oil, natural gas and NGL pricing. In order to mitigate the effect of commodity price volatility and enhance the predictability of cash flows relating to the marketing of our global crude oil and domestic natural gas, we enter into crude oil and natural gas price hedging arrangements.
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. See Note 7.6. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of our derivative instruments. Unsettled Commodity Derivative Instruments As of June 30, 2018, the following crude oil derivative contracts were outstanding: |
| | | | | | | | | | | | | | | | | | | |
| | | | | Swaps | | Collars |
Settlement Period | Type of Contract | Index | Bbls Per Day | Weighted Average Differential | Weighted Average Fixed Price | | Weighted Average Short Put Price | Weighted Average Floor Price | Weighted Average Ceiling Price |
| 2018 | Swaps | NYMEX WTI | 66,000 | $ | — |
| $ | 60.30 |
| | $ | — |
| $ | — |
| $ | — |
|
| 2018 | Collars | NYMEX WTI | 18,000 | — |
| — |
| | — |
| 50.42 |
| 58.82 |
|
| 2018 | Three-Way Collars | NYMEX WTI | 10,000 | — |
| — |
| | 45.50 |
| 52.50 |
| 69.09 |
|
| 2018 | Three-Way Collars | Dated Brent | 3,000 | — |
| — |
| | 40.00 |
| 50.00 |
| 70.41 |
|
| 2018 | Swaps | ICE Brent | 2,000 | — |
| 59.00 |
| | — |
| — |
| — |
|
| 2018 | Collars | ICE Brent | 2,000 | — |
| — |
| | — |
| 50.00 |
| 55.25 |
|
| 2018 | Three-Way Collars | ICE Brent | 5,000 | — |
| — |
| | 43.00 |
| 50.00 |
| 59.50 |
|
| 2018 | Basis Swaps | (1) | 20,000 | (2.30 | ) | — |
| | — |
| — |
| — |
|
| 2019 | Swaps | NYMEX WTI | 44,000 | — |
| 58.37 |
| | — |
| — |
| — |
|
| 2019 | Three-Way Collars | NYMEX WTI | 6,000 | — |
| — |
| | 50.00 |
| 60.00 |
| 72.75 |
|
| 2019 | Swaps | ICE Brent | 5,000 | — |
| 57.00 |
| | — |
| — |
| — |
|
| 2019 | Three-Way Collars | ICE Brent | 3,000 | — |
| — |
| | 43.00 |
| 50.00 |
| 64.07 |
|
| 2019 | Basis Swaps | (1) | 27,000 | (3.23 | ) | — |
| | — |
| — |
| — |
|
| 2020 | Swaption (2) | NYMEX WTI | 5,000 | — |
| 61.79 |
| | — |
| — |
| — |
|
| 2020 | Basis Swaps | (1) | 15,000 | (5.01 | ) | — |
| | — |
| — |
| — |
|
(1) We have entered into crude oil basis swap contracts in order to establish a fixed amount for the differential between pricing in Midland, Texas, and Cushing, Oklahoma. The weighted average differential represents the amount of reduction to Cushing, Oklahoma prices for the notional volumes covered by the basis swap contracts.
(2) We have entered into certain derivative contracts (swaptions), which give counterparties the right, but not the obligation, to enter into swap agreements with us on the option expiration dates.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
Unsettled Commodity Derivative InstrumentsAs of June 30, 2017, the following crude oil derivative contracts were outstanding: |
| | | | | | | | | | | | | | | | |
| | | | | Swaps | | Collars |
Settlement Period | Type of Contract | Index | Bbls Per Day | Weighted Average Fixed Price | | Weighted Average Short Put Price | Weighted Average Floor Price | Weighted Average Ceiling Price |
2H17 (1) | Call Option (2) | NYMEX WTI | 3,000 | $ | — |
| | $ | — |
| $ | — |
| $ | 60.12 |
|
2H17 (1) | Three-Way Collars | ICE Brent | 5,000 | — |
| | 43.00 |
| 50.00 |
| 64.00 |
|
| 2017 | Three-Way Collars | NYMEX WTI | 24,000 | — |
| | 39.08 |
| 47.71 |
| 61.20 |
|
| 2017 | Two-Way Collars | NYMEX WTI | 10,837 | — |
| | — |
| 40.80 |
| 52.71 |
|
| 2017 | Swaps | NYMEX WTI | 4,348 | 50.83 |
| | — |
| — |
| — |
|
| 2017 | Call Option (2) | NYMEX WTI | 3,000 | — |
| | — |
| — |
| 57.00 |
|
| 2017 | Three-Way Collars | ICE Brent | 2,000 | — |
| | 43.00 |
| 50.00 |
| 63.15 |
|
| 2017 | Three-Way Collars | Dated Brent | 2,000 | — |
| | 35.00 |
| 45.00 |
| 66.33 |
|
| 2018 | Three-Way Collars | NYMEX WTI | 10,000 | — |
| | 45.50 |
| 52.50 |
| 69.09 |
|
| 2018 | Three-Way Collars | Dated Brent | 3,000 | — |
| | 40.00 |
| 50.00 |
| 70.41 |
|
| 2018 | Swaptions (3) | NYMEX WTI | 3,000 | 56.10 |
| | — |
| — |
| — |
|
| |
(1)
| We have entered into contracts for portions of 2017 resulting in the difference in hedged volumes for the full year. |
| |
(2)
| We have entered into crude oil derivative enhanced swaps with strike prices that are above the market value as of trade commencement. To effect the enhanced swap structure, we sold call options to the applicable counterparty to receive the above market terms. |
| |
(3)
| We have entered into certain derivative contracts (swaptions), which give counterparties the right, but not the obligation, to enter into swap agreements with us on the option expiration dates. |
Subsequent EventSubsequent to June 30, 2017, we entered into additional ICE Brent crude oil derivative contracts including:
|
| | | | | | | | | | | | | | | | |
| | | | | Swaps | | Collars |
Settlement
Period | Type of Contract | Index | Bbls Per
Day | Weighted
Average
Fixed
Price | | Weighted
Average
Short Put
Price | Weighted
Average
Floor
Price | Weighted
Average
Ceiling
Price |
| 2018 | Three-Way Collars | ICE Brent | 5,000 | $ | — |
| | $ | 43.00 |
| $ | 50.00 |
| $ | 59.50 |
|
| 2018 | Two-Way Collars | ICE Brent | 2,000 | — |
| | — |
| 50.00 |
| 55.25 |
|
| 2019 | Three-Way Collars | ICE Brent | 3,000 | — |
| | 43.00 |
| 50.00 |
| 64.07 |
|
Noble Energy, Inc.
Notes to Consolidated Financial Statements
As of June 30, 2017,2018, the following natural gas derivative contracts were outstanding: |
| | | | | | | | | | | | | | | | | |
| | | | | Swaps | | Collars |
Settlement Period | Type of Contract | Index | MMBtu Per Day | Weighted Average Fixed Price | | Weighted Average Short Put Price | Weighted Average Floor Price | Weighted Average Ceiling Price |
| 2018 | Three-Way Collars | NYMEX HH | 120,000 |
| $ | — |
| | $ | 2.50 |
| $ | 2.88 |
| $ | 3.65 |
|
|
| | | | | | | | | | | | | | | | |
| | | | | Swaps | | Collars |
Settlement Period | Type of Contract | Index | MMBtu Per Day | Weighted Average Fixed Price | | Weighted Average Short Put Price | Weighted Average Floor Price | Weighted Average Ceiling Price |
| 2017 | Three-Way Collars | NYMEX HH | 110,000 | $ | — |
| | $ | 2.58 |
| $ | 2.93 |
| $ | 3.65 |
|
| 2017 | Two-Way Collars | NYMEX HH | 70,000 | — |
| | — |
| 2.93 |
| 3.32 |
|
| 2018 | Three-Way Collars | NYMEX HH | 120,000 | — |
| | 2.50 |
| 2.88 |
| 3.65 |
|
| 2018 | Swaptions(1) | NYMEX HH | 30,000 | 3.36 |
| | — |
| — |
| — |
|
| |
(1)
| We have entered into certain derivative contracts (swaptions), which give counterparties the right, but not the obligation, to enter into swap agreements with us on the option expiration dates. |
In second quarter 2017, we reduced our natural gas hedge portfolio as a result of the Marcellus Shale upstream divestiture and terminated certain natural gas three-way collars covering the remainder of 2017, resulting in a de minimis gain from cash received. In addition, we transfered certain natural gas swaps to the acquirer of the Marcellus Shale upstream assets, resulting in a de minimis loss.
Fair Value Amounts and Loss (Gain) Loss on Commodity Derivative InstrumentsThe fair values of commodity derivative instruments in our consolidated balance sheets were as follows: |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Fair Value of Derivative Instruments |
| | Asset Derivative Instruments | | Liability Derivative Instruments |
| | June 30,
2018 | | December 31,
2017 | | June 30,
2018 | | December 31,
2017 |
| (millions) | Balance Sheet Location | | Fair Value | | Balance Sheet Location | | Fair Value | | Balance Sheet Location | | Fair Value | | Balance Sheet Location | | Fair Value |
Commodity Derivative Instruments | Current Assets | | $ | 29 |
| | Current Assets | | $ | 2 |
| | Current Liabilities | | $ | 250 |
| | Current Liabilities | | $ | 58 |
|
| | Noncurrent Assets | | — |
| | Noncurrent Assets | | — |
| | Noncurrent Liabilities | | 85 |
| | Noncurrent Liabilities | | 15 |
|
| Total | | | $ | 29 |
| | | | $ | 2 |
| | | | $ | 335 |
| | | | $ | 73 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Fair Value of Derivative Instruments |
| | Asset Derivative Instruments | | Liability Derivative Instruments |
| | June 30,
2017 | | December 31,
2016 | | June 30,
2017 | | December 31,
2016 |
| (millions) | Balance Sheet Location | | Fair Value | | Balance Sheet Location | | Fair Value | | Balance Sheet Location | | Fair Value | | Balance Sheet Location | | Fair Value |
Commodity Derivative Instruments | Current Assets | | $ | 23 |
| | Current Assets | | $ | — |
| | Current Liabilities | | $ | — |
| | Current Liabilities | | $ | 102 |
|
| | Noncurrent Assets | | 8 |
| | Noncurrent Assets | | — |
| | Noncurrent Liabilities | | — |
| | Noncurrent Liabilities | | 14 |
|
| Total | | | $ | 31 |
| | | | $ | — |
| | | | $ | — |
| | | | $ | 116 |
|
The effect of commodity derivative instruments on our consolidated statements of operations was as follows: |
| | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| (millions) | 2018 | | 2017 | | 2018 | | 2017 |
| Cash Paid (Received) in Settlement of Commodity Derivative Instruments | | | | | | | |
| Crude Oil | $ | 66 |
| | $ | (11 | ) | | $ | 96 |
| | $ | (16 | ) |
| Natural Gas | (1 | ) | | — |
| | (3 | ) | | 2 |
|
| Total Cash Paid (Received) in Settlement of Commodity Derivative Instruments | 65 |
| | (11 | ) | | 93 |
| | (14 | ) |
| Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments | | | | | | | |
| Crude Oil | 181 |
| | (28 | ) | | 231 |
| | (91 | ) |
| Natural Gas | 3 |
| | (18 | ) | | 4 |
| | (62 | ) |
| Total Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments | 184 |
| | (46 | ) | | 235 |
| | (153 | ) |
| Loss (Gain) on Commodity Derivative Instruments | | | | | | | |
| Crude Oil | 247 |
| | (39 | ) | | 327 |
| | (107 | ) |
| Natural Gas | 2 |
| | (18 | ) | | 1 |
| | (60 | ) |
| Total Loss (Gain) on Commodity Derivative Instruments | $ | 249 |
| | $ | (57 | ) | | $ | 328 |
| | $ | (167 | ) |
|
| | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| (millions) | 2017 | | 2016 | | 2017 | | 2016 |
| Cash (Received) Paid in Settlement of Commodity Derivative Instruments | | | | | | | |
| Crude Oil | $ | (11 | ) | | $ | (120 | ) | | $ | (16 | ) | | $ | (276 | ) |
| Natural Gas | — |
| | (24 | ) | | 2 |
| | (46 | ) |
| Total Cash Received in Settlement of Commodity Derivative Instruments | (11 | ) | | (144 | ) | | (14 | ) | | (322 | ) |
| Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments | | | | | | | |
| Crude Oil | (28 | ) | | 233 |
| | (91 | ) | | 360 |
|
| Natural Gas | (18 | ) | | 62 |
| | (62 | ) | | 69 |
|
| Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments | (46 | ) | | 295 |
| | (153 | ) | | 429 |
|
| (Gain) Loss on Commodity Derivative Instruments | | | | | | | |
| Crude Oil | (39 | ) | | 113 |
| | (107 | ) | | 84 |
|
| Natural Gas | (18 | ) | | 38 |
| | (60 | ) | | 23 |
|
| Total (Gain) Loss on Commodity Derivative Instruments | $ | (57 | ) | | $ | 151 |
| | $ | (167 | ) | | $ | 107 |
|
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
Note 6.5. Debt
Debt consists of the following: |
| | | | | | | | | | | | | |
| | June 30,
2018 | | December 31,
2017 |
| (millions, except percentages) | Debt | | Interest Rate |
| | Debt | | Interest Rate |
| Revolving Credit Facility, due March 9, 2023 | $ | — |
| | — | % | | $ | 230 |
| | 2.27 | % |
| Noble Midstream Services Revolving Credit Facility, due March 9, 2023 | 530 |
| | 3.25 | % | | 85 |
| | 2.75 | % |
| Leviathan Term Loan Facility, due February 23, 2025 | — |
| | — | % | | — |
| | — | % |
Senior Notes, due May 1, 2021 (1) | — |
| | — | % | | 379 |
| | 5.63 | % |
| Senior Notes, due December 15, 2021 | 1,000 |
| | 4.15 | % | | 1,000 |
| | 4.15 | % |
| Senior Notes, due October 15, 2023 | 100 |
| | 7.25 | % | | 100 |
| | 7.25 | % |
| Senior Notes, due November 15, 2024 | 650 |
| | 3.90 | % | | 650 |
| | 3.90 | % |
| Senior Notes, due April 1, 2027 | 250 |
| | 8.00 | % | | 250 |
| | 8.00 | % |
| Senior Notes, due January 15, 2028 | 600 |
| | 3.85 | % | | 600 |
| | 3.85 | % |
| Senior Notes, due March 1, 2041 | 850 |
| | 6.00 | % | | 850 |
| | 6.00 | % |
| Senior Notes, due November 15, 2043 | 1,000 |
| | 5.25 | % | | 1,000 |
| | 5.25 | % |
| Senior Notes, due November 15, 2044 | 850 |
| | 5.05 | % | | 850 |
| | 5.05 | % |
| Senior Notes, due August 15, 2047 | 500 |
| | 4.95 | % | | 500 |
| | 4.95 | % |
Other Senior Notes and Debentures (2) | 92 |
| | 7.13 | % | | 92 |
| | 7.13 | % |
| Capital Lease Obligations | 241 |
| | — | % | | 273 |
| | — | % |
| Total | 6,663 |
| | | | 6,859 |
| | |
| Unamortized Discount | (23 | ) | | | | (24 | ) | | |
Unamortized Premium (1) | — |
| | | | 12 |
| | |
| Unamortized Debt Issuance Costs | (38 | ) | | | | (40 | ) | | |
| Total Debt, Net of Unamortized Discount, Premium and Debt Issuance Costs | 6,602 |
| | | | 6,807 |
| | |
| Less Amounts Due Within One Year | | | | | | | |
| Capital Lease Obligations | (47 | ) | | | | (61 | ) | | |
| Long-Term Debt Due After One Year | $ | 6,555 |
| | | | $ | 6,746 |
| | |
|
| | | | | | | | | | | | | |
| | June 30,
2017 | | December 31,
2016 |
| (millions, except percentages) | Debt | | Interest Rate | | Debt | | Interest Rate |
| Revolving Credit Facility, due August 27, 2020 | $ | — |
| | — | % | | $ | — |
| | — | % |
| Noble Midstream Services Revolving Credit Facility, due September 20, 2021 | 190 |
| | 2.32 | % | | — |
| | — | % |
| Term Loan Facility, due January 6, 2019 | 550 |
| | 2.44 | % | | 550 |
| | 2.01 | % |
| Leviathan Term Loan Facility, due February 23, 2025 | — |
| | — | % | | — |
| | — | % |
| 8.25% Senior Notes, due March 1, 2019 | 1,000 |
| | 8.25 | % | | 1,000 |
| | 8.25 | % |
| 5.625% Senior Notes, due May 1, 2021 | 379 |
| | 5.625 | % | | 379 |
| | 5.625 | % |
| 4.15% Senior Notes, due December 15, 2021 | 1,000 |
| | 4.15 | % | | 1,000 |
| | 4.15 | % |
| 5.875% Senior Notes, due June 1, 2022 | 18 |
| | 5.875 | % | | 18 |
| | 5.875 | % |
| 7.25% Senior Notes, due October 15, 2023 | 100 |
| | 7.25 | % | | 100 |
| | 7.25 | % |
| 5.875% Senior Notes, due June 1, 2024 | 8 |
| | 5.875 | % | | 8 |
| | 5.875 | % |
| 3.90% Senior Notes, due November 15, 2024 | 650 |
| | 3.90 | % | | 650 |
| | 3.90 | % |
| 8.00% Senior Notes, due April 1, 2027 | 250 |
| | 8.00 | % | | 250 |
| | 8.00 | % |
| 6.00% Senior Notes, due March 1, 2041 | 850 |
| | 6.00 | % | | 850 |
| | 6.00 | % |
| 5.25% Senior Notes, due November 15, 2043 | 1,000 |
| | 5.25 | % | | 1,000 |
| | 5.25 | % |
| 5.05% Senior Notes, due November 15, 2044 | 850 |
| | 5.05 | % | | 850 |
| | 5.05 | % |
| 7.25% Senior Debentures, due August 1, 2097 | 84 |
| | 7.25 | % | | 84 |
| | 7.25 | % |
Capital Lease and Other Obligations (1) | 307 |
| | — | % | | 375 |
| | — | % |
| Total | 7,236 |
| | | | 7,114 |
| | |
| Unamortized Discount | (22 | ) | | | | (23 | ) | | |
| Unamortized Premium | 15 |
| | | | 17 |
| | |
| Unamortized Debt Issuance Costs | (32 | ) | | | | (34 | ) | | |
| Total Debt, Net of Unamortized Discount, Premium and Debt Issuance Costs | 7,197 |
| | | | 7,074 |
| | |
| Less Amounts Due Within One Year | | | | | | | |
| Capital Lease Obligations | (64 | ) | | | | (63 | ) | | |
| Long-Term Debt Due After One Year | $ | 7,133 |
| | | | $ | 7,011 |
| | |
(1) The reduction includes $41 million related to certain drilling commitments assumed by the acquirerIn second quarter 2018, we redeemed all of the Marcellus Shale upstream assets.Senior Notes due May 1, 2021, writing off the associated premium. See Note 4. AcquisitionsRedemption of Senior Notes, below. (2) Includes $8 million of Senior Notes due June 1, 2024 and Divestitures and Note 12. Commitments and Contingencies$84 million of Senior Debentures due August 1, 2097. The weighted average interest rate for these instruments is 7.13%. Revolving Credit Facility Our Credit Agreement, as amended, provides for a $4 billion unsecured revolving credit facility (Revolving Credit Facility), which is available for general corporate purposes. The Revolving Credit Facility (i) provides for facility fee rates that range from 10 basis points to 25 basis points per year depending upon our credit rating, (ii) provides for interest rates that are based upon the Eurodollar rate plus a margin that ranges from 90 basis points to 150 basis points depending upon our credit rating.rating and (iii) includes sub-facilities for short-term loans and letters of credit up to an aggregate amount of $500 million under each sub-facility.
On April 24, 2017,In first quarter 2018, we borrowed $1.3 billion to fundextended the cash portionmaturity date of the Clayton Williams Energy Acquisition consideration, redeem assumed Clayton Williams Energy long-term debt, pay associated make-whole premiums, pay related fees and expenses associated withRevolving Credit Facility from August 2020 to March 2023. As of June 30, 2018, no borrowings were outstanding under the transaction and to fund other general corporate expenditures. We repaid all outstanding borrowings during second quarter 2017 with proceeds received from the Marcellus Shale upstream divestiture, cash on hand, and cash generated by the Noble Midstream Partners private placement of limited partner units and Noble Midstream Services borrowings. The outstanding borrowing was subject to a floating interest rate which was 2.02% on April 24, 2017.Revolving Credit Facility.
Noble Midstream Services Revolving Credit FacilityIn 2016, Noble Midstream Services, LLC, a subsidiary of Noble Midstream Partners, entered intomaintains a credit agreement for a $350 million revolving credit facility (Noble Midstream Services Revolving Credit Facility), which is available to fund working capital and to finance acquisitions and other capital expenditures of Noble Midstream Partners.
In first quarter 2018, the facility capacity was increased from $350 million to $800 million and the maturity date was extended from September 2021 to March 2023.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
Borrowings by Noble Midstream Partners under the Noble Midstream Services Revolving Credit Facility bear interest at a rate equal to an applicable margin plus, at Noble Midstream Partners' option, either (a) in the case of base rate borrowings, a rate equal to the highest of (1) the prime rate, (2) the greater of the federal funds rate or the overnight bank funding rate, plus 0.5% and (3) the LIBOR for an interest period of one month plus 1.00%; or (b) in the case of LIBOR borrowings, the offered rate per annum for deposits of dollars for the applicable interest period.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
As of June 30, 2017, $1902018, $530 million was outstanding under the Noble Midstream Services Revolving Credit Facility whichFacility. The increase from December 31, 2017 was primarily used to partially fund acquisitions.the Saddle Butte acquisition, as well as construction activities. See Note 4.3. Acquisitions and Divestitures. Leviathan Term Loan Agreement On February 24, 2017, Noble Energy Mediterranean Ltd. (NEML), a wholly owned subsidiary of Noble Energy, entered into a facility agreement (Leviathan Term Loan Facility) which provides for a limited recourse secured term loan facility with an aggregate principal borrowing amount of up to $1.0 billion, $625 million of which $625 million is initially committed. Any amounts borrowed under the Leviathan Term Loan Facility will be available to fund a portion of our share of costs for the initial phase of development of the Leviathan field offshore Israel.
Any amounts borrowed will be subject to repayment on a quarterly basis following production startup for the first phase of development, which is targeted for the end of 2019. Repayment will be in accordance with an amortization schedule set forth in the facility agreement, with a final balloon payment of no more than 35% of the loans outstanding. The Leviathan Term Loan Facility matures on February 23, 2025, and we can prepay borrowings at any time, in whole or in part, without penalty. The Leviathan Term Loan Facility contains customary representations and warranties, affirmative and negative covenants, events of default and also includes a prepayment mechanism that reduces the final balloon amount if cash flows exceed certain defined coverage ratios.
Any amounts borrowed will accrue interest at LIBOR, plus a margin of 3.50% per annum prior to production startup, 3.25% during the period following production startup until the last two years of maturity, and 3.75% during the last two years until the maturity date. We are also required to pay a commitment fee equal to 1.00% per annum on the unused and available commitments under the Leviathan Term Loan Facility until the beginning of the repayment period.
The Leviathan Term Loan Facility is secured by a first priority security interest in substantially all of NEML's interests in the Leviathan field and its marketing subsidiary, and in assets related to the initial phase of the project. All of NEML’s revenues from the first phase of Leviathan development will be deposited in collateral accounts and we will be required to maintain a debt service reserve account for the benefit of the lenders under the Leviathan Term Loan Facility. Once servicing accounts are replenished and debt service made, all remaining cash will be available to us and our subsidiaries.
Term Loan Agreement and Completed Tender OffersIn 2016, we entered into a term loan agreement (Term Loan Facility) which provides for a three-year term loan facility for a principal amount of $1.4 billion. The Term Loan Facility accrues interest, at our option, at either (a) a base rate equal to the highest of (i) the rate announced by Citibank, N.A., as its prime rate, (ii) the Federal Funds Rate plus 0.5%, and (iii) LIBOR plus 1.0%, plus a margin that ranges from 10 basis points to 75 basis points depending upon our credit rating, or (b) LIBOR plus a margin that ranges from 100 basis points to 175 basis points depending upon our credit rating.
Borrowings under the Term Loan Facility were used solely to fund tender offers for approximately $1.38 billion of notes assumed in our merger with Rosetta Resources Inc. in 2015. As a result, we recognized a gain of $80 million in first quarter 2016 which is reflected in other operating (income) expense, net in our consolidated statements of operations. In fourth quarter 2016, we prepaid $850 million of long-term debt outstanding under the Term Loan Facility from cash on hand. As of June 30, 2017, $550 million was outstanding2018, there were no borrowings under the facility.Leviathan Term Loan Facility.
See Note 7.6. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of debt. Redemption of Senior Notes In May 2018, we redeemed $379 million of Senior Notes due May 1, 2021 that we assumed in the merger (Rosetta Merger) with Rosetta Resources, Inc. in 2015 for $395 million, including $11 million of accrued interest and $5 million of call premium. We fully amortized $10 million of remaining premium and recognized a gain of $5 million, which is reflected in other non-operating (income) expense in our consolidated statements of operations.
Annual Debt Maturities Our nearest annual maturity of outstanding debt, excluding capital lease payments and outstanding balances under the revolving credit facilities, is $1.0 billion of senior notes which mature in 2021. The Revolving Credit Facility and Noble Midstream Services Revolving Credit Facility both mature in March 2023. No other balances are due within the next five years.
Subsequent Event - Noble Midstream Services Term Credit Agreement On July 31, 2018, Noble Midstream Services, LLC entered into a three year senior unsecured term loan credit facility (Noble Midstream Services Term Credit Agreement) that permits aggregate borrowings of up to $500 million. Proceeds from the Noble Midstream Services Term Credit Agreement will be used to repay a portion of the outstanding borrowings under the Noble Midstream Services Revolving Credit Facility, pay fees and expenses in connection with the Noble Midstream Services Term Credit Agreement transactions and for working capital, capital expenditures, acquisitions and other purposes as necessary of Noble Midstream Partners and its subsidiaries.
Borrowings under the Noble Midstream Services Term Credit Agreement will bear interest at a rate equal to, at Noble Midstream Partners' option, either (1) a base rate plus an applicable margin between 0.00% and 0.50% per annum or (2) a Eurodollar rate plus an applicable margin between 1.00% and 1.50% per annum.
The Noble Midstream Services Term Credit Agreement contains customary representations and warranties, affirmative and negative covenants, and events of default that are substantially the same as those contained in the Noble Midstream Services Revolving Credit Facility. Upon the occurrence and during the continuation of an event of default under the Noble Midstream
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
Services Term Credit Agreement, the lenders may declare all amounts outstanding under the Noble Midstream Services Term Credit Agreement to be immediately due and payable and exercise other remedies as provided by applicable law.
Note 7.6. Fair Value Measurements and Disclosures
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:
Cash, Cash Equivalents, Accounts Receivable and Accounts Payable The carrying amounts approximate fair value due to the short-term nature or maturity of the instruments.
Mutual Fund Investments Our mutual fund investments consist of various publicly-traded mutual funds that include investments ranging from equities to money market instruments. The fair values are based on quoted market prices for identical assets.
Commodity Derivative Instruments Our commodity derivative instruments may include variable to fixed price commodity swaps, two-way collars, three-way collars, swaptions, enhanced swaps and enhancedbasis swaps. 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 the fair
Noble Energy, Inc.
Notes to Consolidated Financial Statements
values of commodity derivative 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 option values of the put options sold and the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract terms. SeeNote 5.4. Derivative Instruments and Hedging Activities. Investment in Tamar Petroleum Ltd Our investment in shares of Tamar Petroleum was acquired on March 14, 2018. The fair value of these shares is determined at the end of each quarter based on the trading price of Tamar Petroleum shares on the Tel Aviv Stock Exchange and is reduced by a 15% discount. The discount rate is based on analysis of historical discounts realized in private placements of public common stock, which we believe represents a reasonable estimate of the impact of the temporary lock-up provisions applicable to the shares we own. See Note 2. Basis of Presentation and Note 3. Acquisitions and Divestitures. Deferred Compensation LiabilityThe value is dependent upon the fair values of mutual fund investments and shares of our common stock held in a rabbi trust.See Mutual Fund Investments above.
Stock-Based Compensation Liability A portion of the value of the liability associated with our phantom unit plan is dependent upon the fair value of Noble Energy common stock as of the end of each reporting period.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
Measurement information for assets and liabilities that are measured at fair value on a recurring basis was as follows:
| | | | Fair Value Measurements Using | | | | | | | | | | | | | | | |
| | Quoted Prices in Active Markets (Level 1) (1) | | Significant Other Observable Inputs (Level 2) (2) | | Significant Unobservable Inputs (Level 3) (3) | | Adjustment (4) | | Fair Value Measurement | Fair Value Measurements Using | | | | |
| (millions) | | | | | | | | | | Quoted Prices in Active Markets (Level 1) (1) | | Significant Other Observable Inputs (Level 2) (2) | | Significant Unobservable Inputs (Level 3) (3) | | Adjustment (4) | | Fair Value Measurement |
| June 30, 2017 | | | | | | | | | | |
| Financial Assets | | | | | | | | | | |
| June 30, 2018 | | | | | | | | | | |
| Financial Assets: | | | | | | | | | | |
| Mutual Fund Investments | $ | 67 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 67 |
| $ | 57 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 57 |
|
| Commodity Derivative Instruments | — |
| | 34 |
| | — |
| | (3 | ) | | 31 |
| — |
| | 72 |
| | — |
| | (43 | ) | | 29 |
|
| Financial Liabilities | | | | | | | | | | |
Investment in Tamar Petroleum Ltd. (38,495,575 Shares) (5) | | — |
| | 150 |
| | — |
| | — |
| | 150 |
|
| Financial Liabilities: | | | | | | | | | | |
| Commodity Derivative Instruments | — |
| | (3 | ) | | — |
| | 3 |
| | — |
| — |
| | (378 | ) | | — |
| | 43 |
| | (335 | ) |
| Portion of Deferred Compensation Liability Measured at Fair Value | (86 | ) | | — |
| | — |
| | — |
| | (86 | ) | (73 | ) | | — |
| | — |
| | — |
| | (73 | ) |
| Stock Based Compensation Liability Measured at Fair Value | (12 | ) | | — |
| | — |
| | — |
| — |
| (12 | ) | (12 | ) | | — |
| | — |
| | — |
| | (12 | ) |
| December 31, 2016 | | | | | | | | | | |
| Financial Assets | | | | | | | | | | |
| December 31, 2017 | | | | | | | | | | |
| Financial Assets: | | | | | | | | | | |
| Mutual Fund Investments | $ | 71 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 71 |
| $ | 57 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 57 |
|
| Commodity Derivative Instruments | — |
| | 5 |
| | | | (5 | ) | | — |
| — |
| | 7 |
| | — |
| | (5 | ) | | 2 |
|
| Financial Liabilities | | | | | | | | | | |
| Financial Liabilities: | | | | | | | | | | |
| Commodity Derivative Instruments | — |
| | (121 | ) | | — |
| | 5 |
| | (116 | ) | — |
| | (78 | ) | | — |
| | 5 |
| | (73 | ) |
| Portion of Deferred Compensation Liability Measured at Fair Value | (88 | ) | | — |
| | — |
| | — |
| | (88 | ) | (71 | ) | | — |
| | — |
| | — |
| | (71 | ) |
| Stock Based Compensation Liability Measured at Fair Value | (9 | ) | | — |
| | — |
| | — |
| | (9 | ) | (10 | ) | | — |
| | — |
| | — |
| | (10 | ) |
| |
(1) | Level 1 measurements are fair value measurements which use quoted market prices (unadjusted) in active markets for identical assets or liabilities. We use Level 1 inputs when available as Level 1 inputs generally provide the most reliable evidence of fair value. |
| |
(2) | Level 2 measurements are fair value measurements which use inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly. |
| |
(3) | Level 3 measurements are fair value measurements which use unobservable inputs. |
| |
(4) | Amount represents the impact of netting provisions within our master agreements that allow us to net cash settle asset and liability positions with the same counterparty. |
| |
(5) | As of June 30, 2018, the closing price on the TASE of publicly traded and unrestricted shares of Tamar Petroleum Ltd. was $4.60 per share. |
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Certain assets and liabilities such, as inventory, oil and gas properties, goodwill and other intangible assets, held for sale are not required to be measured at fair value on a nonrecurring basis in our consolidated balance sheets.recurring basis. However, these assets are assessed for impairment, and a resulting asset impairment would require the asset be recorded at fair value.
Asset Impairments During first quarter 2018, upon classification of the Gulf of Mexico properties as assets held for sale, we recognized an impairment of $168 million. See Note 3. Acquisitions and Divestitures. For second quarter 2018 and the first six months ended June 30,of 2017, and 2016, we had no adjustments in fair value related to these items. Other items measured at fair value on a nonrecurring basis are discussed below. Marcellus Shale Firm Transportation Liability As of June 30, 2017, we recorded a $41 million liability representing the discounted present value of our remaining obligation under a firm transportation contract. See Note 12. Commitmentsoil and Contingencies.Noble Energy, Inc.
Notes to Consolidated Financial Statements
gas properties.
Additional Fair Value Disclosures
Investment in CNX Midstream Partners Our investment in CNX Midstream Partners, which is included in our Midstream reportable segment, is accounted for using the equity method. The fair value of the investment is based on the published market price of the common units for the date indicated below. |
| | | | | | | | | | | | | | | |
| | June 30, 2018 | | December 31, 2017 |
| (millions) | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
Investment in CNX Midstream Partners (14,217,198 Common Units and 21,692,198 Common Units, respectively) (1) | $ | 49 |
| | $ | 276 |
| | $ | 70 |
| | $ | 364 |
|
Debt The fair value of fixed-rate, public debt is estimated based on the published market prices for the same or similar issues. As such, we consider the fair value of our public, fixed-rate debt to be a Level 1 measurement on the fair value hierarchy.
Our Term LoanRevolving Credit Facility, and the Noble Midstream Services Revolving Credit Facility and the Leviathan Term Loan Facility are variable-rate, non-public debt. The fair value is estimated based on significant other observable inputs. As such, we consider the fair value of these facilities to be a Level 2 measurement on the fair value hierarchy. See Note 6.5. Debt. Fair value information regarding our debt is as follows: | | | | June 30, 2017 | | December 31, 2016 | June 30, 2018 | | December 31, 2017 |
| (millions) | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
Long-Term Debt, Net (1) | $ | 6,890 |
| | $ | 7,373 |
| | $ | 6,699 |
| | $ | 7,112 |
| |
Long-Term Debt (1) | | $ | 6,422 |
| | $ | 6,591 |
| | $ | 6,586 |
| | $ | 7,142 |
|
| |
(1) | Net ofExcludes unamortized discount, premium, and debt issuance costs and excludes capital lease and other obligations. |
Note 8.7. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs
Capitalized Exploratory Well CostsWe capitalize exploratory well costs until a determination is made that the well has found proved reserves or is deemed noncommercial. On a quarterly basis, we review the status of suspended exploratory well costs and assess the development of these projects. If a well is deemed to be noncommercial, the well costs are charged to exploration expense as dry hole cost.
Changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and subsequently expensed in the same period: |
| | | |
| (millions) | Six Months Ended June 30, 2018 |
| Capitalized Exploratory Well Costs, Beginning of Period | $ | 520 |
|
| Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves | 4 |
|
Divestitures (1) | (167 | ) |
| Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves | (1 | ) |
| Capitalized Exploratory Well Costs Charged to Expense | — |
|
| Capitalized Exploratory Well Costs, End of Period | $ | 356 |
|
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
|
| | | |
| (millions) | Six Months Ended June 30, 2017 |
| Capitalized Exploratory Well Costs, December 31, 2016 | $ | 768 |
|
| Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves | 6 |
|
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves (1) | (203 | ) |
| Capitalized Exploratory Well Costs, June 30, 2017 | $ | 571 |
|
| |
(1)
| Amount relates to the approval and sanction of the first phase of development of the Leviathan field, offshore Israel. During second quarter 2017, we recorded Leviathan field proved undeveloped reserves of 551 MMBoe, net. |
The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced:
|
| | | | | | | |
| (millions) | June 30,
2018 | | December 31,
2017 |
| Exploratory Well Costs Capitalized for a Period of One Year or Less | $ | 8 |
| | $ | 10 |
|
| Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 348 |
| | 510 |
|
| Balance at End of Period | $ | 356 |
| | $ | 520 |
|
| Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 7 |
| | 8 |
|
|
| | | | | | | |
| (millions) | June 30,
2017 | | December 31,
2016 |
| Exploratory Well Costs Capitalized for a Period of One Year or Less | $ | 19 |
| | $ | 69 |
|
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling (1) | 552 |
| | 699 |
|
| Balance at June 30, 2017 | $ | 571 |
| | $ | 768 |
|
| |
(1)
| The decrease from December 31, 2016 is attributable to the reclassification of the Leviathan field to development work in process, partially offset by the capitalization of interest during the period on remaining exploratory wells. |
Undeveloped Leasehold Costs
We reclassify undeveloped leasehold costs to proved property costs when, as a result of exploration and development activities, probable and possible resources are reclassified to proved reserves, including proved undeveloped reserves, become attributable toreserves. On the property as a result of our exploration and development activities.
Noble Energy, Inc.
Notes to Consolidated Financial Statements
As of June 30, 2017, we had remaining undeveloped leasehold costs, to which proved reserves had not been attributed, of $3.1 billion, primarily related to properties acquired of $1.6 billion in the Clayton Williams Energy Acquisition, and $1.2 billion and $185 million attributable to Delaware Basin and Eagle Ford Shale assets, respectively, acquired in the Rosetta Resources Inc. acquisition. Undeveloped leasehold costs were derived from allocated fair values as a result of business combinations or other purchases of unproved properties and, in that the properties are primarily held by production, they are subject to impairment testing utilizing a future cash flows analysis.
The remaining undeveloped leasehold costs as of June 30, 2017 included $86 million related to Gulf of Mexico unproved properties and $52 million related to international unproved properties. These costs are evaluated as part of our periodic impairment review. If,hand, if, based upon a change in exploration plans, timing and extent of development activities, availability of capital and suitable rig and drilling equipment, resource potential, comparative economics, changing regulations and/or other factors, an impairment is indicated, we will record impairment expense related to the respective leases.leases or licenses.
As of June 30, 2018, we had remaining undeveloped leasehold costs, to which proved reserves had not been attributed, of $2.6 billion, including $1.6 billion related to Delaware Basin assets acquired in the Clayton Williams Energy Acquisition in 2017, and $859 million and $129 million attributable to Delaware Basin and Eagle Ford Shale assets, respectively, acquired in the Rosetta Merger in 2015. Undeveloped leasehold costs were derived from allocated fair values as a result of business combinations or other purchases of unproved properties and are subject to impairment testing.
The remaining balance of undeveloped leasehold costs as of June 30, 2018 included $53 million related to international unproved properties. These costs pertain to acquired leases or licenses that are subject to expiration over the next several years unless production is established on units containing the acreage. These costs are evaluated as part of our periodic impairment review.
During the first six monthshalf of 2017,2018, we completed a geological evaluationtransferred $247 million and $20 million of certainundeveloped leasehold costs associated with Delaware Basin and Eagle Ford Shale assets, respectively, to proved properties. These transfers resulted from additions of proved reserves through development activities. In addition, $43 million of capitalized costs associated with Gulf of Mexico leases and determined that $18 million oflicenses was removed from undeveloped leasehold cost should be written-off.costs due to divestiture of the associated assets in second quarter 2018. See Note 3. Acquisitions and Divestitures. Note 9.8. 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: |
| | | | | | | |
| | Six Months Ended June 30, |
| (millions) | 2018 | | 2017 |
| Asset Retirement Obligations, Beginning Balance | $ | 875 |
| | $ | 935 |
|
| Liabilities Incurred | 14 |
| | 82 |
|
| Liabilities Settled | (261 | ) | | (32 | ) |
| Revisions of Estimates | (10 | ) | | (15 | ) |
Accretion Expense (1) | 17 |
| | 23 |
|
| Asset Retirement Obligations, Ending Balance | $ | 635 |
| | $ | 993 |
|
|
| | | | | | | |
| | Six Months Ended June 30, |
| (millions) | 2017 | | 2016 |
| Asset Retirement Obligations, Beginning Balance | $ | 935 |
| | $ | 989 |
|
| Liabilities Incurred | 82 |
| | 3 |
|
| Liabilities Settled | (32 | ) | | (38 | ) |
| Revision of Estimate | (15 | ) | | 4 |
|
Accretion Expense (1) | 23 |
| | 25 |
|
| Asset Retirement Obligations, Ending Balance | $ | 993 |
| | $ | 983 |
|
| |
(1) | Accretion expense is included in depreciation, depletion and amortization (DD&A)expense in the consolidated statements ofoperations. |
For the Six Months Ended June 30, 2018 Liabilities settled include $216 million of liabilities assumed by the purchaser of the Gulf of Mexico properties and $44 million related to abandonment of US onshore properties, primarily in the DJ Basin. Revisions of estimates primarily relate to decreases in cost and timing estimates of $11 million associated with the North Sea abandonment project and $6 million for Eastern Mediterranean, partially offset by an increase of $7 million for US onshore.
For theSix Months Ended June 30, 2017 Liabilities incurred include $59 million related to the Clayton Williams Energy Acquisition and $23 million primarily for other US onshore wells and facilities placed into service. Liabilities settled primarily related to US onshore property abandonments, as well as $12 million related to properties sold in the Marcellus Shale upstream divestiture. Revisions of estimates related to decreases in cost and timing estimates of $30 million for US onshore and Gulf of Mexico, partially offset by an increase of $15 million for West Africa.
For theSix Months Ended June 30, 2016 Liabilities incurred were dueNoble Energy, Inc.
Notes to new wells and facilities for onshore US. Liabilities settled primarily related to onshore US property abandonments.Consolidated Financial Statements (Unaudited)
Note 10.9. Income Taxes
The income tax provision (benefit) expense consists of the following: |
| | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| (millions, except percentages) | 2018 | | 2017 | | 2018 | | 2017 |
| Current | $ | 23 |
| | $ | 37 |
| | $ | 149 |
| | $ | 49 |
|
| Deferred | (7 | ) | | (873 | ) | | (164 | ) | | (873 | ) |
| Total Income Tax Expense (Benefit) | $ | 16 |
| | $ | (836 | ) | | $ | (15 | ) | | $ | (824 | ) |
| Effective Tax Rate | 160.0 | % | | 35.8 | % | | (2.7 | )% | | 36.2 | % |
|
| | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| (millions) | 2017 | | 2016 | | 2017 | | 2016 |
Current (1) | $ | 37 |
| | $ | 45 |
| | $ | 49 |
| | $ | 65 |
|
| Deferred | (873 | ) | | (228 | ) | | (873 | ) | | (414 | ) |
| Total Income Tax Benefit | $ | (836 | ) | | $ | (183 | ) | | $ | (824 | ) | | $ | (349 | ) |
| Effective Tax Rate | 35.8 | % | | 36.7 | % | | 36.2 | % | | 36.7 | % |
(1) CurrentOn April 2, 2018, the US Department of the Treasury and the Internal Revenue Service released Notice 2018-26, signaling intent to issue regulations related to the transition tax (toll tax) on a one-time “deemed repatriation” of accumulated foreign earnings for the year ended December 31, 2017. Notice 2018-26 clarifies that an Internal Revenue Code Section 965(n) election is available with respect to both current year operating losses and net operating losses from a prior year. As a result, during first quarter 2018, we released the valuation allowance recorded against foreign tax credits that will be utilized against the $268 million toll tax liability we had recorded as of December 31, 2017, resulting in a $252 million tax benefit, and reduced our estimated toll tax liability to $16 million to be paid in installments over eight years. We also recorded a corresponding expense of $107 million for the tax rate change adjustment on the previously utilized net operating losses. The impact on first quarter 2018 total tax expense, related to this additional guidance, was a net $145 million discrete tax benefit.
During second quarter 2018, we made no changes to the provisional amounts recognized in 2017.
The ultimate impact of the Tax Reform Legislation may differ from our estimates due to changes in interpretations and assumptions made by us, as well as additional regulatory guidance that may be issued. In particular, our estimate of the impact of the toll tax is a provisional amount, based on current legal interpretations. This amount may be adjusted further in future periods, as an adjustment to income taxestax expense or benefit, in the period in which the final amounts are attributable to our operations in Israel and Equatorial Guinea.determined.
Effective Tax Rate (ETR) At the end of each interim period, we apply a forecasted annualized effective tax rate (ETR) to current yearperiod earnings or loss before tax, which can result in significant interim ETR fluctuations. Our ETR for the three andsix months ended June 30, 2018 varied as compared with the six months ended June 30, 2017 variedprimarily due to a deferred tax benefit of $145 million recorded discretely in the current year, as compared withdiscussed above, and a significant deferred tax benefit recorded at the three andhigher prior year US tax rate of 35% on the Marcellus Shale upstream divestiture in second quarter 2017. In addition, the increase in the current income tax expense for the six months ended June 30, 2016 primarily due to a larger discrete tax benefit in the prior year driven by a tax rate change in a foreign jurisdiction. In addition, the significant increase in the deferred tax benefit for the three and six months ended June 30, 20172018 is primarily due to foreign taxes on a gain associated with the loss recorded forfirst quarter 2018 divestiture of a 7.5% interest in the Marcellus Shale upstream divestiture.Tamar field, offshore Israel.
In our major tax jurisdictions, the earliest years remaining open to examination are as follows: US – 20132014, Israel – 2015 (2013 with respect to Israel Oil Profits Tax) and Equatorial Guinea – 2011.
2013.
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
Note 10. Income Per Share Attributable to Noble Energy
Noble Energy's basic income (loss) per share of common stock is computed by dividing net income (loss) attributable to Noble Energy by the weighted average number of shares of Noble Energy common stock outstanding during each period. The following table summarizes the calculation of basic and diluted income (loss) per share: |
| | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| (millions, except per share amounts) | 2018 | | 2017 | | 2018 | | 2017 |
| Net (Loss) Income and Comprehensive (Loss) Income Attributable to Noble Energy | $ | (23 | ) | | $ | (1,512 | ) | | $ | 531 |
| | $ | (1,476 | ) |
| Weighted Average Number of Shares Outstanding, Basic | 484 |
| | 472 |
| | 485 |
| | 452 |
|
| Incremental Shares from Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust | — |
| | — |
| | 2 |
| | — |
|
| Weighted Average Number of Shares Outstanding, Diluted | 484 |
| | 472 |
| | 487 |
| | 452 |
|
| (Loss) Income Per Share, Basic | $ | (0.05 | ) | | $ | (3.20 | ) | | $ | 1.09 |
| | $ | (3.27 | ) |
| (Loss) Income Per Share, Diluted | (0.05 | ) | | (3.20 | ) | | 1.09 |
| | (3.27 | ) |
| Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above | 14 |
| | 16 |
| | 14 |
| | 15 |
|
Note 11. Segment Information
During second quarter 2017, as a result ofWe have the strategic changes in our US onshore portfolio, we established our Midstream business as a newfollowing reportable segment. The Midstream segment, which includes the consolidated accounts of Noble Midstream Partners, additional US onshore midstream assets and US onshore equity method investments, was previously reported within the United States reportable segment. As a result, as of June 30, 2017, we now have five reportable segments,segments: United States (US onshore and Gulf of Mexico)Mexico (until April 2018)); Eastern Mediterranean (Israel and Cyprus); West Africa (Equatorial Guinea, Cameroon and Gabon); Other International (Falkland Islands, Suriname, Canada, and New Ventures); and Midstream. The Midstream segment includes the consolidated accounts of Noble Midstream Partners, US onshore equity method investments and other US onshore midstream assets.
The geographical reportable segments are in the business of crude oil and natural gas acquisition and exploration, development, production, and acquisitionproduction (Oil and Gas Exploration and Production). The Midstream reportable segment owns, acquires, operates, develops and acquiresdevelops domestic midstream infrastructure assets, with current focus areas being the DJ and Delaware Basins.
Prior period amounts Expenses related to debt, headquarters depreciation and corporate general and administrative expenses are presented on a comparable basis.recorded at the corporate level. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Oil and Gas Exploration and Production | | Midstream | | |
| (millions) | Consolidated | | United
States | | Eastern
Mediter- ranean | | West
Africa | | Other Int'l | | United States | | Intersegment Eliminations and Other (1) | | Corporate |
| Three Months Ended June 30, 2018 | | | | | | | | | | | | | | |
| Crude Oil Sales | $ | 749 |
| | $ | 635 |
| | $ | 2 |
| | $ | 112 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| NGL Sales | 137 |
| | 137 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Natural Gas Sales | 214 |
| | 98 |
| | 111 |
| | 5 |
| | — |
| | — |
| | — |
| | — |
|
| Total Crude Oil, NGL and Natural Gas Sales | 1,100 |
| | 870 |
| | 113 |
| | 117 |
| | — |
| | — |
| | — |
| | — |
|
| Income from Equity Method Investees and Other | 64 |
| | — |
| | — |
| | 36 |
| | — |
| | 28 |
| | — |
| | — |
|
| Sales of Purchased Oil and Gas | 66 |
| | 24 |
| | — |
| | — |
| | — |
| | 42 |
| | — |
| | — |
|
| Intersegment Revenues | — |
| | — |
| | — |
| | — |
| | — |
| | 85 |
| | (85 | ) | | — |
|
| Total Revenues | 1,230 |
| | 894 |
| | 113 |
| | 153 |
| | — |
| | 155 |
| | (85 | ) | | — |
|
| Lease Operating Expense | 132 |
| | 114 |
| | 5 |
| | 19 |
| | — |
| | — |
| | (6 | ) | | — |
|
| Production and Ad Valorem Taxes | 50 |
| | 48 |
| | — |
| | — |
| | — |
| | 2 |
| | — |
| | — |
|
| Gathering, Transportation and Processing Expense | 100 |
| | 133 |
| | — |
| | — |
| | — |
| | 22 |
| | (55 | ) | | — |
|
| Other Royalty Expense | 10 |
| | 10 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total Production Expense | 292 |
| | 305 |
| | 5 |
| | 19 |
| | — |
| | 24 |
| | (61 | ) | | — |
|
| DD&A | 465 |
| | 394 |
| | 15 |
| | 26 |
| | — |
| | 22 |
| | (4 | ) | | 12 |
|
| Loss (Gain) on Divestitures | (78 | ) | | 21 |
| | 10 |
| | — |
| | — |
| | (109 | ) | | — |
| | — |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Oil and Gas Exploration and Production | | Midstream | | |
| (In millions) | Consolidated | | United
States | | Eastern
Mediter- ranean | | West
Africa | | Other Int'l | | United States | | Intersegment Eliminations and Other | |
Corporate |
| Three Months Ended June 30, 2017 | | | | | | | | | | | | | | |
| Crude Oil, NGL and Natural Gas Revenues from Third Parties | $ | 1,017 |
| | $ | 780 |
| | $ | 133 |
| | $ | 104 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Income from Equity Method Investees and Other | 42 |
| | — |
| | — |
| | 25 |
| | — |
| | 17 |
| | — |
| | — |
|
| Intersegment Revenues | — |
| | — |
| | — |
| | — |
| | — |
| | 69 |
| | (69 | ) | | — |
|
| Total Revenues | 1,059 |
| | 780 |
| | 133 |
| | 129 |
| | — |
| | 86 |
| | (69 | ) | | — |
|
| DD&A | 503 |
| | 427 |
| | 19 |
| | 39 |
| | 1 |
| | 5 |
| | — |
| | 12 |
|
| Loss on Marcellus Shale Upstream Divestiture | 2,322 |
| | 2,322 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Gain on Commodity Derivative Instruments | (57 | ) | | (51 | ) | | — |
| | (6 | ) | | — |
| | — |
| | — |
| | — |
|
(Loss) Income Before Income Taxes (1) | (2,334 | ) | | (2,319 | ) | | 106 |
| | 72 |
| | (4 | ) | | 58 |
| | (13 | ) | | (234 | ) |
| | | | | | | | | | | | | | | | |
| Three Months Ended June 30, 2016 | | |
| | |
| | |
| | | | | | | | |
|
| Crude Oil, NGL and Natural Gas Revenues from Third Parties | $ | 823 |
| | $ | 576 |
| | $ | 131 |
| | $ | 116 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Income from Equity Method Investees and Other | 24 |
| | — |
| | — |
| | 9 |
| | — |
| | 15 |
| | — |
| | — |
|
| Intersegment Revenues | — |
| | — |
| | — |
| | — |
| | — |
| | 43 |
| | (43 | ) | |
|
|
| Total Revenues | 847 |
| | 576 |
| | 131 |
| | 125 |
| | — |
| | 58 |
| | (43 | ) | | — |
|
| DD&A | 622 |
| | 539 |
| | 19 |
| | 49 |
| | 1 |
| | 5 |
| | — |
| | 9 |
|
| Loss on Divestitures | 23 |
| | 23 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Loss on Commodity Derivative Instruments | 151 |
| | 129 |
| | — |
| | 22 |
| | — |
| | — |
| | — |
| | — |
|
| (Loss) Income Before Income Taxes | (498 | ) | | (409 | ) | | 71 |
| | 18 |
| | (8 | ) | | 39 |
| | — |
| | (209 | ) |
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Purchased Oil and Gas | 71 |
| | 31 |
| | — |
| | — |
| | — |
| | 40 |
| | — |
| | — |
|
| Loss on Commodity Derivative Instruments | 249 |
| | 196 |
| | — |
| | 53 |
| | — |
| | — |
| | — |
| | — |
|
| (Loss) Income Before Income Taxes | 10 |
| | (90 | ) | | 62 |
| | 48 |
| | (13 | ) | | 175 |
| | (18 | ) | | (154 | ) |
| | | | | | | | | | | | | | | | |
| Three Months Ended June 30, 2017 | | |
| | |
| | |
| | | | | | | | |
|
| Crude Oil Sales | $ | 557 |
| | $ | 458 |
| | $ | 1 |
| | $ | 98 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| NGL Sales | 108 |
| | 108 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Natural Gas Sales | 352 |
| | 214 |
| | 132 |
| | 6 |
| | — |
| | — |
| | — |
| | — |
|
| Total Crude Oil, NGL and Natural Gas Sales | 1,017 |
| | 780 |
| | 133 |
| | 104 |
| | — |
| | — |
| | — |
| | — |
|
| Income from Equity Method Investees and Other | 42 |
| | — |
| | — |
| | 25 |
| | — |
| | 17 |
| | — |
| | — |
|
| Intersegment Revenues | — |
| | — |
| | — |
| | — |
| | — |
| | 69 |
| | (69 | ) | | — |
|
| Total Revenues | 1,059 |
| | 780 |
| | 133 |
| | 129 |
| | — |
| | 86 |
| | (69 | ) | | — |
|
| Lease Operating Expense | 124 |
| | 105 |
| | 6 |
| | 18 |
| | — |
| | — |
| | (5 | ) | | — |
|
| Production and Ad Valorem Taxes | 32 |
| | 32 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Gathering, Transportation and Processing Expense | 121 |
| | 142 |
| | — |
| | — |
| | — |
| | 17 |
| | (38 | ) | | — |
|
| Other Royalty Expense | 6 |
| | 6 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total Production Expense | 283 |
| | 285 |
| | 6 |
| | 18 |
| | — |
| | 17 |
| | (43 | ) | | — |
|
| DD&A | 503 |
| | 427 |
| | 19 |
| | 39 |
| | 1 |
| | 5 |
| | — |
| | 12 |
|
| Loss on Marcellus Shale Upstream Divestiture | 2,322 |
| | 2,322 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Loss on Commodity Derivative Instruments | (57 | ) | | (51 | ) | | — |
| | (6 | ) | | — |
| | — |
| | — |
| | — |
|
| (Loss) Income Before Income Taxes | (2,334 | ) | | (2,319 | ) | | 106 |
| | 72 |
| | (4 | ) | | 58 |
| | (13 | ) | | (234 | ) |
| | | | | | | | | | | | | | | | |
| Six Months Ended June 30, 2018 | | |
| | |
| | |
| | | | | | | | |
|
| Crude Oil Sales | $ | 1,522 |
| | $ | 1,317 |
| | $ | 4 |
| | $ | 201 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| NGL Sales | 283 |
| | 283 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Natural Gas Sales | 468 |
| | 218 |
| | 240 |
| | 10 |
| | — |
| | — |
| | — |
| | — |
|
| Total Crude Oil, NGL and Natural Gas Sales | 2,273 |
| | 1,818 |
| | 244 |
| | 211 |
| | — |
| | — |
| | — |
| | — |
|
| Income from Equity Method Investees and Other | 124 |
| | — |
| | — |
| | 71 |
| | — |
| | 53 |
| | — |
| | — |
|
| Sales of Purchased Oil and Gas | 119 |
| | 55 |
| | — |
| | — |
| | — |
| | 64 |
| | — |
| | — |
|
| Intersegment Revenues | — |
| | — |
| | — |
| | — |
| | — |
| | 166 |
| | (166 | ) | | — |
|
| Total Revenues | 2,516 |
| | 1,873 |
| | 244 |
| | 282 |
| | — |
| | 283 |
| | (166 | ) | | — |
|
| Lease Operating Expense | 287 |
| | 240 |
| | 12 |
| | 41 |
| | — |
| | — |
| | (6 | ) | | — |
|
| Production and Ad Valorem Taxes | 104 |
| | 101 |
| | — |
| | — |
| | — |
| | 3 |
| | — |
| | — |
|
| Gathering, Transportation and Processing Expense | 195 |
| | 260 |
| | — |
| | — |
| | — |
| | 43 |
| | (108 | ) | | — |
|
| Other Royalty Expense | 27 |
| | 27 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total Production Expense | 613 |
| | 628 |
| | 12 |
| | 41 |
| | — |
| | 46 |
| | (114 | ) | | — |
|
| DD&A | 933 |
| | 800 |
| | 28 |
| | 52 |
| | — |
| | 38 |
| | (8 | ) | | 23 |
|
| Gain on Divestitures | (666 | ) | | 15 |
| | (376 | ) | | — |
| | — |
| | (305 | ) | | — |
| | — |
|
Noble Energy, Inc.
Notes to Consolidated Financial Statements (Unaudited)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Oil and Gas Exploration and Production | | Midstream | | |
| (In millions) | Consolidated | | United
States | | Eastern
Mediter- ranean | | West
Africa | | Other Int'l | | United States | | Intersegment Eliminations and Other | |
Corporate |
| Six Months Ended June 30, 2017 | | |
| | |
| | |
| | | | | | | | |
|
| Crude Oil, NGL and Natural Gas Revenues from Third Parties | $ | 2,011 |
| | $ | 1,550 |
| | $ | 265 |
| | $ | 196 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Income from Equity Method Investees and Other | 84 |
| | — |
| | — |
| | 52 |
| | — |
| | 32 |
| | — |
| | — |
|
| Intersegment Revenues | — |
| | — |
| | — |
| | — |
| | — |
| | 127 |
| | (127 | ) | | — |
|
| Total Revenues | 2,095 |
| | 1,550 |
| | 265 |
| | 248 |
| | — |
| | 159 |
| | (127 | ) | | — |
|
| DD&A | 1,031 |
| | 886 |
| | 37 |
| | 74 |
| | 2 |
| | 10 |
| | — |
| | 22 |
|
| Loss on Marcellus Shale Upstream Divestiture | 2,322 |
| | 2,322 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Gain on Commodity Derivative Instruments | (167 | ) | | (154 | ) | | — |
| | (13 | ) | | — |
| | — |
| | — |
| | — |
|
(Loss) Income Before Income Taxes (1) | (2,275 | ) | | (2,251 | ) | | 207 |
| | 138 |
| | (11 | ) | | 107 |
| | (35 | ) | | (430 | ) |
| | | | | | | | | | | | | | | | |
| Six Months Ended June 30, 2016 | | |
| | |
| | |
| | | | | | | | |
|
| Crude Oil, NGL and Natural Gas Revenues from Third Parties | $ | 1,528 |
| | $ | 1,065 |
| | $ | 257 |
| | $ | 206 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Income from Equity Method Investees and Other | 43 |
| | — |
| | — |
| | 12 |
| | — |
| | 31 |
| | — |
| | — |
|
| Intersegment Revenues | — |
| | — |
| | — |
| | — |
| | — |
| | 85 |
| | (85 | ) | | — |
|
| Total Revenues | 1,571 |
| | 1,065 |
| | 257 |
| | 218 |
| | — |
| | 116 |
| | (85 | ) | | — |
|
| DD&A | 1,239 |
| | 1,064 |
| | 39 |
| | 104 |
| | 3 |
| | 9 |
| | — |
| | 20 |
|
| Loss on Divestitures | 23 |
| | 23 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Loss on Commodity Derivative Instruments | 107 |
| | 92 |
| | — |
| | 15 |
| | — |
| | — |
| | — |
| | — |
|
| (Loss) Income Before Income Taxes | (951 | ) | | (743 | ) | | 155 |
| | 27 |
| | (70 | ) | | 80 |
| | — |
| | (400 | ) |
| | | | | | | | | | | | | | | | |
| June 30, 2017 | |
| | |
| | |
| | |
| | | | | | | | |
|
| Goodwill | $ | 1,289 |
| | $ | 1,289 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Total Assets | 21,574 |
| | 16,143 |
| | 2,594 |
| | 1,437 |
| | 83 |
| | 1,106 |
| | (131 | ) | | 342 |
|
| December 31, 2016 | | | |
| | |
| | |
| | | | | | | | |
|
| Total Assets | 21,011 |
| | 16,079 |
| | 2,233 |
| | 1,479 |
| | 89 |
| | 851 |
| | (19 | ) | | 299 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Asset Impairments | 168 |
| | 168 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Purchased Oil and Gas | 128 |
| | 67 |
| | — |
| | — |
| | — |
| | 61 |
| | — |
| | — |
|
| Loss on Commodity Derivative Instruments | 328 |
| | 260 |
| | — |
| | 68 |
| | — |
| | — |
| | — |
| | — |
|
| Income (Loss) Before Income Taxes | 553 |
| | (127 | ) | | 535 |
| | 112 |
| | (27 | ) | | 428 |
| | (40 | ) | | (328 | ) |
| | | | | | | | | | | | | | | | |
| Six Months Ended June 30, 2017 | | |
| | |
| | |
| | | | | | | | |
|
| Crude Oil Sales | $ | 1,084 |
| | $ | 897 |
| | $ | 2 |
| | $ | 185 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| NGL Sales | 213 |
| | 213 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Natural Gas Sales | 714 |
| | 440 |
| | 263 |
| | 11 |
| | — |
| | — |
| | — |
| | — |
|
| Total Crude Oil, NGL and Natural Gas Sales | 2,011 |
| | 1,550 |
| | 265 |
| | 196 |
| | — |
| | — |
| | — |
| | — |
|
| Income from Equity Method Investees and Other | 84 |
| | — |
| | — |
| | 52 |
| | — |
| | 32 |
| | — |
| | — |
|
| Intersegment Revenues | — |
| | — |
| | — |
| | — |
| | — |
| | 127 |
| | (127 | ) | | — |
|
| Total Revenues | 2,095 |
| | 1,550 |
| | 265 |
| | 248 |
| | — |
| | 159 |
| | (127 | ) | | — |
|
| Lease Operating Expense | 263 |
| | 211 |
| | 14 |
| | 40 |
| | — |
| | — |
| | (2 | ) | | — |
|
| Production and Ad Valorem Taxes | 73 |
| | 72 |
| | — |
| | — |
| | — |
| | 1 |
| | — |
| | — |
|
| Gathering, Transportation and Processing Expense | 240 |
| | 280 |
| | — |
| | — |
| | — |
| | 32 |
| | (72 | ) | | — |
|
| Other Royalty Expense | 10 |
| | 10 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total Production Expense | 586 |
| | 573 |
| | 14 |
| | 40 |
| | — |
| | 33 |
| | (74 | ) | | — |
|
| DD&A | 1,031 |
| | 886 |
| | 37 |
| | 74 |
| | 2 |
| | 10 |
| | — |
| | 22 |
|
| Loss on Marcellus Shale Upstream Divestiture | 2,322 |
| | 2,322 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Gain on Commodity Derivative Instruments | (167 | ) | | (154 | ) | | — |
| | (13 | ) | | — |
| | — |
| | — |
| | — |
|
| Income (Loss) Before Income Taxes | (2,275 | ) | | (2,251 | ) | | 207 |
| | 138 |
| | (11 | ) | | 107 |
| | (35 | ) | | (430 | ) |
| | | | | | | | | | | | | | | | |
| June 30, 2018 | |
| | |
| | |
| | |
| | | | | | | | |
|
Goodwill (2) | $ | 1,402 |
| | $ | 1,291 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 111 |
| | $ | — |
| | $ | — |
|
| Total Assets | 21,854 |
| | 15,138 |
| | 2,996 |
| | 1,275 |
| | 62 |
| | 2,280 |
| | (140 | ) | | 243 |
|
| December 31, 2017 | | | |
| | |
| | |
| | | | | | | | |
|
Goodwill (2) | 1,310 |
| | 1,310 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total Assets | 21,476 |
| | 15,767 |
| | 2,846 |
| | 1,308 |
| | 114 |
| | 1,357 |
| | (163 | ) | | 247 |
|
(1) The intersegment eliminations related to income (loss) income before income taxes are the result of midstream expenditures. These costs are presented as property, plant and equipment within the upstreamE&P business on an unconsolidated basis, in accordance with the successful efforts method of accounting, and are eliminated upon consolidation.
(2) Goodwill in the United States reportable segment is associated with our Texas reporting unit. Goodwill in the Midstream segment is associated with the Saddle Butte acquisition.
Note 12. Commitments and Contingencies
Legal ProceedingsWe 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.
Marcellus Shale Firm Transportation Contracts In connection with the 2017 Marcellus Shale upstream divestiture, we reduced ourretained certain firm transportation obligations to flow Marcellus Shale natural gas production to various markets inside and outside of the Marcellus Basin. Our financial commitment through transferfor these agreements, which have remaining terms of certain contractsapproximately four to the acquirer.
We retained certain other15 years, is approximately $1.4 billion, undiscounted. The agreements for firm transportation contracts representing a total financial commitment of approximately $1.6 billion, undiscounted, primarily with remaining contract terms of 15 years. Of this amount, $616 million, undiscounted, relatesrelate to services on certain pipelines which were placed into service in late 2017 and early 2018 or for services on new pipeline projects which are currently under construction and targeted to be placedconstructed by, and connecting to, existing and new interstate pipeline systems, with estimated in-service dates in service fourth quarter 2017. The remaining commitments relate to pipeline projects that are targeted to be placed in service late 2018 but have not yet been approved by the FERC.2018.
We are currently engaged in actions to commercialize these commitments which provide for the transportation of 450,000 MMBtu/d of natural gas. Actions include the permanent assignment of capacity, negotiation of capacity release, utilization of capacity through purchase of third party natural gas, and other potential arrangements. We continue to expect these actions, some of which may require pipeline and/or FERC approval, to ultimately reduce theour financial commitmentscommitment associated with these contracts. However,At the date each pipeline is placed in service and our commitment begins, we will evaluate our position. If we determine that we will not utilize a portion, or all, of the contracted pipeline capacity, we will accrue a liability at fair value for the net amount of the estimated remaining financial commitment.
We cannot guarantee
theseour commercialization efforts will be successful and we may recognize substantial future liabilities, at fair value, for the net amount of the estimated remaining commitments under these contracts.
These financial commitments are included in the table below consistent with expected future cash payments associated with the underlying agreements. See Note 4. Acquisitions and Divestitures. Non-Cancelable Leases and Other Commitments We hold leases and other commitments for drilling rigs, buildings, equipment and other property and have entered into numerous long-term contracts for gathering, processing and transportation services. Minimum commitments have been updated to give effect to the Clayton Williams Energy Acquisition, the Marcellus Shale upstream divestiture, as well as commitments related to Leviathan development activities, and consist of the following asAs of June 30, 2017:2018, our exit cost accrual, relating to certain transportation arrangements, totals $83 million, discounted. For the first six months of 2018, we incurred expense of $3 million related to unutilized transportation related to these contracts. |
| | | | | | | | | | | | | | | | | | | | |
| (millions) | | Drilling, Equipment, and Purchase Obligations | | Transportation and Gathering Obligations(1) | | Operating Lease Obligations | | Capital Lease Obligations(2) | | Total |
| July - December 2017 | | $ | 306 |
| | $ | 116 |
| | $ | 24 |
| | $ | 39 |
| | $ | 485 |
|
| 2018 | | 341 |
| | 247 |
| | 47 |
| | 74 |
| | 709 |
|
| 2019 | | 146 |
| | 276 |
| | 35 |
| | 45 |
| | 502 |
|
| 2020 | | 22 |
| | 250 |
| | 33 |
| | 42 |
| | 347 |
|
| 2021 | | 4 |
| | 213 |
| | 34 |
| | 29 |
| | 280 |
|
| 2022 and Thereafter | | 33 |
| | 1,496 |
| | 198 |
| | 145 |
| | 1,872 |
|
| Total | | $ | 852 |
| | $ | 2,598 |
| | $ | 371 |
| | $ | 374 |
| | $ | 4,195 |
|
| |
(1)
| Includes $1.6 billion of future cash payments related to retained Marcellus Shale firm transportation contracts. See discussion above. |
| |
(2)
| Annual lease payments, net to our interest, exclude regular maintenance and operating costs. See Note 6. Debt. |
Colorado Air Matter In April 2015, we entered into a joint consent decree (Consent Decree) with the US Environmental Protection Agency, US Department of Justice, and State of Colorado to improve emission control systems at a number of our condensate storage tanks that are part of our upstream crude oil and natural gas operations within the Non-Attainment Area of the DJ Basin. The Consent Decree was entered by the courtUS District Court for the District of Colorado on June 2, 2015.
The Consent Decree, which alleges violations of the Colorado Air Pollution Prevention and Control Act and Colorado’s federal approved State Implementation Plan, specifically Colorado Air Quality Control Commission Regulation Number 7, requires us to perform certain injunctive relief activities andcorrective actions, to complete mitigation projects, andto complete supplemental environmental projects (SEP), and to pay a civil penalty. Costs associated with the settlement consist of $4.95$5 million in civil penalties which were paid in 2015. Mitigation costs of $4.5$5 million and SEP costs of $4 million are being expended in accordance with schedules established in the Consent Decree. Costs associated with the injunctive relief are also being expended in accordance with schedules established in the Consent Decree. DuringSince 2015, and 2016, we spenthave incurred approximately $54.7$83 million to undertake injunctive reliefcorrective actions at certain tank systems following the outcome of adequacy of design evaluations and certain operation and maintenance activities to handle potential peak instantaneous vapor flow rates. Future costs associated with injunctive relief are not yet precisely quantifiable as we are continually evaluating various approaches to meet the ongoing obligations of the Consent Decree.
Overall compliance with the Consent Decree has resulted in the temporary shut-in and permanent plugging and abandonment of certain wells and associated tank batteries. Consent Decree compliance could result in additional temporary shut-ins and permanent plugging and abandonment of certain wells and associated tank batteries. The Consent Decree sets forth a detailed compliance schedule with deadlines for achievement of milestones through early 2019 that may be extended depending on certain situations. The Consent Decree contains additional obligations for ongoing inspection and monitoring beyond that which is required under existing Colorado regulations.
We have concluded that the penalties, injunctive relief, and mitigation expenditures that resulted from this settlement did not have, and based on currently available information will not have, a material adverse effect on our financial position, results of operations or cash flows.
Colorado Water Quality Control Division Matter In January 2017, we received a Notice of Violation/Cease and Desist Order (NOV/CDO) advising us of alleged violations of the Colorado Water Quality Control Act (Act) and its implementing regulations as it relates to our Colorado Discharge Permit System General Permit for construction activities associated with oil and gas exploration and /or production within our Wells Ranch Drilling and Production field located in Weld County, Colorado (Permit). The NOV/CDO further orders us to cease and desist from all violations of the Act, the regulations and the Permit and to undertake certain corrective actions. Given the uncertainty associated with administrative actions of this nature, we are unable to predict the ultimate outcome of this action at this time but believe that the resolution of this action will not have a material adverse effect on our financial position, results of operations or cash flows.
Colorado Air ComplianceOil and Gas Conservation Commission Administrative Order on Consent In AprilNovember 2017, we received a proposed ComplianceAdministrative Order on Consent (COC)(AOC) from the Colorado Department of Public HealthOil and Environment’s Air Pollution Control Division (APCD)Gas Conservation Commission (COGCC) to resolve allegations of noncompliance associated with compliance testingsite preparation and stabilization at an oil and gas location in Weld County, Colorado. The AOC, which provides for an opportunity to further discuss the offer of certain engines subjectsettlement, has not yet been executed. Given the uncertainty associated with administrative actions of this nature, we are unable to various General Permit 02 conditions and/or individual permit conditions. In May 2017, we reached a finalpredict the ultimate outcome of this action at this time, but believe that the resolution with the APCD and executed the COC, which requires payment of a civil penalty of $24,710 and an expenditure of no less than $98,840 on an approved SEP(s). This resolution isthis action will not believed to have a material adverse effect on our financial position, results of operations or cash flows.
Colorado Mechanical Integrity Testing Matter In July 2018, we received Notices of Alleged Violation (NOAVs) from the COGCC for alleged noncompliance of State mechanical integrity testing rules at eight shut-in wells in Weld County, Colorado. The NOAVs order us to repair or plug and abandon each of the eight wells (or provide proof that such work has been completed) and to submit to COGCC certain environmental data. We have met with COGCC enforcement leadership to discuss this matter and are working to timely complete the required corrective actions and submit the data requested in the NOAVs. Given the uncertainty associated with administrative actions of this nature, we are unable to predict the ultimate outcome of this action at this time but believe that the resolution of this action will not have a material adverse effect on our financial position, results of operations or cash flows.
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide a narrative about our business from the perspective of management. We use common industry terms, such as thousand barrels of oil equivalent per day (MBoe/d) and million cubic feet equivalent per day (MMcfe/d), to discuss production and sales volumes. Our MD&A is presented in the following major sections:
The preceding consolidated financial statements, including the notes thereto, contain detailed information that should be read in conjunction with our MD&A.
EXECUTIVE OVERVIEW
The following discussion highlights significant operating and financial results for second quarter 2017.2018. This discussion should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2016,2017, which includes disclosures regarding our critical accounting policies as part of “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Current Upstream EnvironmentRecent Achievements
Crude Oil PricesSince 2015, we have strategically repositioned our portfolio to focus capital investment primarily in US onshore plays, including the DJ and Delaware Basins and Eagle Ford Shale, and on our international offshore assets in the Eastern Mediterranean and West Africa. The focus of our capital programs in these areas is expected to positively impact our future cash flows and margins. Going forward, we are concentrating our exploration capabilities on higher-impact opportunities that can drive substantial long-term value creation.
During second quarter 2017, crude oil prices softened as US shale producers brought production online faster than2018, we exited the market expected. Further, evidenceGulf of effectiveness of the OPEC-led production cuts has not yet been reflected in global inventories due in part to the increase in US onshore production. As a result, near-term crude oil continues to be oversupplied globally.
For the remainder of 2017, inventoryMexico and production levels, particularly US onshore supply growth and the effectiveness of OPEC curtailment actions as well as OPEC production from countries not bound to OPEC curtailments, such as Libya and Nigeria, are likely to be the primary determinants of near-term crude oil prices with the risk that continued strong production trends cause crude oil prices to remain persistently low. Future OPEC decisions regarding extension of production curtailments, changes in crude oil storage levels and US shale oil production trends, are likely to continue to have significant impacts on crude oil prices.
Natural Gas PricesThe US domestic natural gas market also remains oversupplied as domestic production has continued to grow due to drilling efficiencies, completion of drilled but uncompleted well inventory and de-bottlenecking of transportation infrastructure. As with crude oil, there has been little offsetting demand growth. As a result, during the first six months of 2017, natural gas prices remained range bound. We expect this situation to continue for the remainder of 2017, with natural gas prices near current or recent trading levels.
Price Trend Chart The chart below shows the historical trend in benchmark prices for West Texas Intermediate (WTI) crude oil, Brent crude oil and U.S. Henry Hub natural gas.
Development and Operating Costs Third party oilfield service and supply costs are also subject to supply and demand dynamics. During the first six months of 2017, increases in US onshore drilling and completion activity resulted in higher demand for oilfield services. As a result, the costs of drilling, equipping and operating wells and infrastructure have begun to experience some inflation, which, along with the commodity price softness noted above, results in continued pressures on industry operating margins. Conversely, the industry has reduced capital-intensive offshore exploration and drilling activities in response to the commodity price environment. As a result, demand for and costs associated with offshore services have declined and in the near-term, will likely not be subject to cost inflation.
Recent Achievements
Despite the current commodity price and cost environment, Noble Energy had a very successful second quarter 2017, achieving several strategic, operational and financial goals. Strategically, we closed several transformative portfolio transactions demonstratingprogress our continued focus on enhancing margins and project returns. Operationally, we continued to enhance US onshore drilling and completions activities and advanced our Eastern Mediterranean and West Africa regional natural gas developments. Financially, we continued to maintainstrengthened our strong balance sheet through reduction of debt.
Second quarter 2018 achievements include the following:
Sales Volumes We delivered quarterly sales volumes of 346 MBoe/d with approximately 56% of our production mix attributable to crude oil and liquidity position.NGLs. Reported volumes reflect the impact of adoption of ASC 606, Revenue from Contracts with Customers (ASC 606). See Exploration and Production (E&P) – Results of Operations. Clayton Williams Energy Acquisition On April 24, 2017,Gulf of Mexico Asset Sale In second quarter 2018, we completed the acquisition (Clayton Williams Energy Acquisition)sale of Clayton Williams Energy, Inc. (Clayton Williams Energy) for $2.5 billionour Gulf of stockMexico assets, including our interests in six producing fields and all undeveloped leases. We received cash consideration. In connection with the acquisition, we assumed,consideration of $383 million, net of customary price adjustments. We recognized impairment expense of $168 million in first quarter 2018 and then subsequently retired, $595an additional loss of $19 million of Clayton Williams Energy long-term debt. The transaction adds highly contiguous acreage in the core of the Delaware Basin and materially expands our Delaware position to approximately 118,000 net acres. The integration of the Clayton Williams Energy assets into our portfolio expands our opportunities in the core, high crude-oil content area of the Delaware Basin, significantly increasing our US onshore growth outlook.second quarter 2018. See Item 1. Financial Statements – Note 3. Clayton Williams Energy AcquisitionAcquisitions and Divestitures.Marcellus Shale Upstream Divestiture On June 28, 2017,Agreement to Progress Alen Natural Gas Development In May 2018, we closedannounced the saleexecution of a Heads of Agreement establishing the framework for development of natural gas from the Alen field, resulting in access to global liquefied natural gas (LNG) markets. Sanction of the Marcellus Shale upstream assets, receiving net proceedsproject is contingent upon final commercial agreements being executed. See Exploration and Production (E&P) – Development Projects.Strategic EPIC Pipeline Agreement During second quarter 2018, we finalized a strategic agreement with EPIC Pipeline, LP (EPIC) to transport crude oil from our Delaware Basin acreage position to Corpus Christi, Texas. We have secured firm capacity for 100 MBbl/d, gross, of $1.0 billion. The divestment enables us to further focus our organization on our highest-return areas that are expected to deliver US onshore volume and cash flow growth.crude oil for a 10-year period beginning at pipeline start-up. In addition, we have signedsecured options for ownership interests in EPIC's crude oil and NGL pipelines. See Exploration and Production (E&P) – Development Projects.
Delaware Basin Firm Crude Oil Sales Agreement In June 2018, we supplemented our Delaware Basin takeaway position through the execution of a definitivefive-year agreement for firm gross sales of at least 10 MBbl/d of crude oil beginning in July 2018, increasing to divest20 MBbl/d beginning in October 2018 and for the remainder of the agreement. See Exploration and Production (E&P) – Development Projects. Hedging Activities We entered into additional strategic crude oil basis swap contracts for 2018-2020 in order to establish a fixed amount for the differential between pricing in Midland, Texas, and Cushing, Oklahoma, thus mitigating the price risk associated with our Marcellus Shale midstream business for $765 million.Delaware Basin production. See Item 1. Financial Statements – Note 4. Derivative Instruments and Hedging Activities. CNX Midstream Partners Unit Sale During second quarter 2018, we sold 7.5 million CNX Midstream Partners common units, or approximately one-third of our investment, receiving net proceeds of approximately $135 million, net of underwriting fees. We continue to hold 14.2 million common units. See Item 1. Financial Statements – Note 3. Acquisitions and Divestitures. Senior Note Redemption To further strengthen our balance sheet and reduce nearer-term maturities, we redeemed $379 million of Senior Notes due May 1, 2021, which had been assumed in the 2015 Rosetta Merger, in May 2018 for $395 million and recognized a gain of $5 million. See Item 1. Financial Statements – Note 12. Commitments5. Debt. Share RepurchasesIn accordance with the $750 million share repurchase program authorized by our Board of Directors earlier this year, we repurchased and Contingencies.
Midstream GrowthAlong with our upstream portfolio actions, we continued to grow our Midstream business and completed our first drop-down transactionretired 1.8 million shares of midstream assets to Noble Midstream Partners L.P (NBLX) for total considerationcommon stock at an average purchase price of $270 million.
Operational Accomplishments Operationally, we delivered quarterly sales volumes of 408 MBoe/d, an increase of 7% from first quarter 2017, established a record for$35.15 per share during second quarter gross sales volumes of 962 MMcfe/d in Israel and continued to progress the Leviathan development project within budget towards first natural gas production by the end of 2019. See Project Updates, below, and Result of Operations.2018.
Financial Flexibility, Liquidity and Balance Sheet Strength We continue to undertake proactive and strategic actions to maintain liquidity and a strong balance sheet. An example of this is using proceeds received from the Marcellus Shale upstream
divestiture and NBLX drop-down transaction to offset the cash impact of the Clayton Williams Energy Acquisition. Proceeds received from these transactions were used to retire $1.3 billion borrowed under our Revolving Credit Facility to pay for the cash consideration of the Clayton Williams Energy Acquisition and associated costs, as well as the retirement of all $595 million of assumed Clayton Williams Energy debt. We strive to maintain a robust liquidity position and ended second quarter 2017 with approximately $4.5 billion of liquidity, which includes cash on hand and unused borrowing capacity. See Liquidity and Capital Resources.
Positioned for the Future
We believe the following guiding principles will contribute to the sustainability and success of our business throughout the commodity price cycle, including extended periods of lower prices:
Execution of a disciplined capital allocation process by:
| |
◦ | designing a flexible investment program aligned with the current commodity price environment; and |
| |
◦ | maintaining a strong balance sheet and liquidity position. |
Enhancing capital efficiencies through:
| |
◦ | utilizing our technical competencies and applying historical learnings from unconventional US shale plays to reduce US onshore finding and development costs; and |
| |
◦ | driving Delaware Basin economics through development cycle efficiencies. |
Leveraging the benefits of our well-positioned and diversified portfolio including:
| |
◦ | exercising investment optionality and flexibility afforded by our assets held by production; and |
| |
◦ | continuing portfolio optimization actions to maximize strategic value. |
Capitalizing on a currently low-cost offshore environment with execution of high-quality long-cycle development projects, such as:
| |
◦ | sanctioning and commencing the first phase of Leviathan field development. |
In summary, as As we progress through the remainder of 2017,2018, we believe we are positioned for sustainability, operational efficiency, and long-term success throughout the oil and gas business cycle. We remain committed to maintaining capital discipline and financial strength and will continuously evaluate commodity prices, along with well productivity and efficiency gains, as we optimize our activity levels in alignment with commodity price conditions.
To this end, our 20172018 capital investment program is responsive to positive or negative commodity price conditions that may develop. Excluding acquisition and Noble Midstream Partners capital, we expect our 2017 capital spending program to be in the upper end of our investment range of $2.3 to $2.6 billion, or approximately 50% higher than 2016. See Operating Outlook – 20172018 Capital Investment Program, below.. Although the industry has begun to recover from the recent downturn, ifIf commodity prices decline or operating costs begin to rise, we could experience material negative impacts on our revenues, profitability, cash flows, liquidity and proved reserves, and, in response, we may consider reductions in our capital program or dividends, asset sales or operating cost structure. Our production and our stock price could decline as a result of these potential developments.
Adoption of ASC 606
As of January 1, 2018, we adopted ASC 606, using the modified retrospective method. ASC 606 adoption did not have an impact on the opening balance of retained earnings, and resulted in de minimis increases of $2 million and $7 million to both revenues and expenses for the second quarter and the first six months of 2018, respectively. ASC 606 adoption did not affect operating or net income or operating cash flows. Comparative information for the prior periods has not been recast and continues to be reported under the accounting standards in effect for those periods. Adoption of the new standard did not impact our financial position and we do not expect that it will going forward. See Exploration and Production (E&P) – Results of Operations. Recently Issued Accounting Standards
OPERATING OUTLOOK
20172018 Production Our expected crude oil, natural gas and NGL productionsales for the remainder of 20172018 may be impacted by several factors including:
commodity prices which, if subject to furthera significant decline, could result in certain currentexisting production becoming uneconomic;
overall level and timing of capital expenditures which, as discussed below and dependent upon our drilling success, will impact near-term production volumes;
with increased industry drilling activity in the basins in which we operate, which may cause US onshore cost inflation pressure mayand result in certain current production becoming less profitable or uneconomic;
Israeli industrial and residential demand for electricity, which is largely impacted by weather conditions and conversion of the Israeli electricity portfolio from coal to natural gas;
timing of the divestiture of a portion of our working interest in the Tamar field, in accordance with the Israel Natural Gas Framework (Framework), which will lower our sales volumes;
timing of crude oil and condensate liftings impacting sales volumes in West Africa as well asAfrica;
natural field decline in the unitization of the Alba field;
integrationUS onshore and timing of producing wells acquired as a result of the Clayton Williams Energy Acquisition;
divestment of Marcellus Shale upstream assets;
offshore Equatorial Guinea;
additional purchases of producing properties or divestments of operating assets;
natural field decline in the US onshore, Gulf
potential weather-related volume curtailments (e.g., due to hurricanes in the Gulf of Mexico and Gulf Coast areas, or winter storms and floodingflooding) impacting US onshore operations;
availability or reliability of supplier materials and services, including access to support equipment and facilities, pipeline disruptions, and/or potential pipeline and processing facility capacity constraintsfacilities which may cause delays in operations;
availability of, or curtailments imposed by, third party processing facilities, which could result in capacity constraints, and interruptions in midstream processing, which may cause production and sales volumes impacts;
occurrence of pipeline disruptions, which may cause delays, restrictions or interruptions in production and/or midstream processing;
timingaccess to transportation and completiontakeaway pipelines for increasing US onshore production volumes, such as in the Delaware Basin, which may cause infield bottlenecks and/or widening of midstream expansion projects by Noble Midstream Partners in areas that provide services to our assets;location-basis differentials;
malfunctions and/or mechanical failures at terminals or other US onshore delivery points;
impact of enhanced completion efforts for US onshore assets;
possible potential growth from participation in future, or decline from existing, non-operated wells;
abandonment of low-margin US onshore wells;
shut-in of US producing properties if storage capacity becomes unavailable; and
potential drilling and/or completion permit delays due to future regulatory changes.
20172018 Capital Investment Program Given Our 2018 capital investment program is designed to deliver near and long-term value and is flexible in the current commodity price environment, we have designed a flexibleenvironment. Excluding capital investment program as part of our comprehensive effort to maintain strong liquidity and manage the Company's balance sheet. Excluding acquisition capital andfunded by Noble Midstream Partners, we expect our 2017initial 2018 program accommodated an investment level of approximately $2.7 to $2.9 billion and was contemplated using a West Texas Intermediate price assumption of $50 per barrel. We have revised our capital investment program to beaccommodate an investment level of approximately $3 billion, reflecting increased onshore facility spend from the first half of 2018 and inflation in the upper end of our range of $2.3 to $2.6 billion, of which $1.3 billion has been incurred during the six months ended June 30, 2017. More than 75%US onshore as a result of the totalhigher commodity price environment.
Approximately 95% of the capital investment program is being allocated to US onshore development, primarily in liquids-rich opportunitiesassociated midstream infrastructure and the Eastern Mediterranean. In addition, given industry constraints in the DJPermian Basin, we plan to reallocate some near-term investment to our other US onshore basins. This will ensure that we are optimizing our development plans and timing our Delaware Basin and Eagle Ford Shale. activity to benefit from necessary takeaway infrastructure planned for next year.
The remaining 25%portion of the capital investment program is designated for other activities, including lease acquisition, seismic and other geological analysis in support of future exploration prospects, as well as other corporate activities.
We will be predominately allocatedcontinue to evaluate the Eastern Mediterranean,level of capital spending throughout the year based on the following factors, among others, and their effect on project financial returns:
commodity prices, including initialprice realizations on specific crude oil, natural gas and NGL production;
operating and development costs associated withcosts;
production, drilling and delivery commitments, or other contractual obligations;
access and availability of gathering, transportation, takeaway and processing capacity for US onshore production volumes;
drilling results;
property acquisitions and divestitures;
exploration activity;
cash flows from operations;
indebtedness levels;
availability of financing or other sources of funding;
impact of new laws and regulations on our business practices, including potential legislative or regulatory changes regarding the Leviathan project.use of hydraulic fracturing; and
potential changes in the fiscal regimes of the US and other countries in which we operate.
Potential for Future Dry Hole Cost, Lease Abandonment Expense or Property Impairments
Exploration Activities Our exploration program seeks to provide growth through long-term and/or large-scale exploration opportunities. We continue to seek exploration opportunities in various geographical areas, such as our entry into Newfoundland, Canada. In other areas of the world, we have capitalized a significant amount of exploratory drilling costs. In the event we conclude that an exploratory well did not encounter hydrocarbons or that a discovery or prospect is not economically or operationally viable, the associated capitalized exploratory well costs would be charged to expense. See Item 1. Financial Statements - Note 8. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs and Results of Operations – Oil and Gas Exploration Expense, below.We may also impair and/or relinquish certain undeveloped leases prior to expiration, based upon geological evaluation or other factors. For example, during the first six months of 2017, we impaired $18 million of cost related to Gulf of Mexico undeveloped leases. We have numerous leases for Gulf of Mexico prospects that have not yet been drilled. A significant portion of these leases are scheduled to expire over the years 2018 to 2020 and some leases may become impaired if production is not established, no action is taken to extend the terms of the leases, or the leases become uneconomic due to low commodity prices or other factors.
As of June 30, 2017, we have capitalized costs related to exploratory wells of $571 million. In addition, we have undeveloped leasehold costs, to which proved reserves had not been attributed, of $3.1 billion. Of this amount, $1.6 billion is attributable to properties acquired in the Clayton Williams Energy Acquisition, and $1.2 billion and $185 million are attributable to Delaware Basin and Eagle Ford Shale assets, respectively, acquired in the Rosetta Resources Inc. acquisition. These costs were derived from allocated fair values as a result of business combinations or other purchases of unproved properties and, in that the properties are primarily held by production, they are subject to impairment testing utilizing a future cash flows analysis.
The remaining undeveloped leasehold costs as of June 30, 2017 included $86 million related to Gulf of Mexico unproved properties and $52 million related to international unproved properties. These costs are evaluated as part of our periodic impairment review. If, based upon a change in exploration plans, availability of capital and suitable rig and drilling equipment, resource potential, comparative economics, changing regulations and/or other factors, an impairment is indicated, we will record impairment expense related to the respective leases. As a result of our exploration activities, future exploration expense, including undeveloped leasehold impairment expense, could be significant. See Results of Operations - Oil and Gas Exploration Expense, below.Proved and Unproved Properties Regulatory Update During the first six months of 2017, no impairments were incurred related2018, the US Administration imposed import tariffs of 25% on steel products and 10% on aluminum products, as well as quantitative restrictions on imports of steel and/or aluminum products from Argentina, Brazil, and South Korea (Australia has been exempted from the imposition of tariffs and implementation of quotas). Key US trading partners have threatened to proved properties.retaliate, or already have retaliated, against imports of US-origin goods and have initiated litigation at the World Trade Organization. The cash flow model that we use to assess proved properties for impairment includes numerous assumptions, such as management’s estimates of future crudeUS oil and natural gas industry relies on steel for drilling and completion of new wells, as well as for facility production along with operatingat refineries, petrochemical plants and development costs, marketpipelines. Much of the steel required is in the form of specialty steel products, manufactured to exact specifications, and may not be available domestically in sufficient quantities.
outlookImplementation of these tariffs will likely increase prices for specialty and other products used in various aspects of upstream, midstream and downstream activities. Furthermore, the tariffs and quantitative restrictions may cause disruption in the energy industry’s supply chain, resulting in delay or cessation of drilling efforts or postponement or cancellation of new inter- or intra-state pipeline projects, that the industry is relying on forward commodity prices, and interest rates. All inputsto transport its increasing onshore production to market, as well as endangering US LNG export projects resulting in negative impacts on natural gas production.
In addition, countries subject to the cash flow model must be evaluated at each date of estimate. However, a decreasetariffs have threatened to retaliate with tariffs on American products, potentially resulting in forward commodity prices, escalating trade disputes with certain trade partners. Trade and/or widening of basis differentials,tariff disputes could result in an impairment.
In addition, well decommissioning programs, especially in deepwaterincreased costs or remote locations, are often complexshortages of materials and expensive. It may be difficult to estimate timing of actual abandonment activities, which are subject to regulatory approval and the availability of rigs and services. It may also be difficult to estimate costs of rigs and services in periods of fluctuating demand. In addition, we do not operate certain assets and we therefore work with respective operators to receive updated estimates of abandonment activities and costs. For example, as of June 30, 2017, we had an asset retirement obligation of $88 million related to a North Sea remediation project. As the operator moves beyond the initial decommissioning phase, we will continue to monitor the status and costs of the project and will adjust our estimate accordingly. See Item 1. Financial Statements - Note 9. Asset Retirement Obligations.Divestments We actively manage our asset portfolio to ensure our assets are well-positioned onsupplies the industry cost of supply curverelies on to produce, process and offer growth at financially attractive rates of return. Therefore, we may periodically divest certain assets, such as the Marcellus Shale upstream assets, to reposition our portfolio. Proceeds from asset sales are redeployed in our capital investment program, used to pay down debt, strengthen our balance sheet and/or support returns to shareholders through dividends or other mechanisms.
When properties meet the criteria for reclassification as assets held for sale, they are valued at the lower of net book value or anticipated sales proceeds less transaction related costs to sell. Impairment expense would be recorded for any excess of net book value over anticipated sales proceeds less transaction related costs to sell.
We strive to obtain the most advantageous price for any asset divestment; however, various factors, such as current and future commodity prices, reserves, production profiles, operating costs, capital investment requirements and potential future liabilities, as well as legal and regulatory requirements, can make it difficult to predict an asset's selling price and whether a transaction will result in a gain or loss. Inability to achieve a desired sales price, or underestimation of amounts of retained liabilities or indemnification obligations, can result in a possible loss on the sale, which could be material. See Item 1. Financial Statements - Note 4. Acquisitions and Divestitures.We continue to review our portfolio to ensure alignment with the aforementioned strategic objectives. Further, the State of Israel requires that 7.5% of our working interest in the Tamar field offshore Israel be divested by December 2021, reducing our working interest from 32.5% to 25%. Additional potential divestments may be considered, even though no commitments have been made by our management and our Board of Directors.
Regulatory Update
US Regulatory Developments In early 2017, President Trump issued two executive orders directing the US Environmental Protection Agency (EPA) and other executive agencies to review their rules and policies that unduly burden domestic energy development. Specifically, on February 28, 2017, President Trump signed an executive order directing the EPA and the US Army Corps of Engineers (Corps) to review the Clean Water Rule and to initiate rulemaking to rescind or revise it, as appropriate under the stated policies of protecting navigable waters from pollution while promoting economic growth, reducing uncertainty, and showing due regard for Congress and the states. On March 28, 2017, President Trump signed an executive order directing the EPA and other executive agencies to review all regulations, orders, guidance documents and policies and take actions to suspend, revise or rescind them, as appropriate and consistent with the law, to the extent that they unduly burden the development of domestic energy resources beyond the degree necessary to protect the public interest.
Pursuant to the first executive order, on June 27, 2017, the EPA and the Corps announced a proposed rule to rescind the Clean Water Rule and to re-codify the regulations that existed before the Clean Water Rule. Consistent with the second executive order, on June 5, 2017, the EPA published notice that it would reconsider certain requirements of a May 2016 rule, which set standards for emissions of methane and volatile organic compounds from new and modifiedtransport its oil and gas production sources,production. Moreover, trade and/or tariff disputes, could have negative impacts on the US and that it would stayglobal economies overall and could result in less demand for 90 days those requirements pending reconsideration. On June 16, 2017, the EPA published a proposed rule to extend the stay for two years. On July 3, 2017, the D.C. Circuit Court of Appeals vacated the 90-day stay, but noted that this decision did not limit the EPA’s authority to reconsider its regulations and proceed with the June 16, 2017 proposed rulemaking. The EPA and the Bureau of Land Management have also announced that they are reconsidering, or plan to reconsider, additional regulations that impact the oil and gas industry. However, it remains unclear how and to what extent this broad review could impact environmental regulations at the federal level.
Voluntary Withdrawal from International Climate Change Accord In December 2015, the United States signed the Paris Agreement on climate change and pledged to take efforts to reduce greenhouse gas (GHG) emissions and to conserve and enhance sinks and reservoirs of GHGs. The Paris Agreement entered into force in November 2016. However, on June 1, 2017, President Trump announced that the United States would withdraw from the Paris Agreement and begin negotiations to either re-enter or negotiate an entirely new agreement with more favorable terms for the United States. While President Trump
expressed a clear intent to cease implementing the Paris Agreement, it is not clear how the Administration plans to accomplish this goal, whether a new agreement can be negotiated, or what terms would be included in such an agreement. Furthermore, in response to the announcement, many state and local leaders stated their intent to intensify efforts to uphold the commitments set forth in the international accord. It is not possible at this time to predict the timing or effect of international treaties or regulations on our operations or to predict with certainty the future costs that we may incur in order to comply with such treaties or regulations.
Impact of Dodd-Frank Act Section 1504In June 2016, the Securities and Exchange Commission (SEC) adopted resource extraction issuer payment disclosure rules under Section 1504 of the Dodd-Frank Act that would have required resource extraction companies, such as us, to publicly file with the SEC beginning in 2019 information about the type and total amount of payments made to a foreign government, including subnational governments (such as states and/or counties), or the U.S. federal government for each project related to the commercial development of crude oil, natural gas or minerals, and the type and total amount of payments made to each government (such rules, the Resource Extraction Issuer Payment Rules).
However, on February 14, 2017, President Trump signed a joint resolution passed by the United States Congress under the Congressional Review Act and eliminated the Resource Extraction Issuer Payment Rules. It should be noted that Section 1504 of the Dodd-Frank Act has not been repealed and that the SEC will now have until February 2018 to issue replacement rules to implement Section 1504 of the Dodd-Frank Act, and that under the Congressional Review Act a rule may not be issued in “substantially the same form” as the disapproved rule unless it is specifically authorized by a subsequent law. We cannot predict whether the SEC will issue replacement rules or, if it does so, whether such replacement rules will again be eliminated pursuant to the Congressional Review Act.
We will continue to monitor proposed and new regulations and legislation in all of our operating jurisdictions to assess the potential impact on our company. We continue to engage in extensive public education and outreach efforts with the goal of engaging and educating the general public and communities about the energy, economic and environmental benefits of safe and responsible crude oil and natural gas development.products.
EXPLORATION AND PRODUCTION (E&P)
We continue to advance our major development projects, which we expect to deliver incremental production and cash flows over the next several years. Updates on major development projects are as follows:
Sanctioned Ongoing Development Projects
A "sanctioned" development project is one for which a final investment decision has been reached. Second quarter 2017 activities included the following:Updates on major development projects are as follows:
DJ Basin (US Onshore) Our activities during second quarter 20172018 were focused primarily in the Wells Ranch and East Pony integrated development plan (IDP) areas. During the quarter, we operated one to two drilling rigs, completed 31 wells and commenced production on 16 wells. Average sales volumes during second quarter 2018 were 121 MBoe/d, including 10 MBoe/d due to ASC 606 adoption. We have expanded drilling and completion activities into the Mustang IDP area, where we have a large contiguous acreage position, and added a drilling rig in this IDP during second quarter 2018. Our development plan in this area includes applying multiple techniques from our other successful US onshore plays, including utilizing row development concepts, enhanced completion designs, capital-efficient facility designs, and other techniques to optimize project returns.
Delaware Basin (US Onshore) During second quarter 2018, we operated an average of twosix drilling rigs, drilled 29completed 22 wells and commenced production on 33 wells.23 wells, with the majority of our activity focused on long laterals and multi-well pads targeting multiple zones within the basin. We continueaveraged 47 MBoe/d of sales volumes during second quarter 2018, with approximately 70% of our production mix attributable to optimize value in these oil-rich areas through our horizontal development program, which has led to an increasing mixcrude oil. During second quarter 2018, we commenced operations at two additional central gathering facilities (CGFs).
Also during second quarter 2018, we secured firm capacity with EPIC for transport of 100 MBbl/d, gross, of crude oil sales volumes andfrom the Delaware Basin to Corpus Christi, Texas, for a record10-year period beginning at pipeline start-up. We have dedicated substantially all our Delaware Basin acreage position in Reeves County, Texas to the EPIC crude oil mix of 53%pipeline, which the operator anticipates will commence operations in the DJfourth quarter of 2019. This strategic agreement is expected to provide long-term flow assurance for our rapidly growing Delaware Basin during secondcrude oil volumes. With this agreement, we have further diversified our US onshore marketing outlets with access to the Texas Gulf Coast and global markets, at an attractive pipeline transport cost.
As part of the EPIC strategic relationship, we secured options to acquire up to 30% ownership interest in the company that owns the EPIC crude oil pipeline. In addition, Noble Midstream Partners secured an option to acquire up to 15% ownership interest in the company that owns the EPIC NGL pipeline. Both options expire in first quarter 2017. We expect total horizontal production2019.
In June 2018, we supplemented our Delaware Basin takeaway position with an additional firm sales agreement, which will result in our crude oil reaching the Gulf Coast. The five-year agreement provides for firm gross sales of at least 10 MBbl/d of crude oil beginning in July 2018, increasing to 20 MBbl/d beginning in October 2018 and specifically, production from Wells Ranch and East Pony, to continue to grow for the remainder of 2017, while we anticipate certainthe agreement. Crude oil sold under the agreement will initially utilize the buyer's existing firm transport capacity to Corpus Christi. Shortly following commencement of full service of the EPIC crude oil pipeline, it is anticipated that crude oil sales under the agreement will be transported by way of our legacy horizontal wells, as well asfirm transportation capacity. We previously executed firm sales agreements to the majority of our vertical wells, to experience production declines as we enhance our focus on horizontal development in the oil-rich areas of the basin.
Texas Gulf Coast or Cushing, Oklahoma markets for Delaware Basin (US Onshore) On April 24, 2017, we completedcrude oil covering gross oil volumes of 10 MBbl/d for the Clayton Williams Energy Acquisitionsecond half of 2018 and increased our portfolio holdings in the Delaware Basin. During second quarter 2017, we operated an average of four and a half drilling rigs (including one on the recently acquired Clayton Williams Energy properties), drilled 13 horizontal wells (of which four were on Clayton Williams Energy leases) and commenced production from six wells, all of which were from our existing Delaware Basin assets. Our integration and assumption of operations of the Clayton Williams Energy assets has been successful and we are currently applying learnings from our legacy Delaware Basin assets to optimize our development plan.5 MBbl/d for 2019.
Eagle Ford Shale (US Onshore) During second quarter 2017, we focused our activity in Webb and Dimmit Counties where2018, we operated an average of one and a half drilling rigs, drilled 11 horizontalrig, completed four wells and commenced production on 21 wells.nine wells, primarily focused within the Upper and Lower Eagle Ford formation zones. In addition, we commenced construction of a central gathering and production facility in the northern area of Gates Ranch. This facility will provide separation and compression capabilities for our upcoming multi-well completion program expected to begin later in 2018. We continue to execute a strongour development plan which led to record quarterlyand averaged sales volumes of 6976 MBoe/d during second quarter 2017. For the remainder2018.
Tamar Natural Gas Project (Eastern Mediterranean) In second quarter 2018, offshore Israel sales volumes to continue to grow in this liquids-rich play.
Gulf of Mexico (US Offshore) Our offshore assets continue to provide high-margin oil production,averaged 227 MMcfe/d, net, and during second quarter 2017, average dailyon a gross basis, sales volumes were 27 MBoe/reached a cumulative milestone delivering 1.6 Tcf of natural gas to-date. Second quarter gross sales volumes established a quarterly production record of more than 1 Bcf/d, net, which includes substantial uptime performance at both the Neptune Spardriven by continued coal displacement in power generation and Thunder Hawk Production Facility. During second quarter 2017, we received approval from the United States Coast Guard for a life extension related to the Neptune Spar, our floating offshore production platform which services our Swordfish asset. The approval is the first life extension in the Gulf of Mexico granted for a floating production system in our industry.warm seasonal weather.
Leviathan Natural Gas Project (Offshore Israel) The first(Eastern Mediterranean) 2018 represents the peak year for capital investments for the initial phase of Leviathan development, offshore Israel. The project is now nearly 60% complete and remains on budget and on schedule. We have commenced construction of the onshore pipeline, completed drilling of Leviathan field provides 1.2 Bcf/d of production capacity3 and consists of four7 wells, a subsea production system and a shallow-water processing platform, with a connection to an onshore valve station. We expect our share of development costs to total approximately $1.5 billion and be funded from our share of cash flows from the Tamar asset as well as borrowings underbegan completion operations at the Leviathan Term Loan Facility (defined below).
During second quarter 2017, we drilled the L5 development4 well. Detailed design and engineering, as well as equipment and pipeline manufacturing activities,First natural gas sales are currently underway. We expect to continue drilling activities and commence well completion in 2018 and are targeting first productionanticipated by the end of 2019.
At June 30, 2017, we recorded Leviathan proved undeveloped reserves of 551 MMBoe, net.
Tamar Natural Gas Project (Offshore Israel) In April 2017, we commenced production from the Tamar 8 well and results from the well are currently being integrated into our geologic modeling for application across the reservoir. Growth in power and industrial demand in Israel, resulting from the increased use of natural gas over coal to fuel power generation, and coupled with almost 100% uptime, enabled us to set a new second quarter record for average daily gross sales volumes of 962 MMcfe/d during second quarter 2017. We continue to market a portion of our working interest in Tamar, in accordance with the Framework, which provides for reduction in our ownership interest to 25% by year-end 2021.
Alba Field Unitization (Offshore West Africa) In April 2017, we executed a unitization agreement on the Alba field with our partner and the Government of Equatorial Guinea. The agreement was between Alba Block and Block D partners. As a result of the unitization, our revenue interest going forward changes from 34% to 32% and our non-operated working interest changed from 35% to 33%. We anticipate third quarter 2017 sales volumes from the Alba field to be lower as a result of the unitization; however, we expect the impact on our proved reserves and allocated future sales volumes to be de minimis.
Unsanctioned Development Projects
Tamar Expansion Project (Offshore Israel) West Africa Natural Gas MonetizationWe are engaged incontinue efforts to monetize our significant natural gas discoveries offshore West Africa. A natural gas development team has been working with local governments to evaluate natural gas monetization concepts and progress negotiations of required contracts. In May 2018, we announced the planning phaseexecution, along with the Government of the Republic of Equatorial Guinea and necessary third-parties, of a Heads of Agreement establishing the framework for the Tamar expansion project. The project would expand field deliverabilitydevelopment of natural gas from the current levelAlen field. The agreement outlines the high-level commercial terms for Alen natural gas to be processed through Alba Plant LLC’s liquefied petroleum gas (LPG) plant and Equatorial Guinea LNG Holdings Limited’s LNG plant. Both plants are located in Punta Europa. The contemplated structure would result in Alen gas being marketed to global LNG markets. Sanction of approximately 1.2 Bcf/dthe project is contingent upon final commercial agreements being executed.
Existing production and processing facilities in place at the Alen platform and in Punta Europa require certain modifications to approximately 2.1 Bcf/d,produce and process the Alen natural gas. The agreement contemplates construction of a quantity that65-kilometer pipeline to transport natural gas from the Alen platform to the facilities in Punta Europa.
would allow for additional regional export. Expansion would include a third flow line component and additional producing wells. Timing of project sanction is dependent upon progress relating to marketing efforts of these resources.
Cyprus Natural Gas Project (Offshore Cyprus) We continue to work with the Government of Cyprus on a plan of development for the Aphrodite field that, as currently planned, would deliver natural gas to potential regional customers. In addition, we are focused on capital cost improvements, as well as natural gas marketing efforts and execution of natural gas sales and purchase agreements, which, once secured, will progress the project to a final investment decision.
West Africa Natural Gas Monetization We continue our efforts to monetize our significant natural gas discoveries offshore West Africa. A natural gas development team has been working with local governments to evaluate natural gas monetization concepts. After analyzing existing infrastructure, including the Alen platform and other facilities, we believe these assets can be efficiently modified and retrofitted to allow for future commercialization of natural gas. Leveraging existing assets for the development of natural gas minimizes future capital expenditures while providing advantageous financial returns.
Given the monetization plan, to develop the Alen resources through existing infrastructure, we changed the units-of-production depletion rate, based on risked resources, during first quarter 2017. As a result, we proportionally allocated the existing book value associated with the existing infrastructure assets to the natural gas resources that will be developed in the future, resulting in approximately $153 million of net asset value being reclassified as development costs not subject to depletion in first quarter 2017. See Item 1. Financial Statements – Note 8. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs, Operating Outlook – Potential for Future Dry Hole Cost, Lease Abandonment Expense or Property Impairments, below, and Results of Operations - Operating Costs and Expenses, below.Exploration Program Update
Our 2017 exploration budget has been substantially reduced comparedWe continue to prior years due to the current commodity price environment. In 2017, we anticipate engaging in seismic acquisitionseek and processing and participating in drilling an exploratory wellevaluate significant onshore and/or offshore Suriname in which we own a 20% non-operating working interest.
opportunities for future exploration. Through our drilling activities, we do not always encounter hydrocarbons. In addition, we may find hydrocarbons but subsequently reach a decision, through additional analysis or appraisal drilling, that a development project is not economically or operationally viable. In the event we conclude that one of our exploratory wells did not encounter hydrocarbons or that a discovery is not economically or operationally viable, the associated capitalized exploratory well costs will be recorded as dry hole expense.
Results of Operations
Highlights for our E&P business were as follows:
Second Quarter 20172018 Significant E&P Operating Highlights Included:
total average daily sales volumes of 408346 MBoe/d, net;
record average daily sales volumes for US onshore crude oil of 88105 MBbl/d;d, net;
record average daily sales volumes of 275 MMcfe/over 1 Bcf/d, net,gross, in Israel, and record second quarter average daily gross sales volumes of 962 MMcfe/d;primarily from the Tamar field;
closed the Clayton Williams Energy AcquisitionGulf of Mexico asset divestiture; and
executed Heads of Agreement regarding framework for $2.5 billiondevelopment of stock and cash consideration, adding highly contiguous acreage in the core of the Delaware Basin and proved reserves of 86 MMBoe, of which 69 MMBoe are proved undeveloped;
closed the sale of all of the Marcellus Shale upstream assets on June 28, 2017, representing approximately 241 MMBoe of proved natural gas reserves, and received cash of $1.0 billion;
recorded Leviathanfrom the Alen field, proved undeveloped reserves of 551 MMBoe, net; and
sold midstream assets to Noble Midstream Partners for $270 million consideration.offshore Equatorial Guinea.
Second Quarter 20172018 E&P Financial Results Included:
net cash proceeds of $383 million, after closing adjustments, received from the Gulf of Mexico asset sale;
total loss of $249 million on Marcellus Shale upstream divestiture of $2.3 billion;commodity derivative instruments;
pre-tax lossincome of $2.1 billion,$7 million, as compared with pre-tax loss of $328$2.1 billion for second quarter 2017; and
capital expenditures, excluding acquisitions, of $787 million, as compared with $613 million for second quarter 2016; and2017.
capital expenditures of $613 million, excluding acquisitions, as compared with $257 million for second quarter 2016.
Following is a summarized statement of operations for our E&P business:
|
| | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| (millions) | 2017 | | 2016 | | 2017 | | 2016 |
| Oil, NGL and Gas Sales from Third Parties | $ | 1,017 |
| | $ | 823 |
| | $ | 2,011 |
| | $ | 1,528 |
|
| Income from Equity Method Investees | 25 |
| | 9 |
| | 52 |
| | 12 |
|
| Total Revenues | 1,042 |
| | 832 |
| | 2,063 |
| | 1,540 |
|
| Production Expense | 310 |
| | 308 |
| | 627 |
| | 610 |
|
| Exploration Expense | 30 |
| | 89 |
| | 72 |
| | 252 |
|
| Depreciation, Depletion and Amortization | 486 |
| | 608 |
| | 999 |
| | 1,210 |
|
Loss on Marcellus Shale Upstream Divestiture (1) | 2,322 |
| | — |
| | 2,322 |
| | — |
|
| (Gain) Loss on Commodity Derivative Instruments | (57 | ) | | 151 |
| | (167 | ) | | 107 |
|
Clayton Williams Energy Acquisition Expenses (2) | 90 |
| | — |
| | 94 |
| | — |
|
| Loss Before Income Taxes | (2,145 | ) | | (328 | ) | | (1,917 | ) | | (631 | ) |
|
| | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| (millions) | 2018 | | 2017 | | 2018 | | 2017 |
Oil, NGL and Gas Sales to Third Parties (1) | $ | 1,100 |
| | $ | 1,017 |
| | $ | 2,273 |
| | $ | 2,011 |
|
Sales of Purchased Gas (2) | 24 |
| | — |
| | 55 |
| | — |
|
| Income from Equity Method Investees | 36 |
| | 25 |
| | 71 |
| | 52 |
|
| Total Revenues | 1,160 |
| | 1,042 |
| | 2,399 |
| | 2,063 |
|
Production Expense (1) | 329 |
| | 309 |
| | 681 |
| | 627 |
|
| Exploration Expense | 29 |
| | 30 |
| | 64 |
| | 72 |
|
| Depreciation, Depletion and Amortization | 435 |
| | 486 |
| | 880 |
| | 999 |
|
Purchases of Gas (2) | 31 |
| | — |
| | 67 |
| | — |
|
| Loss on Marcellus Shale Upstream Divestiture | — |
| | 2,322 |
| | — |
| | 2,322 |
|
(Loss) Gain on Divestitures (3) | 31 |
| | — |
| | (361 | ) | | — |
|
Asset Impairments (3) | — |
| | — |
| | 168 |
| | — |
|
| Loss (Gain) on Commodity Derivative Instruments | 249 |
| | (57 | ) | | 328 |
| | (167 | ) |
Clayton Williams Energy Acquisition Expenses (3) | — |
| | 90 |
| | — |
| | 94 |
|
| Income (Loss) Before Income Taxes | 7 |
| | (2,145 | ) | | 493 |
| | (1,917 | ) |
| |
(1) | On January 1, 2018, we adopted ASC 606. As a result of adoption, we changed the presentation of certain US midstream processing arrangements as related to net and gross presentation of revenues and expenses. This presentation change resulted in increases to revenues, and corresponding increases to production expense, of $2 million and $7 million for second quarter and the first six months of 2018, respectively. SeeItem 1. Financial Statements – Note 2. Basis of Presentation4. Acquisitions and Divestitures. |
| |
(2) | Beginning in first quarter 2018, as part of our Marcellus Shale firm transportation mitigation efforts, we entered into certain transactions for the purchase of third party natural gas and the subsequent sale of natural gas to other third parties. |
Oil, NGL and Gas Sales
Average daily sales volumes and average realized sales prices, which exclude gains and losses related to commodity derivative instruments, were as follows:
| | | | Sales Volumes | | Average Realized Sales Prices | Sales Volumes (1) | | Average Realized Sales Prices (1) |
| | Crude Oil & Condensate (MBbl/d) | | NGLs (MBbl/d) | | Natural Gas (MMcf/d) | | Total (MBoe/d) (1) | | 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) (2) | | Crude Oil & Condensate (Per Bbl) | | NGLs (Per Bbl) | | Natural Gas (Per Mcf) |
| Three Months Ended June 30, 2017 | |
| United States | 110 |
| | 63 |
| | 736 |
| | 296 |
| | $ | 45.78 |
| | $ | 18.79 |
| | $ | 3.20 |
| |
| Israel | — |
| | — |
| | 272 |
| | 46 |
| | — |
| | — |
| | 5.34 |
| |
Equatorial Guinea (2) | 22 |
| | — |
| | 231 |
| | 60 |
| | 49.53 |
| | — |
| | 0.27 |
| |
| Three Months Ended June 30, 2018 | | Three Months Ended June 30, 2018 |
United States (3) | | 108 |
| | 62 |
| | 467 |
| | 247 |
| | $ | 64.67 |
| | $ | 24.46 |
| | $ | 2.29 |
|
| Eastern Mediterranean | | — |
| | — |
| | 225 |
| | 38 |
| | — |
| | — |
| | 5.46 |
|
West Africa (4) | | 17 |
| | — |
| | 225 |
| | 54 |
| | 72.79 |
| | — |
| | 0.27 |
|
| Total Consolidated Operations | 132 |
| | 63 |
| | 1,239 |
| | 402 |
| | 46.40 |
| | 18.79 |
| | 3.13 |
| 125 |
| | 62 |
| | 917 |
| | 339 |
| | 65.77 |
| | 24.46 |
| | 2.57 |
|
Equity Investees (3)(5) | 2 |
| | 4 |
| | — |
| | 6 |
| | 50.93 |
| | 34.46 |
| | — |
| 2 |
| | 5 |
| | — |
| | 7 |
| | 76.07 |
| | 43.36 |
| | — |
|
| Total | 134 |
| | 67 |
| | 1,239 |
| | 408 |
| | $ | 46.49 |
| | $ | 19.84 |
| | $ | 3.13 |
| 127 |
| | 67 |
| | 917 |
| | 346 |
| | $ | 65.93 |
| | $ | 25.90 |
| | $ | 2.57 |
|
| Three Months Ended June 30, 2016 | |
| Three Months Ended June 30, 2017 | | Three Months Ended June 30, 2017 |
| United States | 96 |
| | 59 |
| | 924 |
| | 309 |
| | $ | 40.64 |
| | $ | 14.10 |
| | $ | 1.75 |
| 110 |
| | 63 |
| | 736 |
| | 296 |
| | $ | 45.78 |
| | $ | 18.79 |
| | $ | 3.20 |
|
| Israel | — |
| | — |
| | 276 |
| | 46 |
| | — |
| | — |
| | 5.15 |
| |
Equatorial Guinea (2) | 27 |
| | — |
| | 233 |
| | 66 |
| | 44.55 |
| | — |
| | 0.27 |
| |
| Eastern Mediterranean | | — |
| | — |
| | 272 |
| | 46 |
| | — |
| | — |
| | 5.34 |
|
West Africa (4) | | 22 |
| | — |
| | 231 |
| | 60 |
| | 49.53 |
| | — |
| | 0.27 |
|
| Total Consolidated Operations | | 132 |
| | 63 |
| | 1,239 |
| | 402 |
| | 46.40 |
| | 18.79 |
| | 3.13 |
|
Equity Investees (3)(5) | | 2 |
| | 4 |
| | — |
| | 6 |
| | 50.93 |
| | 34.46 |
| | — |
|
| Total | | 134 |
| | 67 |
| | 1,239 |
| | 408 |
| | $ | 46.49 |
| | $ | 19.84 |
| | $ | 3.13 |
|
| Six Months Ended June 30, 2018 | | Six Months Ended June 30, 2018 |
United States (3) | | 115 |
| | 63 |
| | 486 |
| | 259 |
| | $ | 63.23 |
| | $ | 25.00 |
| | $ | 2.47 |
|
| Eastern Mediterranean | | — |
| | — |
| | 243 |
| | 41 |
| | — |
| | — |
| | 5.47 |
|
West Africa (4) | | 16 |
| | — |
| | 215 |
| | 51 |
| | 70.65 |
| | — |
| | 0.27 |
|
| Total Consolidated Operations | 123 |
| | 59 |
| | 1,433 |
| | 421 |
| | 41.51 |
| | 14.10 |
| | 2.16 |
| 131 |
| | 63 |
| | 944 |
| | 351 |
| | 64.13 |
| | 25.00 |
| | 2.74 |
|
Equity Investees (3)(5) | 1 |
| | 5 |
| | — |
| | 6 |
| | 49.94 |
| | 27.64 |
| | — |
| 2 |
| | 5 |
| | — |
| | 7 |
| | 71.56 |
| | 41.61 |
| | — |
|
| Total | 124 |
| | 64 |
| | 1,433 |
| | 427 |
| | $ | 41.61 |
| | $ | 15.07 |
| | $ | 2.16 |
| 133 |
| | 68 |
| | 944 |
| | 358 |
| | $ | 64.22 |
| | $ | 26.27 |
| | $ | 2.74 |
|
Six Months Ended June 30, 2017 | | United States | 105 |
| | 56 |
| | 733 |
| | 283 |
| | $ | 47.31 |
| | $ | 21.04 |
| | $ | 3.32 |
| 105 |
| | 56 |
| | 733 |
| | 283 |
| | $ | 47.31 |
| | $ | 21.04 |
| | $ | 3.32 |
|
| Israel | — |
| | — |
| | 272 |
| | 46 |
| | — |
| | — |
| | 5.33 |
| |
Equatorial Guinea (2) | 20 |
| | — |
| | 237 |
| | 59 |
| | 51.28 |
| | — |
| | 0.27 |
| |
| Eastern Mediterranean | | — |
| | — |
| | 272 |
| | 46 |
| | — |
| | — |
| | 5.33 |
|
West Africa (4) | | 20 |
| | — |
| | 237 |
| | 59 |
| | 51.28 |
| | — |
| | 0.27 |
|
| Total Consolidated Operations | 125 |
| | 56 |
| | 1,242 |
| | 388 |
| | 47.95 |
| | 21.04 |
| | 3.18 |
| 125 |
| | 56 |
| | 1,242 |
| | 388 |
| | 47.95 |
| | 21.04 |
| | 3.18 |
|
Equity Investees (3)(5) | 2 |
| | 5 |
| | — |
| | 7 |
| | 51.71 |
| | 35.38 |
| | — |
| 2 |
| | 5 |
| | — |
| | 7 |
| | 51.71 |
| | 35.38 |
| | — |
|
| Total | 127 |
| | 61 |
| | 1,242 |
| | 395 |
| | $ | 48.01 |
| | $ | 22.29 |
| | $ | 3.18 |
| 127 |
| | 61 |
| | 1,242 |
| | 395 |
| | $ | 48.01 |
| | $ | 22.29 |
| | $ | 3.18 |
|
| Six Months Ended June 30, 2016 | |
| United States | 99 |
| | 56 |
| | 917 |
| | 308 |
| | $ | 35.22 |
| | $ | 12.73 |
| | $ | 1.82 |
| |
| Israel | — |
| | — |
| | 271 |
| | 45 |
| | — |
| | — |
| | 5.17 |
| |
Equatorial Guinea (2) | 27 |
| | — |
| | 214 |
| | 63 |
| | 39.53 |
| | — |
| | 0.27 |
| |
| Total Consolidated Operations | 126 |
| | 56 |
| | 1,402 |
| | 416 |
| | 36.14 |
| | 12.73 |
| | 2.23 |
| |
Equity Investees (3)(5) | 1 |
| | 4 |
| | — |
| | 6 |
| | 42.34 |
| | 25.02 |
| | — |
| |
| Total | 127 |
| | 60 |
| | 1,402 |
| | 422 |
| | $ | 36.20 |
| | $ | 13.63 |
| | $ | 2.23 |
| |
| |
(1) | On January 1, 2018, we adopted ASC 606. As a result of adoption, we changed the presentation of certain US midstream processing arrangements as related to net and gross presentation of revenues and expenses. SeeItem 1. Financial Statements – Note 2. Basis of Presentation. This presentation change resulted in the following: |
| |
| ◦ | increases in NGL revenues, and corresponding increases in production expense, of $4 million and $9 million for second quarter 2018 and the first six months of 2018, respectively; |
| |
| ◦ | decreases in natural gas revenues, and corresponding decreases in production expense, of $2 million for both second quarter 2018 and the first six months of 2018; |
| |
| ◦ | increases in NGL and natural gas sales volumes of 5 MBbl/d and 31 MMcf/d, respectively, for both second quarter 2018 and the first six months of 2018, respectively; and |
| |
| ◦ | reductions in average realized NGL and natural gas sales prices of $1.31/Bbl and $0.11/Mcf, respectively, for second quarter 2018 and $1.09/Bbl and $0.10/Mcf, respectively, for the first six months of 2018. |
| |
(2) | Natural gas is converted on the basis of six Mcf of gas per one barrel of crude oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Given commodity price disparities, the priceprices 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. |
| |
(4) | Natural gas from the Alba field in Equatorial Guinea 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 in part by affiliated entities accounted for under the equity method of accounting. |
| |
(3)(5)
| Volumes represent sales of condensate and LPG from the LPG plant in Equatorial Guinea. See Income from Equity Method Investees, below. |
An analysis of revenues from sales of crude oil, natural gas and NGLs is as follows: | | | | Sales Revenues | Sales Revenues |
| (millions) | Crude Oil & Condensate | | NGLs | | Natural Gas | | Total | Crude Oil & Condensate | | NGLs | | Natural Gas | | Total |
| Three Months Ended June 30, 2016 | $ | 465 |
| | $ | 76 |
| | $ | 282 |
| | $ | 823 |
| |
| Three Months Ended June 30, 2017 | | $ | 557 |
| | $ | 108 |
| | $ | 352 |
| | $ | 1,017 |
|
| Changes due to | | | | | | | | |
| Decrease in Sales Volumes | | (31 | ) | | (10 | ) | | (107 | ) | | (148 | ) |
Increase (Decrease) in Sales Prices (1) | | 223 |
| | 35 |
| | (29 | ) | | 229 |
|
| Impact of ASC 606 Adoption | | — |
| | 4 |
| | (2 | ) | | 2 |
|
| Three Months Ended June 30, 2018 | | $ | 749 |
| | $ | 137 |
| | $ | 214 |
| | $ | 1,100 |
|
| | | | | | | | | |
| Six Months Ended June 30, 2017 | | $ | 1,084 |
| | $ | 213 |
| | $ | 714 |
| | $ | 2,011 |
|
| Changes due to | | | | | | | | | | | | | | |
| Increase (Decrease) in Sales Volumes | 33 |
| | 4 |
| | (28 | ) | | 9 |
| 49 |
| | 1 |
| | (192 | ) | | (142 | ) |
| Increase in Sales Prices | 59 |
| | 28 |
| | 98 |
| | 185 |
| |
| Three Months Ended June 30, 2017 | $ | 557 |
| | $ | 108 |
| | $ | 352 |
| | $ | 1,017 |
| |
| | | | | | | | | |
| Six Months Ended June 30, 2016 | $ | 829 |
| | $ | 130 |
| | $ | 569 |
| | $ | 1,528 |
| |
| Changes due to | | | | | | | | |
| Decrease in Sales Volumes | (5 | ) | | (1 | ) | | (56 | ) | | (62 | ) | |
| Increase in Sales Prices | 260 |
| | 84 |
| | 201 |
| | 545 |
| |
| Six Months Ended June 30, 2017 | $ | 1,084 |
| | $ | 213 |
| | $ | 714 |
| | $ | 2,011 |
| |
Increase (Decrease) in Sales Prices (1) | | 389 |
| | 60 |
| | (52 | ) | | 397 |
|
| Impact of ASC 606 Adoption | | — |
| | 9 |
| | (2 | ) | | 7 |
|
| Six Months Ended June 30, 2018 | | $ | 1,522 |
| | $ | 283 |
| | $ | 468 |
| | $ | 2,273 |
|
(1) Changes exclude gains and losses related to commodity derivate instruments.
Crude Oil and Condensate SalesRevenuesCrude oil prices continue to be volatile. During second quarter 2017, our sales volumes grew significantly.
Revenues from crude oil and condensate sales increased for second quarter 2017and the first six months of 2018 as compared with 20162017 due to the following:
higher average realized prices, as compared with 2016, due to partial price recovery;
higher sales volumesincreases of 5 MBbl/d, net, in42% and 34% for second quarter and the DJ Basin primarily attributable to well locations being developed in the oil-rich part of the basin and enhanced well design and completion techniques;
higher sales volumes of 10 MBbl/d, net, in the Delaware Basin primarily attributable to increased development and enhanced well design and completion techniques, as well as sales volumes contributed by recently acquired Clayton Williams Energy assets which contributed 5 MBbl/d, net, of the basin's total crude oil sales volumes; and
production from the Gunflint development, Gulf of Mexico, which began producing in July 2016 and contributed 6 MBbl/d, net, during the current quarter;
partially offset by:
lower sales volumes in the Eagle Ford Shale primarily attributable to commodity mix from recently completed wells; and
lower sales volumes due to natural field decline at Aseng and Alen, offshore Equatorial Guinea.
Revenues from crude oil and condensate sales increased for thefirst six months ended June 30, 2017 as compared with 2016 due to the following:
higherof 2018, respectively, in average realized prices due to the partial rebalancing of global supply and demand factorsfactors; and steady price recovery, primarily during first quarter 2017;
higher US onshore sales volumes of 117 MBbl/d net,and 22 MBbl/d for second quarter and the first six months of 2018, respectively, primarily driven by an increase in the DJ Basin primarily attributable to well locations being developed in the oil-rich part of the basin and enhanced well design and completion techniques;
higher sales volumes of 7 MBbl/d, net,development activity in the Delaware Basin primarily attributable to increased development and enhanced well designDJ Basin and completion techniques, as well as sales volumes contributed by recently acquiredthe Clayton Williams Energy assets which contributed 3 MBbl/d, net, of the basin's total crude oil sales volumes; and
production from the Gunflint development, Gulf of Mexico, which began producing in July 2016 and contributed 5 MBbl/d, net;acquisition;
partially offset by:
lower Gulf of Mexico sales volumes inof 19 MBbl/d and 12 MBbl/d for second quarter and the Eagle Ford Shale primarily attributable to commodity mix from recently completed wells; and
lower sales volumesfirst six months of 2018, respectively, due to natural field decline at Asengas well as the sale of the Gulf of Mexico assets in April 2018; and Alen,
lower offshore Equatorial Guinea.Guinea sales volumes of 5 MBbl/d and 4 MBbl/d for second quarter and the first six months of 2018, respectively, due to natural field decline.
NGL SalesRevenues Revenuesfrom NGL sales increased for second quarter 2017and the first six months of 2018 as compared with 20162017 due to the following:
higher US onshore sales volumes of 4 MBbl/d (exclusive of 5 MBbl/d from adoption of ASC 606) and 13 MBbl/d (exclusive of 5 MBbl/d from adoption of ASC 606) for second quarter and the first six months of 2018, respectively, primarily attributable to development activities in the southern area of Gates Ranch in the Eagle Ford Shale;
increases of 37% and 24% in average realized prices for second quarter and the first six months of 2018, respectively, due to the partial rebalancing of domestic supply and demand factors;
higher sales volumes of 3 MBbl/d, net, in the Delaware Basin during the quarter primarily attributable to increased development and enhanced well design and completion techniques as well as sales volumes contributed by recently acquired Clayton Williams Energy assets, which contributed 1 MBbl/d, net, of the basin's NGL sales volumes; and
higher sales volumes in the Eagle Ford Shale primarily attributable to commodity mix from recently completed wells;
partially offset by:
lower sales volumes in the DJ Basin primarily attributable to increased focus on the oil-rich well locations of the basin.
Revenuesfrom NGL sales increased for the six months ended June 30, 2017 as compared with 2016 due to the following:
higher average realized prices due to the partial rebalancing of domestic supply$4 million and demand factors and steady price recovery, primarily during first quarter 2017; and
higher sales volumes of 2 MBbl/d, net, in the Delaware Basin primarily attributable to increased development and enhanced well design and completion techniques;
partially offset by:
lower sales volumes in the DJ Basin primarily attributable to increased focus on the oil-rich well locations of the basin.
Natural Gas SalesRevenuesNatural gas prices have traded within a narrow range thus far in 2017. Revenues from natural gas sales increased$9 million for second quarter and the first six months of 2017 as compared2018, respectively, associated with 2016 due to the following:
higher average realized US prices due to the partial rebalancingadoption of domestic supply and demand factors and significant price recovery as compared with 2017;
higher sales volumes in the Delaware Basin primarily attributable to increased development and enhanced well design and completion techniques as well as sales volumes contributed by recently acquired Clayton Williams Energy assets;
higher sales volumes in the Eagle Ford Shale primarily attributable to commodity mix from recently completed wells; and
production from the Gunflint development, Gulf of Mexico, which began producing in July 2016;ASC 606;
partially offset by:
lower sales volumes inof 9 MBbl/d for second quarter and the first six months of 2018, due to the divestiture of the Marcellus Shale primarilyupstream assets in second quarter 2017.
Natural Gas SalesRevenuesRevenues from natural gas sales decreased second quarter and the first six months of 2018 as compared with 2017 due to natural well decline;the following:
lower sales volumes of 331 MMcf/d and 350 MMcf/d for second quarter and the first six months of 2018, respectively, due to the divestiture of the Marcellus Shale upstream assets in second quarter 2017;
lower sales volumes in Israel due to the DJ Basin primarily attributablesale of a 7.5% interest in the Tamar field;
lower Gulf of Mexico sales volume of 14 MMcf/d and 8 MMcf/d for the second quarter and the first six months of 2018, respectively, due to increased focus onnatural field decline as well as the oil-rich well locationssale of the basin; andGulf of Mexico assets in April 2018;
lower sales volumes of 296 MMcf/d net, duringand 21 MMcf/d for second quarter and the first six months of 2018, respectively, from the Alba field, offshore Equatorial Guinea, due to natural field decline and timing of field maintenance; and
decreases of 14% and 10% in average realized prices for second quarter and the first six months of 2018, respectively, due to the impact of increased onshore US supply, as well as wider summer price differentials for both DJ and Delaware Basin volumes;
partially offset by:
higher US onshore sales volumes of 53 MMcf/d (exclusive of 31 MMcf/d from adoption of ASC 606) and 89 MMcf/d (exclusive of 31 MMcf/d from adoption of ASC 606) the second quarter and the first six months of 20172018, respectively, primarily attributable to development activities in the DJ Basin and the southern area of Gates Ranch in the Eagle Ford Shale; and
higher sales volumes in Israel due to increased demand.
Sales of Purchased Gas, Net Beginning in first quarter 2018, weentered into purchase transactions and separate sale transactions with third parties at prevailing market prices to mitigate unutilized pipeline transportation commitments, primarily related to retained Marcellus Shale natural gas firm transportation agreements. Revenues and expenses from the sales and purchases are recorded on a gross basis, as we act as a resultprincipal in these transactions by assuming control of the salepurchased commodity before it is transferred to the customer. Transportation costs incurred related to utilization of 3.5% working interestthe retained Marcellus Shale firm transportation agreements are recorded within purchases of gas in our consolidated statements of operations. For second quarter and the Tamar field in December 2016.first six months of 2018, the net effect of third party purchases and sales of natural gas were losses of $7 million and $12 million, respectively.
Income from Equity Method InvesteesWe have interests in equity method investees that operate midstream assets servicing our West Africa production. Equity method investments are included in other noncurrent assets in our consolidated balance sheets, and our share of earnings is reported as income from equity method investees in our consolidated statements of operations. Within our consolidated statements of cash flows, activity is reflected within cash flows provided by operating activities and cash flows provided by (used in) investing activities.
Income from equity method investees increased during the first six months of 20172018 as compared with 2016.2017. The increase includes a $24$6 million increase from Atlantic Methanol Production Company, LLC (AMPCO), our methanol investee, and a $16$12 million increase from Alba Plant, our LPG investee, bothall primarily driven by rising commodity prices and a 1 MBbl/d increase in sales volumes at Alba Plant.
prices.
Production Expense Components of production expense from our E&P operations were as follows: |
| | | | | | | | | | | | | | | | | | | | | | | |
| (millions, except unit rate) | Total per BOE (1) | | Total | | United States | | Eastern
Mediter- ranean | | West Africa | | Other Int'l |
| Three Months Ended June 30, 2017 | | | | | | | | | | | |
Lease Operating Expense (2) | $ | 3.54 |
| | $ | 129 |
| | $ | 105 |
| | $ | 6 |
| | $ | 18 |
| | $ | — |
|
| Production and Ad Valorem Taxes | 1.07 |
| | 39 |
| | 39 |
| | — |
| | — |
| | — |
|
Gathering, Transportation and Processing (3) | 3.89 |
| | 142 |
| | 142 |
| | — |
| | — |
| | — |
|
| Total Production Expense | $ | 8.50 |
| | $ | 310 |
| | $ | 286 |
| | $ | 6 |
| | $ | 18 |
| | $ | — |
|
| Total Production Expense per BOE | | | $ | 8.50 |
| | $ | 10.64 |
| | $ | 1.46 |
| | $ | 3.28 |
| | $ | — |
|
| Three Months Ended June 30, 2016 | |
| | |
| | |
| | |
| | |
| | |
|
Lease Operating Expense (2) | $ | 3.45 |
| | $ | 132 |
| | $ | 101 |
| | $ | 7 |
| | $ | 24 |
| | $ | — |
|
| Production and Ad Valorem Taxes | 1.02 |
| | 39 |
| | 39 |
| | — |
| | — |
| | — |
|
Gathering, Transportation and Processing (3) | 3.58 |
| | 137 |
| | 137 |
| | — |
| | — |
| | — |
|
| Total Production Expense | $ | 8.05 |
| | $ | 308 |
| | $ | 277 |
| | $ | 7 |
| | $ | 24 |
| | $ | — |
|
| Total Production Expense per BOE | | | $ | 8.05 |
| | $ | 9.86 |
| | $ | 1.66 |
| | $ | 3.99 |
| | $ | — |
|
| Six Months Ended June 30, 2017 | | | | | | | | | | | |
Lease Operating Expense (2) | $ | 3.78 |
| | $ | 265 |
| | $ | 211 |
| | $ | 14 |
| | $ | 40 |
| | $ | — |
|
| Production and Ad Valorem Taxes | 1.17 |
| | 82 |
| | 82 |
| | — |
| | — |
| | — |
|
Gathering, Transportation and Processing (3) | 3.99 |
| | 280 |
| | 280 |
| | — |
| | — |
| | — |
|
| Total Production Expense | $ | 8.94 |
| | $ | 627 |
| | $ | 573 |
| | $ | 14 |
| | $ | 40 |
| | $ | — |
|
| Total Production Expense per BOE | | | $ | 8.94 |
| | $ | 11.20 |
| | $ | 1.71 |
| | $ | 3.72 |
| | $ | — |
|
| Six Months Ended June 30, 2016 | |
| | |
| | |
| | |
| | |
| | |
|
Lease Operating Expense (2) | $ | 3.98 |
| | $ | 302 |
| | $ | 232 |
| | $ | 17 |
| | $ | 53 |
| | $ | — |
|
| Production and Ad Valorem Taxes | 0.53 |
| | 40 |
| | 40 |
| | — |
| | — |
| | — |
|
Gathering, Transportation and Processing (3) | 3.54 |
| | 268 |
| | 268 |
| | — |
| | — |
| | — |
|
| Total Production Expense | $ | 8.06 |
| | $ | 610 |
| | $ | 540 |
| | $ | 17 |
| | $ | 53 |
| | $ | — |
|
| Total Production Expense per BOE | | | $ | 8.06 |
| | $ | 9.65 |
| | $ | 2.05 |
| | $ | 4.63 |
| | $ | — |
|
N/M Amount is not meaningful. |
| | | | | | | | | | | | | | | | | | | |
| (millions, except unit rate) | Total per BOE (1) (2) | | Total | | United States (2) | | Eastern
Mediter- ranean | | West Africa |
| Three Months Ended June 30, 2018 | | | | | | | | | |
Lease Operating Expense (3) | $ | 4.47 |
| | $ | 138 |
| | $ | 114 |
| | $ | 5 |
| | $ | 19 |
|
| Production and Ad Valorem Taxes | 1.56 |
| | 48 |
| | 48 |
| | — |
| | — |
|
Gathering, Transportation and Processing (4) | 4.31 |
| | 133 |
| | 133 |
| | — |
| | — |
|
| Other Royalty Expense | 0.33 |
| | 10 |
| | 10 |
| | — |
| | — |
|
| Total Production Expense | $ | 10.67 |
| | $ | 329 |
| | $ | 305 |
| | $ | 5 |
| | $ | 19 |
|
| Total Production Expense per BOE | | | $ | 10.67 |
| | $ | 13.55 |
| | $ | 1.47 |
| | $ | 3.84 |
|
| Three Months Ended June 30, 2017 | |
| | |
| | |
| | |
| | |
|
Lease Operating Expense (3) | $ | 3.54 |
| | $ | 129 |
| | $ | 105 |
| | $ | 6 |
| | $ | 18 |
|
| Production and Ad Valorem Taxes | 0.89 |
| | 32 |
| | 32 |
| | — |
| | — |
|
Gathering, Transportation and Processing (4) | 3.89 |
| | 142 |
| | 142 |
| | — |
| | — |
|
| Other Royalty Expense | 0.16 |
| | 6 |
| | 6 |
| | — |
| | — |
|
| Total Production Expense | $ | 8.48 |
| | $ | 309 |
| | $ | 285 |
| | $ | 6 |
| | $ | 18 |
|
| Total Production Expense per BOE | | | $ | 8.48 |
| | $ | 10.60 |
| | $ | 1.46 |
| | $ | 3.28 |
|
| Six Months Ended June 30, 2018 | | | | | | | | | |
Lease Operating Expense (3) | $ | 4.62 |
| | $ | 293 |
| | $ | 240 |
| | $ | 12 |
| | $ | 41 |
|
| Production and Ad Valorem Taxes | 1.59 |
| | 101 |
| | 101 |
| | — |
| | — |
|
Gathering, Transportation and Processing (4) | 4.10 |
| | 260 |
| | 260 |
| | — |
| | — |
|
| Other Royalty Expense | 0.43 |
| | 27 |
| | 27 |
| | — |
| | — |
|
| Total Production Expense | $ | 10.74 |
| | $ | 681 |
| | $ | 628 |
| | $ | 12 |
| | $ | 41 |
|
| Total Production Expense per BOE | | | $ | 10.74 |
| | $ | 13.42 |
| | $ | 1.64 |
| | $ | 4.39 |
|
| Six Months Ended June 30, 2017 | |
| | |
| | |
| | |
| | |
|
Lease Operating Expense (3) | $ | 3.78 |
| | $ | 265 |
| | $ | 211 |
| | $ | 14 |
| | $ | 40 |
|
| Production and Ad Valorem Taxes | 1.03 |
| | 72 |
| | 72 |
| | — |
| | — |
|
Gathering, Transportation and Processing (4) | 3.99 |
| | 280 |
| | 280 |
| | — |
| | — |
|
| Other Royalty Expense | 0.14 |
| | 10 |
| | 10 |
| | — |
| | — |
|
| Total Production Expense | $ | 8.94 |
| | $ | 627 |
| | $ | 573 |
| | $ | 14 |
| | $ | 40 |
|
| Total Production Expense per BOE | | | $ | 8.94 |
| | $ | 11.20 |
| | $ | 1.71 |
| | $ | 3.72 |
|
| |
(1) | Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees. |
| |
(2) | United States E&P production expense includes charges from our midstream operations that are eliminated on a consolidated basis. See Item 1. Financial Statements – Note 11. Segment Information. |
| |
(3) | Lease operating expense includes oil and gas operating costs (labor, fuel, repairs, replacements, saltwater disposal and other related lifting costs) and workover expense. |
| |
(3)(4)
| CertainUpon adoption of our processing expense was historically presented as a componentASC 606 on January 1, 2018, we changed the presentation for certain of other operating expense, net, in our consolidated statements of operations. Beginning in 2017, we have changed our presentation to reflect processing expense as a component of production expense. These costs are now included within gathering, transportation and processing expense. Forexpenses in accordance with the three and six months ended June 30, 2017, these costs totaledcontrol model under the new standard. As such, we reflected increases of $2 million and $5$7 million respectively. Forto gathering, transportation and processing expense related to US operations for second quarter and the three andfirst six months ended June 30, 2016, these costs totaled $6 millionof 2018, respectively. On a per BOE basis, including the increase in production volumes, the presentation change resulted in decreases of $0.46/Boe and $10 million respectively,$0.35/Boe for US production expense for the second quarter and havethe first six months of 2018, respectively. No other geographical locations were affected by the presentation change. Comparative information for the prior period has not been reclassified from marketing expenserecast and continues to conform tobe reported under ASC 605, Revenue Recognition, the current presentation.accounting standard in effect for the prior period. |
For second quarter 2017, total production expense remained flat as compared with 2016. Changes included the following:
an increase in lease operating expense due to higher production in the Delaware Basin; and
an increase in gathering, transportation and processing expense due to higher production in the Delaware Basin, the shifting of crude oil volumes onto a new export pipeline and contractual increases of pipeline fees in the DJ Basin, and the startup of our Gunflint development, Gulf of Mexico, which began producing in July 2016;
partially offset by:
a decrease in lease operating expense due to the timing of workover projects in the DJ Basin and offshore West Africa; and
a decrease in gathering, transportation and processing expense due to lower production in the DJ Basin and Marcellus Shale.
For the first six months of 2017,2018, total production expense increased as compared with 20162017 due to the following:
an increase in US lease operating expense primarily due to higherincreased development activities resulting in added production in the Delaware Basin;across each of our onshore US basins;
an increase in US production and ad valorem taxes due to higher commodity prices; and
an increase in US gathering, transportation and processing expense attributable to development activities in the southern area of Gates Ranch in the Eagle Ford Shale which led to increased sales volumes; and
an increase in US other royalty expense due to the factors noted above;increased commodity market prices;
partially offset by:
a decrease in first quarter 2018 in US lease operating expense in the Gulf of Mexico due to lower production caused by natural field decline and the timingsubsequent sale of workover projectsthe assets in the DJ Basin and offshore West Africa;
a decrease in production and ad valorem taxes due to a $28 million US onshore severance tax refund recorded in firstsecond quarter 2016 versus a $7 million US onshore severance tax charge recorded in first quarter 2017;2018; and
a decreasedecreases in US lease operating and gathering, transportation and processing expenseexpenses due to lower productionthe divestiture of the Marcellus Shale upstream assets in the DJ Basin and Marcellus Shale.second quarter 2017.
Production expense on a per BOE basis increased due lower sales volumes and increases in production and ad valorem taxes as discussed above. Transportation expense per BOE is also higher infor the first six months of 2017 as compared to 2016 due to the shifting of crude oil volumes onto a new export pipeline and contractual increases of pipeline fees in the DJ Basin.
Exploration Expense Our 2017 exploration budget has been substantially reduced compared to prior years due to the current commodity price environment. Exploration expense for second quarter and the first six months of 2018, as compared with 2017 included Gulfprimarily due to the decrease in total sales volumes driven by the divestiture of Mexico leasehold impairmentthe Marcellus Shale upstream assets in second quarter 2017, coupled with an increase in certain production expenses noted above. Specifically, the divestiture of the Marcellus Shale upstream assets removed lower-cost, natural gas-focused sales volumes from our portfolio, while an increase in volumes from the Delaware Basin and Eagle Ford Shale contributed higher-cost, crude oil-focused sales volumes, thereby increasing our average production expense of $18 million.per BOE.
Exploration Expense Exploration expense for second quarter and the first six months of 2016 included dry hole cost2018 totaled $64 million, including $24 million of $114lease rental expense primarily in the Delaware Basin and $27 million primarilyof staff expense.
Exploration expense for the first six months of 2017 totaled $72 million, including $18 million of undeveloped leasehold impairment expense related to the Silvergate exploratory well,impairment of leases in deepwater Gulf of Mexico and the Dolphin 1 natural gas discovery, offshore Israel.$29 million of staff expense.
Depreciation, Depletion and Amortization DD&A expense for our E&P operations was as follows:
|
| | | | | | | | | | | | | | | | | | | |
| (millions, except unit rate) | Total | | United
States | | Eastern
Mediter- ranean | | West Africa | | Other Int'l |
| Three Months Ended June 30, 2017 | | | | | | | | | |
DD&A Expense (millions) (1) | $ | 486 |
| | $ | 427 |
| | $ | 19 |
| | $ | 39 |
| | $ | 1 |
|
Unit Rate per BOE (2) | $ | 13.32 |
| | $ | 15.89 |
| | $ | 4.62 |
| | $ | 7.11 |
| | $ | — |
|
| Three Months Ended June 30, 2016 | | | | | | | | | |
DD&A Expense (millions) (1) | $ | 608 |
| | $ | 539 |
| | $ | 19 |
| | $ | 49 |
| | $ | 1 |
|
Unit Rate per BOE (2) | $ | 15.88 |
| | $ | 19.19 |
| | $ | 4.55 |
| | $ | 8.15 |
| | $ | — |
|
| Six Months Ended June 30, 2017 | | | | | | | | | |
DD&A Expense (millions) (1) | $ | 999 |
| | $ | 886 |
| | $ | 37 |
| | $ | 74 |
| | $ | 2 |
|
Unit Rate per BOE (2) | $ | 14.25 |
| | $ | 17.32 |
| | $ | 4.52 |
| | $ | 6.88 |
| | $ | — |
|
| Six Months Ended June 30, 2016 | | | | | | | | | |
DD&A Expense (millions) (1) | $ | 1,210 |
| | $ | 1,064 |
| | $ | 39 |
| | $ | 104 |
| | $ | 3 |
|
Unit Rate per BOE (2) | $ | 16.00 |
| | $ | 19.01 |
| | $ | 4.75 |
| | $ | 9.09 |
| | $ | — |
|
|
| | | | | | | | | | | | | | | | | | | |
| (millions, except unit rate) | Total | | United
States | | Eastern
Mediter- ranean | | West Africa | | Other Int'l |
| Three Months Ended June 30, 2018 | | | | | | | | | |
| DD&A Expense | $ | 435 |
| | $ | 394 |
| | $ | 15 |
| | $ | 26 |
| | $ | — |
|
Unit Rate per BOE (1) | $ | 14.10 |
| | $ | 17.51 |
| | $ | 4.41 |
| | $ | 5.25 |
| | $ | — |
|
| Three Months Ended June 30, 2017 | | | | | | | | | |
| DD&A Expense | $ | 486 |
| | $ | 427 |
| | $ | 19 |
| | $ | 39 |
| | $ | 1 |
|
Unit Rate per BOE (1) | $ | 13.32 |
| | $ | 15.89 |
| | $ | 4.62 |
| | $ | 7.11 |
| | $ | — |
|
| Six Months Ended June 30, 2018 | | | | | | | | | |
| DD&A Expense | $ | 880 |
| | $ | 800 |
| | $ | 28 |
| | $ | 52 |
| | $ | — |
|
Unit Rate per BOE (1) | $ | 13.87 |
| | $ | 17.10 |
| | $ | 3.82 |
| | $ | 5.56 |
| | $ | — |
|
| Six Months Ended June 30, 2017 | | | | | | | | | |
| DD&A Expense | $ | 999 |
| | $ | 886 |
| | $ | 37 |
| | $ | 74 |
| | $ | 2 |
|
Unit Rate per BOE (1) | $ | 14.25 |
| | $ | 17.32 |
| | $ | 4.52 |
| | $ | 6.88 |
| | $ | — |
|
| |
(2)
| Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees. |
Total DD&A expense for second quarter and the first six months of 20172018 decreased as compared with 20162017 due to the following:
lower sales volumesyear-end reserve additions, primarily in US onshore due to enhanced well design and completion techniques in our horizontal drilling program as well as reserve additions in the DJ BasinTamar field due to well results and the impact of certain property divestitures in second quarter 2016;geological evaluation, and globally due to positive commodity price revisions;
timing of the Marcellus Shale upstream divestiture in second quarter 2017, which reduced DD&A expense by approximately $63 million as a result of being classified as held for sale during April 2017;
sale of a 3.5% working interest in the Tamar field, offshore Israel, in December 2016 which reduced DD&A expense by approximately $2$99 million and $4$118 million infor second quarter and first six months of 2017, respectively;
a reduction in depletable costs of $153 million due to the reallocation of common asset costs from Alen, offshore Equatorial Guinea, to the West Africa natural gas monetization development project, which reduced DD&A expense by $16 million in the first six months of 2017; and2018, respectively;
lower sales volumes in Gulf of Mexico due to natural field decline and reductionclassification of the assets as held for sale in first quarter 2018, resulting in the depletable costs due to negative revisionscessation of DD&A expense, together resulting in estimatesdecreases of $62 million and $109 million for second quarter and the first six months of 2018, respectively; and
reclassification of a 7.5% working interest in the Tamar field, offshore Israel, as asset retirement costs;held for sale at December 31, 2017, resulting in the cessation of DD&A expense and decreases of $3 million and $7 million for second quarter and the first six months of 2018, respectively;
partially offset by:
increasedhigher sales volumes in the Delaware Basin, which more than doubled, due to higher levels ofincreased development activity as well as sales volumes contributed by recently acquiredactivities subsequent to the Clayton Williams Energy assets, which contributed 8 MBb/d, netAcquisition in second quarter 2017;
increased development activities in the southern area of Gates Ranch in the basin's total sales volumes;
an increase in sales volumes from the Gunflint development, Gulf of Mexico, which commenced production in July 2016;Eagle Ford Shale; and
higher sales volumes from the Tamar field, offshore Israel, due to higher domestic demand.
The decreaseunit rate per BOE for second quarter 2018, as compared with 2017, increased due to increased development activity and capital program in the Delaware Basin resulting in a higher depletable basis. The unit rate per BOE for the first six months of 2018, as compared with 2017, decreased due to the sale of higher-cost production from the Gulf of Mexico assets. This decrease is partially offset by the sale of lower-cost production from the sale of 7.5% Tamar interest in 2018 and the sale of the Marcellus Shale upstream assets in 2017. In addition, an increase in reserves as of December 31, 2017 in Equatorial Guinea also contributed to a decline in unit rate per BOE.
Other Operating Expense, Net See Item 1. Financial Statements – Note 2. Basis of Presentation and Item 1. Financial Statements – Note 11. Segment Information for discussion of other operating expense items for second quarter and the first six months of 20172018 as compared with 2016, was due to the reduction of higher-cost production volumes from divested Marcellus Shale properties, an increase in lower-cost production volumes from the Tamar field, decreased production from the DJ Basin and the reduction in Alen net book value, partially offset by decreases in proved reserves at year-end 2016 due to downward price revisions in the US and Equatorial Guinea.2017. Loss (Gain) Loss on Commodity Derivative Instruments (Gain) lossLoss (gain) on commodity derivative instruments includes (i) cash settlements (received) or paid relating to our crude oil and natural gas commodity derivative contracts; and (ii) non-cash (increases) or decreases in the fair values of our crude oil and natural gas commodity derivative contracts.
For the first six months of 2018, loss on commodity derivative instruments included:
net cash settlement payment of $93 million; and
net non-cash increase of $235 million in the fair value of our net commodity derivative liability, primarily driven by increases in the forward commodity price curve for crude oil.
For the first six months of 2017, gain on commodity derivative instruments included:
net cash settlement receiptsreceipt of $14 million; and
net non-cash increasesincrease of $153 million in the fair value of our net commodity derivative instruments of $153 million primarilyasset, driven by changes in the forward commodity price curves for both crude oil and natural gas.
For the first six months of 2016, loss on commodity derivative instruments included:
net cash settlement receipts of $322 million; and
non-cash decreases in the fair value of our derivative instruments of $429 million primarily driven by changes in the forward commodity price curves for both crude oil and natural gas.
MIDSTREAM
The Midstream segment owns, operates, develops and acquires domestic midstream infrastructure assets, with current focus areas being the DJ and Delaware Basins.
Noble Midstream Partners – Major Midstream Project Updates
Third-Party Sales During second quarter 2017, we initiated sales of fresh water delivery services to a third party producer located in the Greeley Crescent IDP area of the DJ Basin.
Acreage Dedications The majority of the Delaware Basin acreage acquired in the Clayton Williams Energy Acquisition has been dedicated to the Midstream segment for infield crude oil, natural gas and produced water gathering. Additionally, infield natural gas gathering has been added to the existing crude oil and produced water dedication on Noble Energy's original 47,000, net, Delaware Basin acres.
Major Midstream Construction Projects During second quarter 2017, we progressed the construction and development of multiple major projects including:
completion of a produced water expansion project servicing the Wells Ranch IDP area of the DJ Basin;
continued construction on crude oil and produced water gathering systems servicing the Greeley Crescent IDP area of the DJ Basin, which are expected to be operational in third quarter 2017;
completion of our first central gathering facility (CGF) and crude oil, natural gas and produced water gathering infrastructure located in the Delaware Basin of Texas, which became operational in July 2017; and
continued construction activities on the expansion of a freshwater system servicing the Mustang IDP area of the DJ Basin.
Advantage Pipeline Acquisition In April 2017, Noble Midstream Partners, along with its partner, Plains, completed the acquisition of Advantage Pipeline for $133 million through a newly formed 50/50 joint venture. Noble Midstream Partners contributed $66.5 million of cash, funded by available cash on hand and the Noble Midstream Services Revolving Credit Facility. Noble Midstream Partners serves as the operator of the Advantage Pipeline system, which includes a 70-mile crude oil pipeline in the Delaware Basin from Reeves County, Texas to Crane County, Texas with 150,000 barrels per day of shipping capacity (expandable to over 200,000 barrels per day) and 490,000 barrels of storage capacity.
Results of Operations
Highlights for our Midstream segment were as follows:
Second Quarter 20172018 Significant Midstream Operating Highlights Included:
signed a definitive agreement to divest an affiliate that holdscommenced gathering services in the 50% interestMustang IDP area in CONE Gathering, LLC (CONE Gathering) for $765 million;the DJ Basin;
acquisition by Noble Midstream Partnerscompleted construction of additional midstream assetsthe Collier and Billy Miner Train II CGFs in the Delaware Basin;
secured long-term dedications, from Noble Energy for $270 million consideration, including $245 million in cashexisting and 562,430 of common units, funded with $138 million net proceeds from a concurrent private placement of common units, $90 million of borrowings and the remainder from cash on hand;
acquisition of Advantage Pipeline L.L.C. (Advantage Pipeline) for $66.5 million, net, through a newly formed 50/50 joint venture between Noble Midstream Partners and Plains Pipeline, L.P. (Plains), a wholly owned subsidiary of Plains All American Pipeline, L.P.;
commencement of fresh water delivery services to an unaffiliatednew third party customers, for the Black Diamond system, a large, integrated gathering system in the Greeley Crescent integratedDJ Basin acquired in the Saddle Butte acquisition; and
received a third party producer's activity set and development plan (IDP) area of the DJ Basin; and
record throughput volumes resulting from increased upstream development activitiesfor Delaware Basin acreage, with gathering services expected to commence in the Wells Ranch and East Pony IDP areas of the DJ Basin.late 2018.
Second Quarter 20172018 Midstream Financial Results Included:
net proceeds of approximately $135 million received, and gain of $109 million recognized, on the sale of a portion of our investment in CNX Midstream Partners common units;
pre-tax income of $58$175 million, as compared with pre-tax income of $39$58 million for second quarter 2016;2017; and
capital expenditures, excluding acquisitions, of $88$157 million, as compared with de minimis capital expenditures$88 million for second quarter 2016.2017.
Following is a summarized statement of operations for our Midstream segment:
| | | | Three Months Ended June 30, | | Six Months Ended June 30, | Three Months Ended June 30, | | Six Months Ended June 30, |
| (millions) | 2017 | | 2016 | | 2017 | | 2016 | 2018 | | 2017 | | 2018 | | 2017 |
| Midstream Services Revenues - Third Party | $ | 4 |
| | $ | — |
| | $ | 4 |
| | $ | — |
| |
Income from Equity Method Investees (1) | 13 |
| | 15 |
| | 28 |
| | 31 |
| |
| Midstream Services Revenues – Third Party | | $ | 15 |
| | $ | 4 |
| | $ | 28 |
| | $ | 4 |
|
| Sales of Purchased Oil | | 42 |
| | — |
| | 64 |
| | — |
|
| Income from Equity Method Investees | | 13 |
| | 13 |
| | 25 |
| | 28 |
|
| Intersegment Revenues | 69 |
| | 43 |
| | 127 |
| | 85 |
| 85 |
| | 69 |
| | 166 |
| | 127 |
|
| Total Revenues | 86 |
| | 58 |
| | 159 |
| | 116 |
| 155 |
| | 86 |
| | 283 |
| | 159 |
|
| Operating Costs and Expenses | 23 |
| | 14 |
| | 42 |
| | 27 |
| 27 |
| | 23 |
| | 61 |
| | 42 |
|
| Depreciation, Depletion and Amortization | 5 |
| | 5 |
| | 10 |
| | 9 |
| |
| Depreciation and Amortization | | 22 |
| | 5 |
| | 38 |
| | 10 |
|
| Gain on Divestitures | | (109 | ) | | — |
| | (305 | ) | | — |
|
| Purchased Oil | | 40 |
| | — |
| | 61 |
| | — |
|
| Total (Income) Expense | | (20 | ) | | 28 |
| | (145 | ) | | 52 |
|
| Income Before Income Taxes | 58 |
| | 39 |
| | 107 |
| | 80 |
| $ | 175 |
| | $ | 58 |
| | $ | 428 |
| | $ | 107 |
|
| |
(1)
| Includes earnings from equity method investment in the Advantage Joint Venture. |
Revenues The amount of revenue generated by the midstream business depends primarily depends on the volumes of crude oil, natural gas and water for which services are provided to the E&P business.business and third party customers. These volumes are primarily affected primarily by the level of drilling and completion activity in the areas of upstreamE&P operations and by changes in the supply of, and demand for, crude oil, natural gas and NGLs in the markets served directly or indirectly by our midstream assets.
Total revenues for second quarter and the three andfirst six months ended June 30, 2017of 2018 increased from 20162017 primarily due to the following:
an increase of $23 millionin crude oil and $41 million, respectively, driven by drillingproduced water gathering services revenue and completion activity in the Wells Ranch and East Pony IDP areas of the DJ Basin which resulted in increased services related to fresh water delivery water logistics, and additional crude oil and natural gas gathering services; and
an increase of $4 millionrevenue due to the commencement of fresh water deliveries to a third partyservices in the Greeley Crescent IDP area and Delaware Basin subsequent to second quarter 2017. In addition, fresh water delivery revenue increased due to the timing of well completion activity in the Mustang IDP area, and sales of purchased crude oil commenced in first quarter 2018 as a result of the DJ Basin;Saddle Butte acquisition.
partially offsetAs part of the Saddle Butte acquisition in first quarter 2018, we acquired a large-scale integrated gathering system (Black Diamond gathering system) and associated third party contracts which include transactions for the purchase and sale of crude oil with varying counterparties. Revenues and expenses from the sales and purchases are recorded on a gross basis as we act as a principal in these transactions by assuming control of the purchased commodity before it is transferred to the customer. The purchases and sales of crude oil are at the prevailing market prices. For second quarter and the first six months of 2018, the net effect of third party purchases and sales of crude oil was de minimis.
a decrease in income from Cone Gathering LLCOperating Costs and Cone Midstream Partners LP.
Expenses Total operating expenses for second quarter and the three andfirst six months ended June 30, 2017of 2018 increased from 20162017 primarily due to higher drillingan increase in gathering systems and completion activityfacilities operating expense associated with the the Billy Miner CGF and Jesse James CGF, which commenced operations in the Wells Ranchsecond half of 2017, along with the addition of expenses associated with the Black Diamond gathering system, acquired in the Saddle Butte acquisition in first quarter 2018.
Depreciation and East Pony IDP areasamortization expense for second quarter and the first six months of 2018 increased from 2017 due to assets placed in service subsequent to first quarter 2017, including expense related to tangible and intangible assets acquired in the DJ Basin which resultedSaddle Butte acquisition during first quarter 2018.
CORPORATE
Results of Operations – Corporate and Other
General and Administrative Expense General and administrative expense (G&A) was as follows: | | | | Three Months Ended June 30, | | Six Months Ended June 30, | Three Months Ended June 30, | | Six Months Ended June 30, |
| | 2017 | | 2016 | | 2017 | | 2016 | |
| G&A Expense (millions) | $ | 103 |
| | $ | 107 |
| | $ | 202 |
| | $ | 198 |
| |
| (millions, except unit rate) | | 2018 | | 2017 | | 2018 | | 2017 |
| G&A Expense | | $ | 105 |
| | $ | 103 |
| | $ | 209 |
| | $ | 202 |
|
Unit Rate per BOE (1) | $ | 2.82 |
| | $ | 2.79 |
| | $ | 2.88 |
| | $ | 2.62 |
| $ | 3.40 |
| | $ | 2.82 |
| | $ | 3.29 |
| | $ | 2.88 |
|
| |
(1) | Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees. |
G&A expense for second quarter and the first six months of 2017 remained flat2018 increased as compared with 2016.2017. This increase was driven by increased employee costs and third party fees in support of our development projects, partially offset by a decrease in contractor expenses. The increase in the unit rate per BOE for the first six months of 20172018 as compared with 20162017 was due primarily to the increase in total G&A expense combined with the decrease in total sales volumes.volumes due to the divestiture of the Marcellus Shale upstream assets in second quarter 2017.
Interest Expense and Capitalized Interest Interest expense and capitalized interest were as follows: | | | | Three Months Ended June 30, | | Six Months Ended June 30, | Three Months Ended June 30, | | Six Months Ended June 30, |
| (millions, except unit rate) | 2017 | | 2016 | | 2017 | | 2016 | 2018 | | 2017 | | 2018 | | 2017 |
| Interest Expense, Gross | $ | 107 |
| | $ | 102 |
| | $ | 206 |
| | $ | 209 |
| $ | 91 |
| | $ | 107 |
| | $ | 181 |
| | $ | 206 |
|
| Capitalized Interest | (11 | ) | | (24 | ) | | (23 | ) | | (52 | ) | (18 | ) | | (11 | ) | | (35 | ) | | (23 | ) |
| Interest Expense, Net | $ | 96 |
| | $ | 78 |
| | $ | 183 |
| | $ | 157 |
| $ | 73 |
| | $ | 96 |
| | $ | 146 |
| | $ | 183 |
|
Unit Rate per BOE (1) | $ | 2.63 |
| | $ | 2.04 |
| | $ | 2.61 |
| | $ | 2.07 |
| $ | 2.37 |
| | $ | 2.63 |
| | $ | 2.30 |
| | $ | 2.61 |
|
| |
(1) | Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees. |
Interest expense, gross, for second quarter and the first six months of 2017 remained relatively flat2018 decreased as compared with 2016 as2017 primarily due to a decrease in the overall debt balance. Specifically, subsequent to second quarter 2017, we repaid $550 million on our debt structure has not changed significantly.Term Loan Facility due January 6, 2019 and during the first six months of 2018, we repaid $379 million of Senior Notes due May 1, 2021. In addition, in second quarter 2017, we conducted a tender offer and subsequent redemption of our 8.25% Senior Notes, resulting in a lower interest rate and lower interest expense, gross. These were partially offset by an increase of $445 million in the amount outstanding under our Noble Midstream Services Revolving Credit Facility. See Item 1. Financial Statements - Note 6.5. Debt. The decrease in capitalizedCapitalized interest for second quarter and the first six months of 20172018 increased as compared with 2016 is2017 primarily due to lowerhigher work in progress amounts related to major long-term projects including Gunflint, Gulf of Mexico, and the Alba B3 compression project, offshore Equatorial Guinea, which were both completed in July 2016. We also impaired certain of our discoveries offshore Equatorial Guinea after an additional review of 3D seismic data was completed in fourth quarter 2016, resulting in a lower capitalized exploratory well cost balance.Leviathan development. See Item 1. Financial Statements - Note 8.7. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.The increase in the unit rate of interest expense, net, per BOE was due to the changes noted above, combined with the decrease in total sales volumes.
Income Taxes See Item 1. Financial Statements – Note 10. Income Taxes for a discussion of the change in our effective tax rate for second quarter and the first six months of 20172018 decreased as compared with 2016.2017 primarily due to the changes noted above, partially offset by the decrease in total sales volumes.LIQUIDITY AND CAPITAL RESOURCES
Capital Structure/Financing Strategy
In seeking to effectively fund and monetize our discovered hydrocarbons, we employ a capital structure and financing strategy designed to provide sufficient liquidity throughout the commodity price cycle, including the current commodity price environment.a sustained period of low prices. Specifically, we strive to retain the ability to fund long cycle, multi-year, capital intensive development projects throughout a range of scenarios, while also funding a continuing exploration program and maintaining capacity to periodically capitalize on financially attractive merger and acquisition opportunities, such as the recent Clayton Williams Energy Acquisition.opportunities. We endeavor to maintain a strong balance sheet and an investment grade debt rating in service of these objectives.
We strive to maintain a minimum liquidity level to address volatility and risk. Traditional sources of our liquidity are cash flows from operations, cash on hand, available borrowing capacity under our Revolving$4.0 billion unsecured revolving credit facility (Revolving Credit FacilityFacility) and proceeds from property divestitures.divestitures of properties. We occasionally access the capital markets to ensure adequate liquidity exists in the form of unutilized capacity under our Revolving Credit Facility or to refinance scheduled debt
maturities. We also evaluate potential strategic farm-out arrangements of our working interests for reimbursement of our capital spending. We periodically consider repatriations of foreign cash to increase our financial flexibility and fund our capital investment program. See Operating Outlook – Impact of Recent Changes in US Tax Law. Although we engagedOur portfolio transformation strategy, primarily executed during 2017, has continued into 2018, with the sales of Gulf of Mexico assets, a 7.5% working interest in significant developmentTamar, our 50% interest in CONE Gathering LLC and portfolio activitiesa portion of our investment in CNX Midstream Partners common units. As a result, our divestitures have generated cash proceeds of approximately $3.5 billion during second quarter 2017, including the Clayton Williams Energy Acquisition2017-2018 and the Marcellus Shale upstream divestiture, we ended the quarter with no amounts outstandingwere used to improve our capital structure and strengthen our liquidity profile.
We strive to fund our capital program through organic cash flows and, when needed, utilize borrowings under our Revolving Credit Facility or additional fixed-rate debt. We also maintained a debt-to-book capital ratio of 43%.
Additionally, we reduced our natural gas hedge portfolio as a result of the Marcellus Shale upstream divestiture. In this regard, we terminated, restructured or transferred to the acquirer of the Marcellus Shale upstream assets certain natural gas hedge arrangements. The impact to our consolidated financial statements was de minimis for the three and six months ended June 30, 2017.
During second quarter 2017, Noble Midstream Partners purchased additional midstream assets from Noble Energy for $270 million and expanded its business through entry into a joint venture. Funding for these transactions included a $138 million private placement of common units and $90 million of net borrowings under the Noble Midstream Services Revolving Credit Facility.
Also, during the first six months of 2017, we received $175 million in payments from foreign operations on an outstanding note payable, leaving a balance of approximately $551 million that can be repaid without additional US tax impact.
As of June 30, 2017,2018, our outstanding debt (excluding capital lease obligations) totaled $6.9$6.4 billion. While we have no near-term debt maturities, weWe may periodically seek to access the capital markets to refinance a portion of our outstanding indebtedness. In addition, we may from time to time seek to retire or purchase our outstanding senior notes through cash purchases in open market purchases, privately negotiated transactions or otherwise. Such repurchases, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be significant.
Second Quarter and Year-to-Date 2018 Highlights
During second quarter 2018, we continued to focus efforts on shareholder return initiatives, including share repurchases and dividend growth, as well as debt reduction with the following actions completed:
redemption of $379 million in outstanding senior notes;
acquisition of 1.8 million shares of Noble Energy stock, for $63 million, resulting in year to date repurchases of 4.0 million shares for $130 million, pursuant to the Board of Directors' authorized $750 million share repurchase program; and
announcement in July 2018 of an August 2018 dividend of 11 cents per common share, which continues the 10% increase over 2017.
In addition, during the first six months of 2018, we completed the following financing activities:
repaid all amounts outstanding under the Revolving Credit Facility;
extended the Revolving Credit Facility maturity date by two and a half years to March 2023;
amended the Noble Midstream Services Revolving Credit Facility to increase the capacity from $350 million to $800 million; and
extended the maturity date of the Noble Midstream Services Revolving Credit Facility by one and a half years to March 2023.
Also, during the first six months of 2018, we repatriated $404 million in payments from foreign operations on an outstanding note payable. This payment eliminates the balance on the note payable and has no US tax impact.
Available Liquidity
Information regarding cash and debt balances is shown in the table below: | | | | June 30, | | December 31, | June 30, | | December 31, |
| (millions, except percentages) | 2017 | | 2016 | 2018 | | 2017 |
Total Cash (1) | $ | 540 |
| | $ | 1,209 |
| $ | 621 |
| | $ | 713 |
|
Amount Available to be Borrowed Under Revolving Credit Facility (2) | 4,000 |
| | 4,000 |
| 4,000 |
| | 3,770 |
|
| Total Liquidity | $ | 4,540 |
| | $ | 5,209 |
| $ | 4,621 |
| | $ | 4,483 |
|
Total Debt (3) | $ | 7,236 |
| | $ | 7,114 |
| $ | 6,663 |
| | $ | 6,859 |
|
| Noble Energy Share of Equity | 9,635 |
| | 9,288 |
| 10,252 |
| | 9,936 |
|
Ratio of Debt-to-Book Capital (4) | 43 | % | | 43 | % | 39 | % | | 41 | % |
| |
(1) | As of June 30, 2017,2018, total cash included cash and cash equivalents of $20$15 million related to Noble Midstream Partners. As of December 31, 2016,2017, total cash included $18 million cash and cash equivalents of $57 million related to Noble Midstream Partners and $38 million restricted cash of $30 million related to a Delaware Basin propertythe Saddle Butte acquisition that closed in January 2017.first quarter 2018. |
| |
(2) | Excludes $160 million and $625 millionamounts available to be borrowed under the Noble Midstream Services Revolving Credit Facility and Leviathan Term Loan Facility, respectively, which are not available to Noble Energy for general corporate purposes. See discussion below. |
| |
(4) | We define our ratio of debt-to-book capital as total debt (which includes long-term debt excluding unamortized discount, the current portion of long-term debt, and short-term borrowings) divided by the sum of total debt plus Noble Energy's share of equity. |
Cash and Cash EquivalentsWe had approximately $540$621 million in cash and cash equivalents at June 30, 2017,2018, primarily denominated in US dollars and invested in money market funds and short-term deposits with major financial institutions. Approximately $462$428 million of this cash is attributable to our foreign subsidiaries. We have recorded a related deferreddo not expect to incur any significant US income tax liability on undistributedexpense with respect to future repatriation of foreign earnings of $332 million for the future additional US tax liability for the US and foreign tax rate differences, net of estimated foreign tax credits. Our cash and cash equivalents at June 30, 2017 included $20 million relating to Noble Midstream Partners.cash.
Revolving Credit Facility Facilities Noble Energy's Revolving Credit Facility of $4.0 billion matures on August 27, 2020, and the commitment is $4 billion through the maturity date. On April 24, 2017, we borrowed $1.3 billion to fund activities in connection with the Clayton Williams Energy Acquisition, including the cash portion of the acquisition consideration, redeem outstanding debt, pay associated make-whole premiums and pay related fees and expenses. We repaid all outstanding borrowings during second quarter 2017 with proceeds received from the Marcellus Shale upstream divestiture, cash on hand, and cash proceeds received from the Noble Midstream Partners asset contribution. Subsequent to second quarter 2017, we borrowed and had outstanding
2023. The Noble Midstream Services Revolving Credit Facility of $800 million also matures in 2023. These facilities are used to fund capital investment programs and acquisitions and may periodically provide amounts for working capital purposes. At June 30, 2018, no amounts were outstanding under the Revolving Credit Facility and $530 million was outstanding under the Noble Midstream Services Revolving Credit Facility, matures on September 20, 2021,leaving $4.0 billion and $270 million in remaining availability under the commitment is $350 million through the maturity date. During second quarter 2017, we drew amounts to fund acquisition activity, resulting in an outstanding balance of $190 million at June 30, 2017.respective credit facilities. See Item 1. Financial Statements – Note 6. Debt. Leviathan Term Loan Facility On February 24, 2017, we entered into a facility agreement (LeviathanThe Leviathan Term Loan Facility) providingFacility provides for a limited recourse secured term loan facility with an aggregate principal borrowing amount of up to $1.0 billion, of which $625 million is initially committed. Any loansamounts borrowed under the Leviathan Term Loan Facility will be available to fund a portion of our share of costs for the initial phase of development of the Leviathan field, offshore Israel. To support the Leviathan development program and to bring first production online by the end of 2019, we may borrow amounts under this facility in the near-term. As of June 30, 2017,2018, no amounts were drawn under this facility.
Legacy Rosetta Note Redemption In May 2018, we redeemed $379 million of Senior Notes due May 1, 2021, that we had assumed in the Rosetta Merger, for $395 million, including $11 million of accrued interest and $5 million of call premium. We fully amortized $10 million of remaining premium, and recognized a gain of $5 million for the unamortized premium.
Contractual Obligations
Subsequent Event - Noble Midstream Services Term Credit Agreement On July 31, 2018, Noble Midstream Services, LLC entered into a three year senior unsecured term loan credit facility (Noble Midstream Services Term Credit Agreement) of up to $500 million. Proceeds from the Noble Midstream Services Term Credit Agreement will be used to repay a portion of the outstanding borrowings under the Noble Midstream Services Revolving Credit Facility, pay fees and expenses in connection with the Noble Midstream Services Term Credit Agreement transactions and for working capital, capital expenditures, acquisitions and other purposes as necessary of Noble Midstream Partners and its subsidiaries. See Item 1. Financial Statements – Note 12. Commitments and Contingencies for an updated tabular presentation of non-cancelable leases and other commitments as of June 30, 2017.5. Debt. Contractual Obligations
Exploration Commitments The terms of some of our production sharing contracts, licenses or concession agreements may require us to conduct certain exploration activities, including drilling one or more exploratory wells or acquiring seismic data, within specific time periods. These obligations can extend over periods of several years, and failure to conduct such exploration activities within the prescribed periods could lead to loss of leases or exploration rights and/or penalty payments.
Leviathan Development Obligations The initial development of our Leviathan field requires substantial infrastructure and capital. Wecapital, and we have executed major equipment and installation contracts in support of our development activities in the field.activities. As of June 30, 2017,2018, we had entered into approximately $644$235 million, net, of contracts to support the remaining development of this fieldactivities and bring first production online by the end of 2019.
Continuous Development ObligationsAlthough the majority of our assets are held by production, certain of our US onshore assets, such as our Eagle Ford Shale and Delaware Basin properties, are held through continuous development obligations. As such, we plan our activities and budget accordingly to ensure that we meet any such obligations that are in line with our strategic plans. Therefore, we are contractually obligated to fund a level of development activity in these areas.areas, the amount of which could be substantial, or exercise options with land owners to extend leases. Failure to meet continuous development obligations or to exercise lease extensions may result in loss of leases.
EPIC Firm Transportation Agreement During second quarter 2018, we dedicated acreage to, and secured firm capacity with, EPIC for transport of 100 MBbl/d of crude oil from the Delaware Basin to Corpus Christi, Texas, for a 10-year period beginning at pipeline start-up.
Marcellus Shale Firm Transportation Agreements In connectionWe have remaining financial commitments of approximately $1.4 billion, undiscounted, associated with the Marcellus Shale upstream divestiture, we reduced our firm transportation financial commitments through transfer of several contracts to the acquirer.
contracts. We retained certain other firm transportation contracts representing a total financial commitment of approximately $1.6 billion, undiscounted, primarily with remaining contract terms of 15 years.
One of the retained contracts, related to Texas Eastern pipeline, will be fully utilized through an agreement with the acquirer, whereby the acquirer will deliver quantities of natural gas to us and receive a netback sales price that reflects the value received by us at the sales point, less our effective fixed transportation fees and other expenses, plus a margin. This contract represents an undiscounted financial commitment of approximately $124 million, before offset by the netback agreement, thus reducing the remaining overall commitment noted above.
Two of the retained contracts relate to the Leach & Rayne Xpress projects, which are currently under construction and targeted to be placed in service fourth quarter 2017. These contracts represent an undiscounted financial commitment of $616 million.
Two additional retained contracts relate to the WB Xpress and NEXUS projects. Although scheduled to be placed in service fourth quarter 2018, these projects have not yet been approved by the Federal Energy Regulatory Commission (FERC), and construction has not begun. These contracts represent an undiscounted financial commitment of $869 million.
We are currently engaged in actions to commercialize and addressa substantial portion of these remaining four commitments, which provide for the transportation of approximately 500,000450,000 MMBtu/dayd of natural gas. Actions include the permanent assignment of capacity, negotiation of capacity release, utilization of capacity through purchase of third party natural gas, and other potential arrangements. In addition, we have a “call” or right to purchase natural gas, priced at a regional index, from the acquirer of the Marcellus Shale upstream assets. This call extends through July 1, 2022 and may be exercised on quantities of the acquirer's production between 431,100 MMBtu/d and 832,645 MMBtu/d.
We expect these actions, some of which may require pipeline and/or FERC approval, to ultimatelycontinue to reduce theour financial commitment associated with these contracts. AtFor pipelines currently under construction and targeted for in-service late 2018, we will evaluate our position at the date each pipeline is placed in service and our commitment begins, we will evaluate our position.begins. If we determine that we will not utilize a portion, or all, of the contracted pipeline capacity, we will
accrue a liability at fair value for the net amount of the estimated remaining financial commitment. These contracts represent approximately $890 million, undiscounted, of the total $1.4 billion commitment and include the related expense in operating expense in our consolidated statements of operations.
In accordance with US GAAP, we recognize the fair value of a liability for an exit cost in the period in which a liability is incurred. As a result, as of June 30, 2017, we accrued non-cash exit costs of $41 million, discounted, relating to our transportation contract with the Gateway pipeline project. Gateway is currently in service; however, we no longer have production to satisfy this commitment and do not plan to utilize this capacity in the future. As such, we recorded a charge to expense which is included in loss on Marcellus Shale upstream divestiture in our consolidated statements of operations.
Other Delivery and Firm Transportation AgreementsWe have entered into various long-term gathering, processing and transportation contracts for some of our US onshore and offshore production, primarily in the DJ Basin and South Texas, with remaining terms of one to 11 years. We use long-term contracts such as these to provide production flow assurance and ensure access to markets for our products at the best possible price and at the lowest possible logistics cost. See Item 1. Financial Statements – Note 12. Commitments and Contingencies.Certain of these contracts require us to make payments for any shortfalls in delivering or transporting minimum volumes under the commitments. As properties are undergoing development activities, we may experience temporary shortfalls until production volumes increase to meet or exceed the minimum volume commitments.
For the first six months of 2017 and 2016, we incurred expense of approximately $33 million and $27 million, respectively, related to volume deficiencies and/or unutilized commitments primarily in our US onshore operations. These amounts are recorded as marketing expense in our consolidated statements of operations. We expect to continue to incur expense related to deficiency and/or unutilized commitments in the near-term. Should commodity prices decline or if we are unable to continue to develop our properties as planned, or certain wells become uneconomic and are shut-in, we could incur additional shortfalls in delivering or transporting the minimum volumes and we could be required to make payments in the event that these commitments are not otherwise offset. We continually seek to optimize under-utilized assets through capacity release and third-party arrangements, as well as, for example, through the shifting of transportation of production from rail cars to pipelines when we receive a higher netback price. We may continue to experience these shortfalls both in the near and long-term.
Credit Rating EventsWe do not have any triggering events on our consolidated debt that would cause a default in case of a downgrade of our credit rating. In addition, there are no existing ratings triggers in any of our commodity hedging agreements that would require the posting of collateral. However, a series of downgrades or other negative rating actions could increase our cost of financing, and may increase our requirements to post collateral as financial assurance of performance under certain other contractual arrangements such as pipeline transportation contracts, crude oil and natural gas sales contracts, work commitments and certain abandonment obligations. A requirement to post collateral could have a negative impact on our liquidity.
Cash Flows
Summary cash flow information is as follows: | | | | Six Months Ended June 30, | Six Months Ended June 30, |
| (millions) | 2017 | | 2016 | 2018 | | 2017 |
| Total Cash Provided By (Used in) | | | | | | |
| Operating Activities | $ | 877 |
| | $ | 440 |
| $ | 1,079 |
| | $ | 877 |
|
| Investing Activities | (1,091 | ) | | (51 | ) | (1,050 | ) | | (1,121 | ) |
| Financing Activities | (426 | ) | | (117 | ) | (121 | ) | | (426 | ) |
| (Decrease) Increase in Cash and Cash Equivalents | $ | (640 | ) | | $ | 272 |
| |
| Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash | | $ | (92 | ) | | $ | (670 | ) |
Operating ActivitiesNet cashCash provided by operating activities increased for the first six months of 2017 increased as2018 compared with 2016. Increases2017 by approximately $202 million. The increase is primarily due to higher realized crude oil prices and an increase in average realizedcrude oil production in the DJ and Delaware basins. In addition, changes in working capital included a significant increase in the balance of the current portion of the commodity pricesderivatives liability.
These increases were partially offset by decreaseslower realized natural gas prices, a decrease in sales volumes. Working capital changes resultednatural gas production attributable to our exit from the Marcellus Shale in a $99 million operating cash flow decrease for the first six months ofsecond quarter 2017, as compared with a $381 million operating cash flow decrease for the first six months of 2016. The changes in working capital were primarily dueand higher production costs attributable to an increase in accounts payable driven by increased operational activity partially offset by an increase in accounts receivable resulting from higher revenues.US onshore activity.
Investing Activities Our investing activities include capital spending on a cash basis for oil and gas properties and investments in unconsolidated subsidiaries accounted for by the equity method. These investing activities may be offset by proceeds from property sales or dispositions, including farm-out arrangements, which may result in reimbursement for capital spending that occurred in prior periods.
Capital spending forTotal additions to property, plant and equipment increased by $403$567 million during the first six months of 20172018 as compared with 2017 primarily due to increases in spending related to development costs in the Delaware Basin, construction of midstream infrastructure and Leviathan development costs, partially offset by decreases in development costs primarily in the Marcellus Shale and Eagle Ford Shale. See Operating Outlook – 2018 Capital Investment Program, above.During the first six months of 2016, primarily due to increased US onshore development activity2018, we completed certain portfolio activities including the Saddle Butte acquisition for $650 million, net. Also during the first six months of 2018, we received net proceeds of $1.4 billion from asset sales, including the sale of our Gulf of Mexico assets, a 7.5% interest in response to currentthe Tamar field, our 50% interest in CONE Gathering LLC and a portion of our CNX Midstream Partners common units.
commodity prices. In addition,2017, we used $637 million of cash to fund a portion of the consideration paid in the Clayton Williams Energy Acquisition and we acquired Delaware Basin assets for $301 million. We received net cash proceeds of $1.0 billion from the Marcellus Shale upstream divestiture, and other investing activities provided a net cash of $33 million of cash. During the first six months of 2016, we received net proceeds of $767 million from asset sales.million.
Financing Activities Our financing activities, in general, include debt transactions, the issuance orand repurchase of Noble Energy common stock and Noble Midstream Partners common units, payment of cash dividends to Noble Energy shareholders, and payment of cash distributions to, and receipt of cash contributions from, Noble Midstream Partners noncontrolling interest owners,owners.
Our primary financing activities during the first six months of 2018 included a $230 million, net, Revolving Credit Facility repayment and $445 million, net, Noble Midstream Services Revolving Credit Facility borrowings used primarily to fund an acquisition. We also used $384 million of cash to redeem senior notes which had accrued interest of $11 million and repaymentsis reflected within operating activities.
In addition, during the first six months of borrowings. During2018, we made common stock repurchases totaling $130 million pursuant to our stock repurchase program, paid $102 million of cash dividends to Noble Energy shareholders and $22 million of cash distributions to Noble Midstream Partners noncontrolling interest owners. We also received $331 million of contributions from noncontrolling interest owners. Other financing activities used net cash of $29 million.
In comparison, during the first six months of 2017, we borrowed and repaid $1.3 billion under our Revolving Credit Facility and borrowed a net $190 million under the Noble Midstream Services Revolving Credit Facility. We also repaid $595 million of assumed Clayton Williams Energy debt. We used cash of $92 million to pay dividends on our common stock and $12 million to pay distributions to noncontrolling interest owners.
In comparison, during the first six months We received $138 million of 2016, funds were provided bynet cash proceeds from the term loan acquisition ($1.4 billion). We used cash to pay dividends on ourissuance of Noble Midstream Partners common stock ($86 million), fund the purchase of certain of our outstanding senior notes ($1.38 billion), and make principal payments related to capital lease obligations ($27 million).units.
Investing Activities
Acquisition, Capital and Exploration Expenditures Information for investing activities (on an accrual basis) is as follows: |
| | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| (millions) | 2017 | | 2016 | | 2017 | | 2016 |
| Acquisition, Capital and Exploration Expenditures | |
| | |
| | |
| | |
|
Unproved Property Acquisition (1) | $ | 1,581 |
| | $ | — |
| | $ | 1,826 |
| | $ | — |
|
Proved Property Acquisition (2) | 782 |
| | — |
| | 840 |
| | — |
|
| Exploration | 7 |
| | 58 |
| | 17 |
| | 156 |
|
| Development | 598 |
| | 189 |
| | 1,182 |
| | 436 |
|
Midstream (3) | 152 |
| | 5 |
| | 245 |
| | 20 |
|
| Corporate and Other | 10 |
| | 10 |
| | 15 |
| | 20 |
|
| Total | $ | 3,130 |
| | $ | 262 |
| | $ | 4,125 |
| | $ | 632 |
|
Investment in Equity Method Investee (4) | $ | 67 |
| | $ | — |
| | $ | 67 |
| | $ | 6 |
|
(1) Unproved property acquisition cost for the first six months of 2017 includes $1.6 billion related to the Clayton Williams Energy Acquisition and $246 million related to the Delaware Basin asset acquisition.
(2) Proved property acquisition cost for the first six months of 2017 includes $724 million of proved properties and $59 million of asset retirement obligations acquired in the Clayton Williams Energy Acquisition and $58 million related to the Delaware Basin asset acquisition.
(3) Midstream expenditures for the first six months of 2017 include $67 million related to the Clayton Williams Energy Acquisition.
(4) Investment in equity method investee for the first six months of 2017 represents our contribution to the Advantage Joint Venture, in which Noble Midstream Partners owns a 50% interest.
Development costs increased during the first six months of 2017 as compared with 2016 as we have increased our US onshore activity in response to the current commodity price environment and focus on development of liquids-rich assets in the DJ Basin, Delaware Basin, and Eagle Ford Shale. See Operating Outlook – 2017 Capital Investment Program, above.
Financing Activities
Long-Term Debt Our principal source of liquidity is our Revolving Credit Facility that matures August 27, 2020. At June 30, 2017, we had no amount outstanding under the Revolving Credit Facility, leaving $4.0 billion available for use. On April 24, 2017, we drew $1.3 billion under our Revolving Credit Facility to fund activities in connection with the Clayton Williams Energy Acquisition, including the cash portion of the acquisition consideration, redeem outstanding debt, pay associated make-whole premiums and pay related fees and expenses. We repaid all outstanding borrowings in late June 2017 with proceeds received from the Marcellus Shale upstream divestiture, cash on hand, and cash proceeds received from the Noble Midstream Partners asset contribution.
We may rely on our Revolving Credit Facility to help fund our capital investment program, and may periodically borrow amounts for working capital purposes. See Item 1. Financial Statements – Note 6. Debt.Our outstanding fixed-rate debt (excluding capital lease obligations) totaled approximately $6.2 billion at June 30, 2017. The weighted average interest rate on fixed-rate debt was 5.69%, with maturities ranging from March 2019 to August 2097.
DividendsWe paid total cash dividends of 20 cents per share of common stock during the first six months of 2017, consistent with 20 cents per share during the first six months of 2016.
On July 25, 2017,24, 2018, our Board of Directors declared a quarterly cash dividend of 1011 cents per common share, which will be paid on August 21, 201720, 2018 to shareholders of record on August 7, 2017.6, 2018. 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.
DistributionsCapital Expenditure Activities The following presents our capital expenditures (on an accrual basis) for the second quarter and the first six months of 2018 and 2017: |
| | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| (millions) | 2018 | | 2017 | | 2018 | | 2017 |
| Acquisition, Capital and Exploration Expenditures | |
| | |
| | |
| | |
|
Unproved Property Acquisition (1) | $ | — |
| | $ | 1,581 |
| | $ | — |
| | $ | 1,826 |
|
Proved Property Acquisition (2) | — |
| | 782 |
| | — |
| | 840 |
|
| Exploration and Development | 771 |
| | 605 |
| | 1,427 |
| | 1,199 |
|
Midstream (3) | 157 |
| | 152 |
| | 616 |
| | 245 |
|
| Corporate and Other | 16 |
| | 10 |
| | 27 |
| | 15 |
|
| Total | $ | 944 |
| | $ | 3,130 |
| | $ | 2,070 |
| | $ | 4,125 |
|
Investment in Equity Method Investee (4) | $ | — |
| | $ | 67 |
| | $ | — |
| | $ | 67 |
|
(1) 2017 acquisition costs include $1.6 billion related to Noncontrolling Interest Owners Duringthe Clayton Williams Energy Acquisition and $246 million related to the Delaware Basin acquisition.
(2) 2017 acquisition costs include $724 million of proved properties and $59 million of asset retirement obligations acquired in the Clayton Williams Energy Acquisition and $58 million related to the Delaware Basin asset acquisition.
(3) Midstream expenditures for the six months ended June 30, 2018 include $206 million related to the Saddle Butte acquisition. Midstream expenditures for the first six months of 2017 distributions paidinclude $67 million related to noncontrolling interest owners totaled $12 million.the Clayton Williams Energy Acquisition.
Exercise(4) 2017 costs represent our contribution to the Advantage Joint Venture, in which Noble Midstream Partners owns a 50% interest.
Development costs for second quarter and the first six months of Stock Options We received cash proceeds of $9 million from the exercise of stock options during2018 increased as compared with second quarter and the first six months of 2017 due to increased US onshore activity and $7Leviathan development activities. Year to date development costs include approximately $1.1 billion for US onshore E&P operations and approximately $350 million duringfor Leviathan. The increase in development costs was partially offset by a decrease due to the first six months2017 Marcellus Shale divestiture. In addition, midstream capital spending, exclusive of 2016.
Common Stock Repurchases We receive sharesacquisitions, increased due to the construction of common stock from employees forgathering systems in the payment of withholding taxes due on the vesting of restricted shares issued under stock-based compensation plans. We received 986,394 shares with a value of $35 million, including 719,849 shares with a value of $25 million related to vesting of Clayton Williams Energy restricted stockDJ and options in connection with the Clayton Williams Energy Acquisition, during the first six months of 2017. We received 232,870 shares with a value of $8 million during the first six months of 2016. Delaware Basins.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES, UPDATE
The following discussion updates the policies and estimates disclosed in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies and Estimates of our Annual Report on Form 10-K for the year ended December 31, 2016.
Goodwill
As of June 30, 2017, our consolidated balance sheet included goodwill of $1.3 billion, which resulted from the excess of the purchase price over amounts assigned to assets acquired and liabilities assumed in the Clayton Williams Energy Acquisition in second quarter 2017. The goodwill was assigned to the Texas reporting unit.
Annual Goodwill Test Goodwill is not amortized to earnings but is assessed, at least annually, for impairment at the reporting unit level. Our policy is to conduct a qualitative goodwill impairment assessment by examining relevant events and circumstances which could have a negative impact on our goodwill such as: macroeconomic conditions; industry and market conditions, including commodity prices; cost factors; overall financial performance; segment dispositions and acquisitions; and other relevant entity-specific events.
If, after assessing the totality of events or circumstances described above, we determine that it is more likely than not that the fair value of our US onshore reporting unit is less than its carrying amount, the two-step goodwill test is performed. The two-step goodwill impairment test is also performed whenever events or changes in circumstances indicate that the carrying value may not be recoverable. If, after performing the two-step goodwill test, it is determined that the carrying value of goodwill is impaired, the amount of goodwill is reduced and a corresponding charge is made to earnings in the period in which the goodwill is determined to be impaired.
The two-step impairment test is used to identify potential goodwill impairment and measure the amount of a goodwill impairment loss to be recognized. The first step of the goodwill impairment test, used to identify potential impairment, compares the fair value of a reporting unit with its carrying amount, including goodwill. If the fair value of the reporting unit exceeds its carrying amount, goodwill is not considered to be impaired, and the second step of the test is not required. If necessary, the second step of the impairment test, used to measure the amount of impairment loss, compares the implied fair value of reporting unit goodwill with the carrying amount of that goodwill. If the carrying amount of reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to the excess.
The first step of the impairment test requires management to make estimates regarding the fair value of the reporting unit to which goodwill has been assigned. If it is necessary to determine the fair value of the US onshore reporting unit, we use a combination of the income approach and the market approach.
Under the income approach, the fair value of the US onshore reporting unit is estimated based on the present value of expected future cash flows. The income approach is dependent on a number of factors including estimates of forecasted revenue and operating costs and proved reserves, as well as the success of future exploration for and development of unproved reserves, discount rates and other variables. Negative revisions of estimated reserves quantities, increases in future cost estimates, divestiture of a significant component of the reporting unit, or sustained decreases in crude oil or natural gas prices could lead to a reduction in expected future cash flows and possibly an impairment of all or a portion of goodwill in future periods.
Key assumptions used in the discounted cash flow model described above include estimated quantities of crude oil, natural gas and NGL reserves, including both proved reserves and risk-adjusted unproved reserves; estimates of market prices considering forward commodity price curves as of the measurement date; and estimates of operating, administrative and capital costs adjusted for inflation. We discount the resulting future cash flows using a peer company based weighted average cost of capital.
Under the market approach, we estimate the value of the US onshore reporting unit by comparison to similar businesses whose securities are actively traded in the public market. This requires management to make certain judgments about the selection of comparable companies and/or comparable recent company and asset transactions and transaction premiums. We use a peer company multiple method for the market approach. Market multiples represent market estimates of fair value based on selected financial metrics. We use earnings before interest, taxes, DD&A and exploration expense (also known as EBITDAX) as our financial metric as we believe it more accurately compares companies using successful efforts and full cost accounting methods, both of which are in our peer group.
Although we base the fair value estimate of the US onshore reporting unit on assumptions we believe to be reasonable, those assumptions are inherently unpredictable and uncertain and actual results could differ from the estimate. In the event of a prolonged industry downturn, commodity prices may stay depressed or decline further, thereby causing the fair value of the US onshore reporting unit to decline, which could result in an impairment of goodwill.
DisposalsIf, in the future, we dispose of a reporting unit or a portion of a reporting unit that constitutes a business, we will include goodwill associated with that business in the carrying amount of the business in order to determine the gain or loss on disposal. The amount of goodwill allocated to the carrying amount of a business can significantly impact the amount of gain or
loss recognized on the sale of that business. The amount of goodwill to be included in that carrying amount will be based on the relative fair value of the business to be disposed of and the portion of the reporting unit that will be retained. We did not allocate any goodwill to the carrying amount of the Marcellus Shale upstream assets that were sold on June 28, 2017. See Item 1. Financial Statements - Note 3. Clayton Williams Energy Acquisition.Exit Costs
During second quarter 2017, in connection with our Marcellus Shale upstream divestiture, we accrued a liability of $41 million, discounted, for exit costs related to our commitment under a retained firm transportation contract, and charged the amount to loss on Marcellus Shale upstream divestiture in our consolidated statements of operations.
We have retained additional Marcellus Shale firm transportation contracts, relating to pipeline projects which are not yet commercially available to us. These projects are either under construction or have not yet been approved by the FERC. We did not accrue any exit cost liabilities related to these contracts as of June 30, 2017. See Item 1. Financial Statements – Note 12. Commitments and Contingencies.We account for exit costs in accordance with ASC 420 – Exit or Disposal Cost Obligations, which requires that a liability for a cost associated with an exit or disposal activity be recognized at fair value in the period in which the liability is incurred. Further, a liability for costs that will continue to be incurred under a contract for its remaining term without economic benefit to the entity shall be recognized at the “cease-use date”, which is defined as the date the entity ceases using the right conveyed by the contract, for example, the right to use a leased property or to receive future goods or services.
As these projects become commercially available to us, our management must make significant judgments and estimates regarding the timing and amount of recognition of any additional exit cost liabilities, taking into consideration our commercialization activities and/or the potential occurrence of a cease-use date.
Any additional exit cost liability will be initially recorded at fair value, and, in periods subsequent to initial measurement, changes to the liability, including changes resulting from revisions to either the timing or the amount of estimated cash flows over the future contract period, will be recognized as an adjustment to the liability in the period of the change. Therefore, initial recognition of a liability, as well as subsequent increases or decreases in exit cost liability estimates, could have a significant impact on our consolidated net income (loss).
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
We areexposed to market risk in the normal course of business operations, and the volatility of crude oil and natural gas prices continues to impact the oil and gas industry. See Results of Operations - RevenuesE&P, above. Derivative Instruments Held for Non-Trading Purposes Due to the volatility of crude oil and natural gas prices, we continue to use derivative instruments as a means of managing our exposure to price changes.
At June 30, 2017,2018, we had various open commodity derivative instruments related to crude oil and natural gas. Changes in fair value of commodity derivative instruments are reported in earnings in the period in which they occur. Our open commodity derivative instruments were in a net assetliability position with a fair value of $31$306 million. Based on the June 30, 20172018 published commodity futures price curves for the underlying commodities, a hypothetical price increase of 10% per Bbl for crude oil and 10% per MMBtu for natural gas would decreaseincrease the fair value of our net commodity derivative assetliability by approximately $43 million, effectively changing our net asset position to a net liability of $12$280 million. Our derivative instruments are executed under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net cash settled at the time of election. See Item 1. Financial Statements – Note 5.4. Derivative Instruments and Hedging Activities. Marcellus Shale Firm Transportation Contracts We retained certain other firm transportation contracts after the closing of the Marcellus Shale upstream divestiture. These contracts generally relate to pipelines which are currently under construction and not available for use, or pipelines for which construction has not yet begun and which are not currently approved by the FERC. Our volume commitments under these contracts total approximately 500,000 MMBtu/d.
Access to these contracts may be operationally or financially beneficial to other natural gas operators in the region. We are currently assessing various options to commercialize and address the remaining commitments, including the negotiation of capacity release, utilization of capacity through the purchase of third party natural gas and other potential arrangements. In addition, we have a “call” or right to purchase natural gas priced at a regional index from the acquirer of the Marcellus Shale upstream assets through July 1, 2022 when the acquirer's production exceeds 431,100 MMBtu/d but is less than 832,645 MMBtu/d. However, we do not have information regarding the acquirer's future development plans; therefore, there is
uncertainty regarding when or if any volumes may become available. We expect these actions, some of which may require pipeline and/or FERC approval, to ultimately reduce the financial commitment associated with these contracts.
Changes in natural gas prices, in and out of basin supply and demand, the industry's ability to export substantial natural gas volumes to areas outside of the Marcellus Shale, as well as changes in basis differentials, could impact our commercialization options. We have no control over these market factors and therefore may not realize any benefits from our commercialization efforts. As a result, and when or if required, we may recognize substantial future liabilities, at fair value, for the net amount of the estimated remaining commitments under these contracts and charges to other operating expense in future periods. See Item 1. Financial Statements – Note 12. Commitments and Contingencies.Interest Rate Risk
Changes in interest rates affect the amount of interest we pay on certain of our borrowings and the amount of interest we earn on our short-term investments.
At June 30, 2017,2018, we had approximately $6.9$6.4 billion (excluding capital lease obligations) of long-term debt outstanding, net outstanding.of unamortized discount and debt issuance costs. Of this amount, $6.2$5.8 billion was fixed-rate debt, net of unamortized discount and debt issuance costs, with a weighted average interest rate of 5.69%5.06%. Although near term changes in interest rates may affect the fair value of our fixed-rate debt, they do not expose us to interest rate risk or cash flow loss.
However, we are exposed to interest rate risk related to our interest-bearing cash and cash equivalents balances. As of June 30, 2017,2018, our cash and cash equivalents totaled $540$621 million, approximately 46% of which was invested in money market funds and short-term investments with major financial institutions.
In addition, borrowings under the Term LoanRevolving Credit Facility, and Noble Midstream Services Revolving Credit Facility and Leviathan Term Loan Facility 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. A change in the interest rate applicable to our variable-rate debt could expose us to additional interest cost. While we currently have no interest rate derivative instruments as of June 30, 2017,2018, we may invest in such instruments in the future in order to mitigate interest rate risk. A change in the interest rate applicable to our short-term investments Term Loan Facility or the amount currentlyamounts, if any, outstanding under the Noble Revolving Credit Facility, Noble Midstream Services Revolving Credit Facility or Leviathan Term Loan Facility would have a de minimis impact. See Item 1. Financial Statements – Note 5. Debt. Foreign Currency Risk
The US dollar is considered the functional currency for each of our international operations. Substantially all of our international crude oil, natural gas and NGL production is sold pursuant to US dollar denominated contracts. Transactions, such as operating costs and administrative expenses that are paid in a foreign currency, are remeasured into US dollars and recorded in the financial statements at prevailing currency exchange rates. Certain monetary assets and liabilities, such as taxes payablefor example certain local working capital items, are denominated in a foreign tax jurisdictions, are settled in the foreign local currency.currency and remeasured into US dollars. A reduction in the value of the US dollar against currencies of other countries in which we have material operations could result in the use of additional cash to settle operating, administrative and tax liabilities. Furthermore, our investment in Tamar Petroleum is denominated and settled in New Israeli Shekels.
Net transaction gains and losses were de minimis for the threesecond quarter and the first six months ended June 30, 2017 and 2016.of 2018.
We currently have no foreign currency derivative instruments outstanding. However, we may enter into foreign currency derivative instruments (such as forward contracts, costless collars or swap agreements) in the future if we determine that it is necessary to invest in such instruments in order to mitigate our foreign currency exchange 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, development and acquisitions activities;
our ability to satisfy contractual commitments, including utilization or commercialization of firm transportation commitments in the Marcellus Shale;
our ability to make and integrate acquisitions;
our ability to successfully and economically explore for and develop crude oil, natural gas and NGL resources;
anticipated trends in our business;
market conditions in the oil and gas industry;
the impact of governmental fiscal regulation, including federal, state, local, and foreign host regulations, and/or terms, such as those involving the protection of the environment or marketing of production, as well as other regulations; and
access to resources.
Any such projections or statements reflect Noble Energy’s views (as of the date such projects were published or such statements were made) about future events and financial performance. No assurances can be given that such events or performance will occur as projected, and actual results may differ materially from those projected. Important factors that could cause the actual results to differ materially from those projected include, without limitation, the volatility in commodity prices for crude oil and natural gas, the presence or recoverability of estimated reserves, the ability to replace reserves, environmental risks, drilling and operating risks, exploration and development risks, information technology and security risks, competition, government regulation or other action, the ability of management to execute its plans to meet its goals and other risks inherent in Noble Energy’s business that are detailed in its Securities and Exchange Commission filings.
Forward-looking statements are typically identified by use of terms such as “may,” “will,” “expect,” “believe,” “anticipate,” “estimate,” “intend,” and similar words, although some forward-looking statements may be expressed differently. These forward-looking statements are made based upon our current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements. You should consider carefully the statements under Item 1A. Risk Factors included in our Annual Report on Form 10-K for the year ended December 31, 20162017 and in this quarterly report on Form 10-Q, 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, 20162017 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 12. 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, 2016.2017. Item 1A. Risk Factors
There have been no material changes from the risk factors disclosed in Item 1A. Risk Factors of our Annual Report on Form 10-K for the year ended December 31, 2016.2017.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
The following table sets forth, for the periods indicated, our share repurchase activity: |
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| Period | Total Number of Shares Purchased (1) | | Average Price Paid Per Share | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs |
| | | | | | | | (in thousands) |
4/1/2017 - 4/30/2017 (2) | 721,724 |
| | $ | 34.19 |
| | — |
| | — |
|
| 5/1/2017 - 5/31/2017 | 2,714 |
| | 31.02 |
| | — |
| | — |
|
| 6/1/2017 - 6/30/2017 | 1,810 |
| | 29.41 |
| | — |
| | — |
|
| Total | 726,248 |
| | $ | 34.19 |
| | — |
| | — |
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| | | | | | | | | | | | | |
| 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) |
| 4/1/2018 - 4/30/2018 | 216 |
| | $ | 31.72 |
| | — |
| | |
| 5/1/2018 - 5/31/2018 | 837,995 |
| | 32.84 |
| | 837,418 |
| | |
| 6/1/2018 - 6/30/2018 | 941,779 |
| | 35.65 |
| | 941,502 |
| | |
| Total | 1,779,990 |
| | $ | 34.33 |
| | 1,778,920 |
| | $ | 620 |
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(1) | StockIncludes stock repurchases of 1,070 during the period relatedrelating 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. |
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(2) | Includes 719,849During second quarter 2018, we repurchased and retired 1.8 million shares relatedof common stock at an average purchase price of $35.15 per share pursuant to the payment$750 million share repurchase program, authorized by our Board of withholding taxes due by Clayton Williams Energy shareholders upon vesting of restricted stock and options in connection with the Clayton Williams Energy Acquisition.Directors, which expires December 31, 2020. |
Item 3. Defaults Upon Senior Securities
None.
Item 4. Mine Safety Disclosures
Not applicable.
Item 5. Other Information
None.
The information required by this Part II. Item 6 is set forth in the Index to Exhibits accompanying this quarterly report on Form 10-Q and is incorporated by reference into this Part II. Item 6.
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| Exhibit Number | | Exhibit* |
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| 2.1 | | Agreement and Plan of Merger, dated as of January 13, 2017, by and among Noble Energy, Inc., Wild West Merger Sub Inc., NBL Permian LLC, and Clayton Williams Energy, Inc. (filed as Exhibit 2.1 to the Registrant’s Current Report on Form 8-K (Date of Report: January 13, 2017) filed on January 17, 2017 and incorporated herein by reference). |
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| 2.2 | | |
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| 2.3 | | |
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| 3.1 | | |
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| 3.2 | | |
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| 3.3 | | |
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| 3.4 | | |
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| 10.1* | | |
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| 12.1 | | |
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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.INS | | Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. |
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| 101.SCH | | XBRL Schema Document |
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| 101.CAL | | XBRL Calculation Linkbase Document |
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| 101.LAB | | XBRL Label Linkbase Document |
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| 101.PRE | | XBRL Presentation Linkbase Document |
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| 101.DEF | | XBRL Definition Linkbase Document |
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| * | Management contract or compensatory plan or arrangement required to be filed as an exhibit hereto.
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| ** | Copies of exhibits will be furnished upon prepayment of 25 cents per page. Requests should be addressed to the Executive Vice President and Chief Financial Officer, Noble Energy, Inc., 1001 Noble Energy Way, Houston, Texas 77070. |
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 | | August 3, 20172018 | | /s/ Kenneth M. Fisher |
| | | | | Kenneth M. Fisher Executive Vice President, Chief Financial Officer |
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Exhibit Number | | Exhibit** |
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2.1 | | Agreement and Plan of Merger, dated as of January 13, 2017, by and among Noble Energy, Inc., Wild West Merger Sub Inc., NBL Permian LLC, and Clayton Williams Energy, Inc. (filed as Exhibit 2.1 to the Registrant’s Current Report on Form 8-K (Date of Report: January 13, 2017) filed on January 17, 2017 and incorporated herein by reference). |
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2.2 | | |
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2.3 | | |
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2.4 | |
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2.5 | | |
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3.1 | | |
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3.2 | | |
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3.3 | | |
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3.4 | |
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12.1 | | |
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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.INS | | XBRL Instance Document |
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101.SCH | | XBRL Schema Document |
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101.CAL | | XBRL Calculation Linkbase Document |
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101.LAB | | XBRL Label Linkbase Document |
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101.PRE | | XBRL Presentation Linkbase Document |
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101.DEF | | XBRL Definition Linkbase Document |
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** | Copies of exhibits will be furnished upon prepayment of 25 cents per page. Requests should be addressed to the Executive Vice President and Chief Financial Officer, Noble Energy, Inc., 1001 Noble Energy Way, Houston, Texas 77070. |
