Cover Page
Cover Page - USD ($) $ in Billions | 12 Months Ended | |
Dec. 31, 2019 | Jun. 30, 2019 | |
Cover page. | ||
Document Type | 10-K | |
Document Annual Report | true | |
Document Period End Date | Dec. 31, 2019 | |
Document Transition Report | false | |
Entity File Number | 001-07964 | |
Entity Registrant Name | NOBLE ENERGY, INC. | |
Entity Incorporation, State or Country Code | DE | |
Entity Tax Identification Number | 73-0785597 | |
Entity Address, Address Line One | 1001 Noble Energy Way | |
Entity Address, City or Town | Houston, | |
Entity Address, State or Province | TX | |
Entity Address, Postal Zip Code | 77070 | |
City Area Code | (281) | |
Local Phone Number | 872-3100 | |
Title of 12(b) Security | Common Stock, $0.01 par value | |
Trading Symbol | NBL | |
Security Exchange Name | NASDAQ | |
Entity Well-known Seasoned Issuer | Yes | |
Entity Voluntary Filers | No | |
Entity Current Reporting Status | Yes | |
Entity Interactive Data Current | Yes | |
Entity Filer Category | Large Accelerated Filer | |
Entity Small Business | false | |
Entity Emerging Growth Company | false | |
Entity Shell Company | false | |
Entity Public Float | $ 10.7 | |
Entity Common Stock, Shares Outstanding | 478,509,368 | |
Documents Incorporated by Reference | Portions of the Registrant’s definitive proxy statement for the 2020 Annual Meeting of Shareholders to be held on April 28, 2020, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2019 , are incorporated by reference into Part III. | |
Entity Central Index Key | 0000072207 | |
Current Fiscal Year End Date | --12-31 | |
Document Fiscal Year Focus | 2019 | |
Document Fiscal Period Focus | FY | |
Amendment Flag | false |
Consolidated Statements of Oper
Consolidated Statements of Operations and Comprehensive (Loss) Income - USD ($) shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Revenues | |||
Total | $ 4,438 | $ 4,986 | $ 4,256 |
Costs and Expenses | |||
Production Expense | 1,137 | 1,197 | 1,141 |
Exploration Expense | 202 | 129 | 188 |
Depreciation, Depletion and Amortization | 2,197 | 1,934 | 2,053 |
General and Administrative | 416 | 385 | 415 |
Cost of Purchased Oil and Gas | 431 | 296 | 0 |
Gain on Divestitures, Net | 0 | (843) | (326) |
Asset Impairments | 1,160 | 206 | 70 |
Goodwill Impairment | 0 | 1,281 | 0 |
Loss on Marcellus Shale Upstream Divestiture and Other | 0 | 0 | 2,379 |
Other Operating Expense, Net | 214 | 50 | 138 |
Total | 5,757 | 4,635 | 6,058 |
Operating (Loss) Income | (1,319) | 351 | (1,802) |
Other Expense | |||
Loss (Gain) on Commodity Derivative Instruments | 143 | (63) | (63) |
Loss on Extinguishment of Debt or Facility | 44 | 8 | 98 |
Interest, Net of Amount Capitalized | 260 | 282 | 354 |
Other Non-Operating Expense (Income), Net | 10 | (16) | 0 |
Total | 457 | 211 | 389 |
(Loss) Income Before Income Taxes | (1,776) | 140 | (2,191) |
Income Tax (Benefit) Expense | (343) | 126 | (1,141) |
Net (Loss) Income and Comprehensive (Loss) Income Including Noncontrolling Interests | (1,433) | 14 | (1,050) |
Less: Net Income and Comprehensive Income Attributable to Noncontrolling Interests | 79 | 80 | 68 |
Net Loss and Comprehensive Loss Attributable to Noble Energy | $ (1,512) | $ (66) | $ (1,118) |
Loss Attributable to Noble Energy per Common Share | |||
Basic and Diluted (in usd per share) | $ (3.16) | $ (0.14) | $ (2.38) |
Weighted Average Number of Shares Outstanding | |||
Basic and Diluted (in shares) | 478 | 483 | 469 |
Oil, NGL and Gas Sales | |||
Revenues | |||
Total | $ 3,904 | $ 4,461 | $ 4,060 |
Sales of Purchased Oil and Gas | |||
Revenues | |||
Total | 389 | 275 | 0 |
Costs and Expenses | |||
Cost of Purchased Oil and Gas | 85 | 108 | 0 |
Other Revenue | |||
Revenues | |||
Total | $ 145 | $ 250 | $ 196 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Current Assets | ||
Cash and Cash Equivalents | $ 484 | $ 716 |
Accounts Receivable, Net | 730 | 616 |
Other Current Assets | 148 | 418 |
Total Current Assets | 1,362 | 1,750 |
Property, Plant and Equipment | ||
Oil and Gas Properties (Successful Efforts Method of Accounting) | 30,404 | 29,002 |
Property, Plant and Equipment, Other | 1,083 | 891 |
Total Property, Plant and Equipment, Gross | 31,487 | |
Total Property, Plant and Equipment, Gross | 29,893 | |
Accumulated Depreciation, Depletion and Amortization | (14,036) | |
Accumulated Depreciation, Depletion and Amortization | (11,474) | |
Total Property, Plant and Equipment, Net | 17,451 | |
Total Property, Plant and Equipment, Net | 18,419 | |
Other Noncurrent Assets | 1,834 | 841 |
Total Assets | 20,647 | 21,010 |
Current Liabilities | ||
Accounts Payable - Trade | 1,250 | 1,207 |
Other Current Liabilities | 719 | 519 |
Total Current Liabilities | 1,969 | 1,726 |
Long-Term Debt | 7,477 | 6,574 |
Deferred Income Taxes | 662 | 1,061 |
Other Noncurrent Liabilities | 1,378 | 1,165 |
Total Liabilities | 11,486 | 10,526 |
Commitments and Contingencies | ||
Mezzanine Equity | ||
Redeemable Noncontrolling Interest, Net | 106 | 0 |
Shareholders’ Equity | ||
Preferred Stock - Par Value $1.00 per share; 4 Million Shares Authorized; None Issued | 0 | 0 |
Common Stock - Par Value $0.01 per share; 1 Billion Shares Authorized; 522 Million and 520 Million Shares Issued, respectively | 5 | 5 |
Additional Paid in Capital | 8,927 | 8,203 |
Accumulated Other Comprehensive Loss | (31) | (32) |
Treasury Stock, at Cost; 39 Million Shares | (732) | (730) |
Retained Earnings | 241 | 1,980 |
Noble Energy Share of Equity | 8,410 | 9,426 |
Noncontrolling Interests | 645 | 1,058 |
Total Shareholders' Equity | 9,055 | 10,484 |
Total Liabilities, Mezzanine Equity and Shareholders' Equity | $ 20,647 | $ 21,010 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Dec. 31, 2019 | Dec. 31, 2018 |
Statement of Financial Position [Abstract] | ||
Preferred Stock, par value per share (in dollars per share) | $ 1 | $ 1 |
Preferred Stock, shares authorized (in shares) | 4,000,000 | 4,000,000 |
Preferred Stock, shares issued (in shares) | 0 | 0 |
Common Stock, par value per share (in dollars per share) | $ 0.01 | $ 0.01 |
Common Stock, shares authorized (in shares) | 1,000,000,000 | 1,000,000,000 |
Common Stock, shares issued (in shares) | 522,000,000 | 520,000,000 |
Treasury Stock (in shares) | 39,000,000 | 39,000,000 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Cash Flows From Operating Activities | |||
Net (Loss) Income Including Noncontrolling Interests | $ (1,433) | $ 14 | $ (1,050) |
Adjustments to Reconcile Net (Loss) Income to Net Cash Provided by Operating Activities | |||
Depreciation, Depletion and Amortization | 2,197 | 1,934 | 2,053 |
Loss on Marcellus Shale Upstream Divestiture and Other | 0 | 0 | 2,379 |
Gain on Divestitures, Net | 0 | (843) | (326) |
Asset Impairments | 1,160 | 206 | 70 |
Goodwill Impairment | 0 | 1,281 | 0 |
Deferred Income Tax Benefit | (434) | (70) | (1,227) |
Loss on Extinguishment of Debt or Facility | 44 | 4 | 98 |
Loss (Gain) on Commodity Derivative Instruments | 143 | (63) | (63) |
Net Cash Received (Paid) in Settlement of Commodity Derivative Instruments | 32 | (161) | 13 |
Stock Based Compensation | 68 | 62 | 104 |
Firm Transportation Exit Cost | 88 | 0 | 0 |
Noncash Exploration Expense | 100 | 2 | 71 |
Other Adjustments for Noncash Items Included in Net (Loss) Income | 98 | 17 | (21) |
Changes in Operating Assets and Liabilities | |||
(Increase) Decrease in Accounts Receivable | (6) | 156 | (171) |
Increase (Decrease) in Accounts Payable | 9 | (63) | 248 |
Other Current Assets and Liabilities, Net | 94 | (14) | (107) |
Other Operating Assets and Liabilities, Net | (162) | (126) | (120) |
Net Cash Provided by Operating Activities | 1,998 | 2,336 | 1,951 |
Cash Flows From Investing Activities | |||
Additions to Property, Plant and Equipment | (2,524) | (3,279) | (2,649) |
Acquisitions, Net of Cash Received | 0 | (653) | (954) |
Additions to Equity Method Investments | (799) | 0 | (68) |
Net Proceeds from Divestitures | 173 | 1,999 | 2,073 |
Other | 12 | 2 | (19) |
Net Cash Used in Investing Activities | (3,138) | (1,931) | (1,617) |
Cash Flows From Financing Activities | |||
Proceeds from Revolving Credit Facility | 50 | 1,580 | 1,585 |
Repayment of Revolving Credit Facility | (50) | (1,810) | (1,355) |
Repayment of Term Loan Facility | 0 | 0 | (550) |
Repayment of Noble Midstream Services Revolving Credit Facility | (755) | (802) | (240) |
Repayment of Senior Notes | (1,053) | (384) | (1,114) |
Repayment of Clayton Williams Energy Long-term Debt | 0 | 0 | (595) |
Proceeds from Issuance of Senior Notes | 1,000 | 0 | 1,086 |
Dividends Paid, Common Stock | (227) | (208) | (190) |
Purchase and Retirement of Common Stock | 0 | (295) | 0 |
Proceeds from Issuance of Mezzanine Equity, Net of Offering Costs | 97 | 0 | 0 |
Issuance of Noble Midstream Partners Common Units, Net of Offering Costs | 243 | 0 | 312 |
Contributions from Noncontrolling Interest Owners | 37 | 353 | 19 |
Other | (127) | (110) | (114) |
Net Cash Used in Financing Activities | 905 | (399) | (831) |
(Decrease) Increase in Cash, Cash Equivalents, and Restricted Cash | (235) | 6 | (497) |
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | 719 | 713 | 1,210 |
Cash, Cash Equivalents, and Restricted Cash at End of Period | 484 | 719 | 713 |
Revolving Credit Facility | |||
Cash Flows From Financing Activities | |||
Proceeds from Credit Facility | 1,290 | 777 | 325 |
Term Loan Facility | |||
Cash Flows From Financing Activities | |||
Proceeds from Credit Facility | $ 400 | $ 500 | $ 0 |
Consolidated Statements of Shar
Consolidated Statements of Shareholders' Equity - USD ($) $ in Millions | Total | Common Stock | Additional Paid in Capital | Accumulated Other Comprehensive Loss | Treasury Stock at Cost | Retained Earnings | Non-controlling Interests |
Beginning Balance at Dec. 31, 2016 | $ 9,600 | $ 5 | $ 6,450 | $ (31) | $ (692) | $ 3,556 | $ 312 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Net (Loss) Income | (1,050) | (1,118) | 68 | ||||
Clayton Williams Energy Acquisition | 1,851 | 1,876 | (25) | ||||
Stock-based Compensation | 100 | 100 | |||||
Exercise of Stock Options | 10 | 10 | |||||
Dividends | (190) | (190) | |||||
Issuance of Noble Midstream Partners Common Units, Net of Offering Costs | 312 | 312 | |||||
Distributions to Noncontrolling Interest Owners | (28) | (28) | |||||
Other | 14 | 2 | 1 | (8) | 19 | ||
Ending Balance at Dec. 31, 2017 | 10,619 | 5 | 8,438 | (30) | (725) | 2,248 | 683 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Net (Loss) Income | 14 | (66) | 80 | ||||
Stock-based Compensation | 78 | 78 | |||||
Dividends | (208) | (208) | |||||
Purchase and Retirement of Common Stock | (295) | (295) | |||||
Clayton Williams Energy Acquisition | (25) | (25) | |||||
Contributions from Noncontrolling Interest Owners | 353 | 353 | |||||
Distributions to Noncontrolling Interest Owners | (51) | (51) | |||||
Other | (1) | 7 | (2) | (5) | 6 | (7) | |
Ending Balance at Dec. 31, 2018 | 10,484 | 5 | 8,203 | (32) | (730) | 1,980 | 1,058 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Net (Loss) Income | (1,433) | (1,512) | 79 | ||||
Stock-based Compensation | 76 | 76 | |||||
Dividends | (227) | (227) | |||||
Issuance of Noble Midstream Partners Common Units, Net of Offering Costs | 210 | 110 | 100 | ||||
Subsidiary Equity Transaction | 0 | 538 | (538) | ||||
Contributions from Noncontrolling Interest Owners | 37 | 37 | |||||
Distributions to Noncontrolling Interest Owners | (74) | (74) | |||||
Other | (18) | 1 | (2) | (17) | |||
Ending Balance at Dec. 31, 2019 | $ 9,055 | $ 5 | $ 8,927 | $ (31) | $ (732) | $ 241 | $ 645 |
Consolidated Statements of Sh_2
Consolidated Statements of Shareholders' Equity (Parenthetical) - $ / shares | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Statement of Stockholders' Equity [Abstract] | |||
Cash Dividends per share (in dollars per share) | $ 0.47 | $ 0.43 | $ 0.40 |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2019 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | 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 (until April 2018); Eastern Mediterranean; and West Africa. Our Midstream segment develops, owns, operates and acquires domestic midstream infrastructure assets, or invests in other midstream entities, with current focus areas being the DJ and Delaware Basins. Note 1. Summary of Significant Accounting Policies Basis of Presentation and Consolidation We use accounting policies that conform to US GAAP. Our consolidated accounts include our accounts and the accounts of our wholly-owned subsidiaries. Intercompany balances and transactions have been eliminated upon consolidation. For the periods presented, net income or loss is materially consistent with comprehensive income or loss. Certain prior-period amounts have been reclassified to conform to the current period presentation. Segment Information Accounting policies are consistent across geographical segments. Transfers between segments are accounted for at market value. See Note 3. Segment Information . Noble Midstream Partners Noble Energy has determined that the partners with equity at risk in Noble Midstream Partners LP (Noble Midstream Partners, Nasdaq: NBLX) lack the authority, through voting rights or similar rights, to direct the activities that most significantly impact Noble Midstream Partners' economic performance; therefore, Noble Midstream Partners is considered a variable interest entity (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. Noncontrolling Interests Our consolidated financial statements include both noncontrolling interests and a redeemable noncontrolling interest. The noncontrolling interests represent the public's ownership in Noble Midstream Partners and third-party ownership in Noble Midstream Partners' consolidated non-wholly owned subsidiaries. The redeemable noncontrolling interest represents third-party preferred equity secured by Noble Midstream Partners in March 2019. The entire equity commitment totals $200 million , of which $100 million was funded and the remaining $100 million is available for a one year period, subject to certain conditions precedent. The preferred equity is perpetual and has a 6.5% annual dividend rate. Noble Midstream Partners can redeem the preferred equity in whole or in part at any time for cash at a predetermined redemption price. The preferred equity partner can request redemption at a pre-determined base return following the later of the sixth anniversary of the preferred equity closing or the fifth anniversary of the completion date of the EPIC Crude Oil Pipeline (defined below). As the preferred equity partner’s redemption right is outside of Noble Midstream Partners’ control, the preferred equity is not considered to be a component of shareholders' equity and, therefore, is reported as mezzanine equity. In addition, because the preferred equity is held by a third-party, it is considered a redeemable noncontrolling interest. We accrete changes in the preferred equity redemption value from the issuance date to the earliest redemption date and offset the accretion against additional paid in capital. See Note 4. Acquisitions and Divestitures . Equity Method of Accounting We use the equity method of accounting for investments in entities that we do not control but over which we exert significant influence. For certain entities, we serve as the operator and exert significant influence over the day-to-day operations. For other entities, we do not serve as the operator; however, our voting position on management committees or the board of directors allows us to exert significant influence over decisions regarding capital investments, budgets, turnarounds, maintenance, monetization decisions and other project matters. We consider these equity method investments essential components of our business as well as necessary and integral elements of our value chain in support of ongoing upstream operations. In order to reflect the economics associated with our integrated upstream value chain, we include income from equity method investments as a component of revenues in our consolidated statements of operations. See Note 5. Equity Method Investments . Use of Estimates The preparation of consolidated financial statements in conformity with US GAAP requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Estimated quantities of crude oil, NGL and natural gas reserves are the most significant of our estimates. See Supplemental Oil and Gas Information (Unaudited) . Other items subject to estimates and assumptions include the carrying amounts of inventory, property, plant and equipment, equity method investments, goodwill, intangible assets, exit cost liabilities and AROs, valuation allowances for receivables and deferred income tax assets, valuation of derivative instruments, and fair values, among others. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. Declines in commodity prices, or other events, could result in a reduction in our fair value estimates and cause us to perform analyses to determine if our oil and gas properties, or other long-lived assets, are impaired. As future commodity prices cannot be determined accurately, actual results could differ significantly from our estimates. Fair Value Measurements Certain assets and liabilities are measured at fair value on a recurring basis on our consolidated balance sheets. Other assets and liabilities are measured at fair value on a nonrecurring basis. Fair value measurements are based on a hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three levels. The fair value hierarchy is as follows: • Level 1 measurements are fair value measurements which use quoted market prices (unadjusted) in active markets for identical assets or liabilities. • 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. • Level 3 measurements are fair value measurements which use unobservable inputs. The fair value hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. We use Level 1 inputs when available, as Level 1 inputs generally provide the most reliable evidence of fair value. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-term nature or maturity of the instruments. Cash and Cash Equivalents For purposes of reporting cash flows, cash and cash equivalents include unrestricted cash on hand and investments with original maturities of three months or less at the time of purchase. Accounts Receivable and Allowance for Expected Credit Losses Our accounts receivable result primarily from sales of crude oil, NGL and natural gas production and joint interest billings to our partners for their share of expenses on joint venture projects for which we are the operator. The majority of these receivables have payment terms of 30 days or less . Our accounts receivable reflects broad national and international customer base, which limits our exposure to concentrations of credit risk. We continually monitor the creditworthiness of the counterparties and have obtained credit enhancements from some parties in the form of parental guarantees or letters of credit. At the end of each reporting period, we assess the recoverability of all material receivables using historical data, current market conditions, and reasonable and supportable forecasts of future economic conditions to determine their expected collectibility. The loss given default method is used when, based on management's judgment, an allowance for expected credit losses should be accrued on a material receivable to reflect the net amount expected to be collected. See “Recently Adopted Accounting Standards” below for discussion on our early adoption of Accounting Standards Update No. 2016-13 (ASU 2016-13): Financial Instruments – Credit Losses. See Note 2. Additional Financial Statement Information . Property, Plant and Equipment Significant accounting policies for our property, plant and equipment are as follows: Oil and Gas Properties (Successful Efforts Method of Accounting) We account for crude oil and natural gas properties under the successful efforts method of accounting. Under this method, costs to acquire mineral interests in crude oil and natural gas properties, drill and equip exploratory wells that find proved reserves, and drill and equip development wells are capitalized. Capitalized costs of producing crude oil and natural gas properties, along with support equipment and facilities, are depleted using the unit-of-production method based on proved crude oil, NGL and natural gas reserves on a field-by-field basis, as estimated by our qualified petroleum engineers. Costs of certain gathering facilities or processing plants serving a number of properties or used for third-party processing are depreciated using the straight-line method over the useful lives of the assets ranging from three to thirty years . Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A is eliminated and we either adjust the basis of the respective asset or recognize a gain or loss. Costs related to repair and maintenance activities are expensed as incurred. Proved Property Impairment For our proved properties, we routinely assess whether impairment indicators exist and have processes in place to ensure that we become aware of such indicators. Impairment indicators include, but are not limited to, sustained decreases in commodity prices, negative revisions of proved reserves, and increases in development or operating costs. We conduct an impairment test in the event impairment indicators exist. Under such test, we estimate future net cash flows expected in connection with the property and compare such future net cash flows to the carrying amount of the property to determine if the carrying amount is recoverable. Other long-lived assets, such as our midstream assets, are evaluated in a manner consistent with our policy for proved property. When the carrying amount of the proved property exceeds its estimated undiscounted future net cash flows, an impairment is indicated and the fair value of the asset is then estimated. Fair value inputs, which are level 3 on the fair value hierarchy, may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future net cash flows are based on management’s expectations for the future and include estimates of future crude oil and natural gas production, commodity prices based on published forward commodity price curves or contract prices as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate. In the event of an impairment, the carrying amount of the proved property is reduced to estimated fair value. See Note 10. Impairments . Unproved Property Our unproved properties consist of leasehold costs and allocated value to probable and possible reserves resulting from acquisitions. Undeveloped leasehold costs are derived from allocated fair values as a result of business combinations or other purchases of unproved properties and are subject to impairment testing. 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. We assess individually significant unproved properties for impairment on a quarterly basis and recognize a loss at the time of impairment. In determining whether a significant unproved property is impaired, we consider numerous factors including, but not limited to, current exploration plans, favorable or unfavorable exploration activity on the property being evaluated and/or adjacent properties, our geologists' evaluation of the property, and the remaining months in the lease term for the property. When we have allocated fair value to an unproved property as the result of a transaction accounted for as a business combination, we use a future net cash flow analysis to assess the unproved property for impairment. Cash flows used in the impairment analysis are determined based on management’s estimates of crude oil, NGL and natural gas reserves, future commodity prices and future costs to produce the reserves. Reserves volumes are reduced by risk adjustments applied to probable and possible reserves. See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs . Properties Acquired in Business Combinations When sufficient market data is not available, we determine the fair values of proved and unproved oil and gas properties acquired in transactions accounted for as business combinations by preparing estimates of cash flows from the production of crude oil, NGL and natural gas reserves. We estimate future prices to apply to the estimated reserves quantities acquired, and estimate future operating and development costs, to arrive at estimates of future net cash flows. For the fair value assigned to proved reserves, future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the business combination. When estimating and valuing unproved reserves, discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors. For other assets acquired in business combinations, we use a combination of available cost and market data and/or estimated cash flows to determine the fair values. Assets Held for Sale At the end of each reporting period, we evaluate properties being marketed for sale to determine whether any should be reclassified as held for sale. If the held-for-sale criteria are met, the property is reclassified as held for sale on our consolidated balance sheets and valued at the lower of net book value or anticipated sales proceeds less costs to sell. Impairment expense is recorded for any excess of net book value over anticipated sales proceeds less costs to sell. Exploration Costs Geological and geophysical costs, delay rentals, amortization of unproved leasehold costs, and costs to drill exploratory wells that do not find proved reserves are expensed as oil and gas exploration. We carry the costs of an exploratory well as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as we are making sufficient progress assessing the reserves and the economic and operating viability of the project. For certain capital-intensive international projects, it may take us more than one year to evaluate the future potential of the exploratory well and make a determination of its economic viability. Our ability to move forward on a project may be dependent on gaining access to transportation or processing facilities or obtaining permits and government or partner approval, the timing of which is beyond our control. In such cases, exploratory well costs remain suspended as long as we are actively pursuing access to necessary facilities, permits and approvals and we believe they will be obtained. We assess the status of suspended exploratory well costs on a quarterly basis. See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs . Property, Plant and Equipment, Other Other property includes automobiles, trucks, an airplane, office furniture, computer equipment, buildings, leasehold improvements and other fixed assets. These items are recorded at cost and are depreciated using the straight-line method based on expected lives of the individual assets or group of assets, ranging from three to thirty years . Other property also includes linefill, which is recorded at cost to produce into the production line. Linefill is not subject to depreciation but is reviewed for impairment. Capitalization of Interest We capitalize interest costs associated with the development and construction of significant properties or projects to bring them to a condition and location necessary for their intended use, which for crude oil and natural gas assets is at first production from the field. Interest is capitalized using an interest rate equivalent to the weighted average interest rate we pay on long-term debt, including our unsecured revolving credit facilities, term loan credit facilities and Senior Notes. Capitalized interest is included in the cost of oil and gas assets and is amortized with other costs on a unit-of-production basis. Asset Retirement Obligations Asset retirement obligations (AROs) consist of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. We recognize the fair value of a liability for an ARO in the period in which we have an existing legal obligation associated with the retirement that can reasonably be estimated. The associated asset retirement cost is capitalized as part of the carrying value of the oil and gas asset. The asset retirement cost is recorded at estimated fair value, measured by the expected future cash outflows required to satisfy the obligation discounted at our credit-adjusted risk-free rate. After initial recording, the liability is increased for the passage of time, with the increase being reflected as accretion expense included in DD&A expense in the consolidated statements of operations. Subsequent adjustments in the cost estimate are reflected in the liability and the amounts continue to be amortized over the useful life of the related long-lived asset. See Note 7. Asset Retirement Obligations . Intangible Assets Intangible assets consist of customer contracts and relationships that were recorded at their estimated fair values at the date of acquisition. Amortization is calculated using the straight-line method, which reflects the pattern in which the estimated economic benefit is expected to be received over the estimated useful life of the intangible assets, which is currently over periods of seven to 13 years. As of December 31, 2019 , the net book value of our intangible assets was $ 278 million, net of accumulated amortization of $62 million . Intangible assets with finite useful lives are reviewed for impairment when events or changes in circumstances indicate that the carrying amounts of such assets may not be recoverable. See Note 4. Acquisitions and Divestitures . Exit Costs We recognize the fair value of a liability for an exit cost in the period in which a liability is incurred. The recognition and fair value estimation of an exit cost liability requires that management take into account certain estimates and assumptions. Fair value estimates are based on expected future discounted cash outflows required to satisfy the obligation, net of estimated recoveries. In periods subsequent to initial measurement, changes to an exit cost liability, including changes resulting from revisions to either the timing or the amount of estimated cash flows over the future contract period, are recognized as an adjustment to the liability in the period of the change. Exit costs, and associated accretion expense, are included in other operating expense, net in our consolidated statements of operations. See Note 11. Exit Cost – Transportation Commitments . Derivative Instruments and Hedging Activities All derivative instruments are recorded on our consolidated balance sheets as either an asset or liability and are measured at fair value. We account for our commodity derivative instruments using mark-to-market accounting and recognize all gains and losses in earnings during the period in which they occur. We offset the fair value amounts recognized for derivative instruments against the fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral. The cash collateral (commonly referred to as a “margin”) must arise from derivative instruments recognized at fair value that are executed with the same counterparty under a master agreement with netting clauses. See Note 14. Derivative Instruments and Hedging Activities . Stock-Based Compensation Restricted stock and stock options issued to employees and directors are recorded on grant-date at fair value. Expense is recognized on a straight-line basis over the employee’s and director’s requisite service period (generally the vesting period of the award) in the consolidated statements of operations. See Note 16. Stock-Based and Other Compensation Plans . Contingencies We are subject to legal proceedings, claims and liabilities that arise in the ordinary course of business. We accrue for losses associated with legal claims when such losses are considered probable and the amounts can be reasonably estimated. See Note 12. Commitments and Contingencies . Income Taxes We are subject to income and other taxes in numerous taxing jurisdictions worldwide. For financial reporting purposes, we provide taxes at rates applicable for the appropriate tax jurisdictions. We account for income taxes using the asset and liability method. Deferred tax assets and liabilities are recognized when items of income and expense are recognized in the financial statements in different periods than when recognized in the applicable tax return. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the date when the change in the tax rate was enacted. In assessing the realizability of deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income in the appropriate tax jurisdictions during the periods in which those temporary differences become deductible. We consider the scheduled reversal of deferred tax liabilities, current financial position, results of operations, projected future taxable income and tax planning strategies as well as current and forecasted business economics in the oil and gas industry. The amount of the deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced. See Note 13. Income Taxes . Treasury Stock We record treasury stock purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as reductions in shareholders’ equity in the consolidated balance sheets. Revenue Recognition Our revenues are derived primarily from the sale of crude oil, NGL and natural gas production to crude oil refining companies, midstream marketing companies, marketers, industrial companies, electric utility companies, independent power producers and cogeneration facilities, among others. We recognize revenues based on the amount of product sold to a customer when control transfers to the customer. Our revenue arrangements include the following: Crude Oil Sale Arrangements – US We sell our share of crude oil production under both short-term and long-term contracts at market-based prices, adjusted for location, quality and transportation charges. Revenue is measured based on the index-based contract price, and may include adjustments for market differentials and downstream costs incurred by the customer, including gathering, transportation, and fuel costs. Crude Oil Sale Arrangements – West Africa We sell our share of crude oil and condensate at market-based prices and recognize revenue at the time a crude oil cargo is loaded onto the tanker. Natural Gas and NGLs Sale Arrangements – US We evaluate these arrangements to determine whether the processor is a service provider or a customer. In arrangements where we determine that the processor is a customer, we record revenue when the processor takes control of the 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 arrangements, we receive natural gas and NGL products “in-kind” after processing at the tailgate of the plant. In these arrangements, where we determine that the processor is a service provider, we record revenue and applicable gathering, processing, transportation and fractionation fees on a gross basis at the time the product is delivered to the end customer. Natural Gas Sale Arrangements – West Africa We sell our share of natural gas production under a 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 – Eastern Mediterranean We sell our share of natural gas production primarily based on long-term contracts with fixed volume commitments. Performance obligations 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 these sales contracts contain take-or-pay provisions whereby the customers are required to purchase a contractual minimum over varying time periods. We record revenues related to the volumes delivered at the contract price at the time of delivery. The following table provides estimated future revenues for remaining performance obligations under fixed volume natural gas sales agreements using the contractual fixed base or floor price provision in effect. Actual future sales volumes under these agreements may exceed future minimum volume commitments. In addition, future sales revenues will vary due to components of variable consideration above the contractual base or floor provision, such as index-based escalations and market price changes. Certain of these contracts contain embedded derivatives for which we have elected the normal purchases and normal sales scope exception, which excludes the derivatives from mark-to-market accounting. Estimated future revenues related to remaining performance obligations were as follows as of December 31, 2019: (millions) 2020 2021 2022 2023 2024 Thereafter Total Natural Gas Revenues (1) $ 743 $ 768 $ 583 $ 583 $ 583 $ 5,259 $ 8,519 (1) Includes amounts related to the Tamar and Leviathan fields, offshore Israel. Oil and Gas Purchase and Sale Arrangements We enter into separate third-party purchase and sale transactions at prevailing market prices to mitigate unutilized pipeline transportation commitments. We recognize associated revenues and expenses 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. We also enter into crude oil buy/sell arrangements that effect a change in location and/or grade with required repurchase of crude oil at a delivery point. We account for these transactions on a net basis and record the residual transportation fee within gathering, transportation and processing expense in the consolidated statements of operations. Midstream Services Arrangements Third-party Midstream services revenues relate to fixed fee arrangements for gathering, transportation and storage services. Our performance obligations for the provision of such services are satisfied over time using volumes delivered as the measure of progress. Basic and Diluted Earnings (Loss) Per Share Attributable to Noble Energy Basic earnings (loss) per share (EPS) of our common stock is computed on the basis of the weighted average number of shares outstanding during each period. The diluted EPS of our common stock includes the effect of outstanding common stock equivalents such as stock options, shares of restricted stock, and/or shares of our stock held in a rabbi trust, except in periods in which there is a net loss. In the event of a net loss, we exclude the effect of outstanding common stock equivalents from the calculation of diluted EPS as the inclusion would be anti-dilutive. Recently Adopted Accounting Standards Leases Effective January 1, 2019, we adopted Accounting Standards Update No. 2016-02 (ASU 2016-02), which created Topic 842 – Leases (ASC 842). The standard requires lessees to recognize a right-of-use (ROU) asset and lease liability on the balance sheet for the rights and obligations created by leases. This standard does not apply to leases to explore for or use minerals, oil, natural gas or similar nonregenerative resources, including the intangible right to explore for those resources and rights to use the land in which those natural resources are contained. Upon adoption, we elected the following optional practical expedients: • transition “practical expedients,” permitting us not to reassess our prior conclusions about lease identification, lease classification and initial direct costs; • the practical expedient pertaining to land easements, allowing us to account for existing land easements under our previous accounting policy; and • the practical expedient to not separate lease and non-lease components for the majority of our leases (elected by asset class). We adopted ASC 842 using the modified retrospective method and recorded ROU assets and lease liabilities of $282 million and $287 million , respectively, primarily related to operating leases. ROU assets and corresponding liabilities are based on the present value of the minimum lease payments. Our accounting for finance leases remains substantially unchanged. Adoption of ASC 842 did not materially impact our consolidated statement of operations and comprehensive income and had no impact on our consolidated statement of cash flows. Additional information related to our accounting policies for leases is as follows: • Most of our leases do not provide implicit borrowing rates; therefore, using the portfolio approach, we determine the present value of lease payments using hypothetical secured borrowing rates based on information available at lease commencement. • Leases with an initial term of 12 months or less are not recorded on the balance sheet and we recognize lease expense for these leases on a straight-line basis over the lease term. Most leases include one or more options to renew, with renewal terms that can extend the lease term from one month to one year or more. Additionally, some of our leases include an option for early termination. We include renewal periods and exclude termination periods from our lease term if, at commencement, it is reasonably likely that we will exercise the option. • Certain of our lease agreements include rental payments that are adjusted periodically for inflation or passage of time. These step payments are included within our present value calculation as they are known adjustments at commencement. Variable payments related to lease agreements are not material. • We have lease agreements that include |
Additional Financial Statement
Additional Financial Statement Information | 12 Months Ended |
Dec. 31, 2019 | |
Additional Financial Statement Information [Abstract] | |
Additional Financial Statement Information | Note 2. Additional Financial Statement Information Statements of Operations Information Other statements of operations information is as follows: Year Ended December 31, (millions) 2019 2018 2017 Other Revenue Income from Equity Method Investments and Other $ 51 $ 172 $ 177 Midstream Services Revenues - Third Party 94 78 19 Total $ 145 $ 250 $ 196 Production Expense Lease Operating Expense $ 532 $ 576 $ 571 Production and Ad Valorem Taxes 175 190 118 Gathering, Transportation and Processing Expense 417 393 432 Other Royalty Expense 13 38 20 Total $ 1,137 $ 1,197 $ 1,141 Exploration Expense Leasehold Impairment and Amortization $ — $ 1 $ 62 Dry Hole Cost (1) 100 1 9 Seismic, Geological and Geophysical 21 22 27 Staff Expense 48 54 55 Other 33 51 35 Total $ 202 $ 129 $ 188 Loss on Marcellus Shale Upstream Divestiture and Other Loss on Sale $ — $ — $ 2,270 Exit Cost — — 93 Other — — 16 Total $ — $ — $ 2,379 Other Operating Expense, Net Marketing Expense $ 34 $ 40 $ 47 Firm Transportation Exit Cost (2) 88 — — Clayton Williams Energy Acquisition Expenses — — 100 Loss (Gain) on Asset Retirement Obligation Revisions 9 (25 ) (42 ) Other, Net 83 35 33 Total $ 214 $ 50 $ 138 (1) See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs . (2) See Note 11. Exit Cost – Transportation Commitments . Balance Sheet Information Other balance sheet information is as follows: December 31, (millions) 2019 2018 Accounts Receivable, Net Commodity Sales $ 446 $ 383 Joint Interest Billings 164 137 Other 128 111 Allowance (8 ) (15 ) Total $ 730 $ 616 Other Current Assets Commodity Derivative Assets $ 14 $ 180 Inventories, Materials and Supplies 59 55 Assets Held for Sale (1) 14 133 Prepaid Expenses and Other Current Assets 61 50 Total $ 148 $ 418 Other Noncurrent Assets Equity Method Investments (2) $ 1,066 $ 286 Operating Lease Right-of-Use Assets (3) 227 — Customer-Related Intangible Assets, Net 278 310 Goodwill 110 110 Mutual Fund Investments 27 38 Other Noncurrent Assets 126 97 Total $ 1,834 $ 841 Other Current Liabilities Production and Ad Valorem Taxes $ 118 $ 103 Asset Retirement Obligations 84 118 Interest Payable 74 66 Operating Lease Liabilities (3) 88 — Compensation and Benefits Payable 126 83 Other Current Liabilities 229 149 Total $ 719 $ 519 Other Noncurrent Liabilities Deferred Compensation Liabilities $ 133 $ 147 Asset Retirement Obligations 730 762 Operating Lease Liabilities (3) 164 — Firm Transportation Exit Cost Accrual (4) 129 67 Other Noncurrent Liabilities 222 189 Total $ 1,378 $ 1,165 (1) Amounts relate to divestitures of non-core assets and acreage in Reeves County, Texas. See Note 4. Acquisitions and Divestitures . (2) See Note 5. Equity Method Investments . (3) Amounts relate to assets and liabilities recorded as a result of ASC 842 adoption. See Note 9. Leases . (4) See Note 11. Exit Cost – Transportation Commitments . Reconciliation of Total Cash We define total cash as cash, cash equivalents and restricted cash. The following table provides a reconciliation of total cash: December 31, (millions) 2019 2018 Cash and Cash Equivalents at Beginning of Period $ 716 $ 675 Restricted Cash at Beginning of Period 3 38 Cash, Cash Equivalents, and Restricted Cash at Beginning of Period $ 719 $ 713 Cash and Cash Equivalents at End of Period $ 484 $ 716 Restricted Cash at End of Period — 3 Cash, Cash Equivalents, and Restricted Cash at End of Period $ 484 $ 719 A significant portion of our cash is located in foreign subsidiaries. The cash is denominated in US dollars and at certain times is invested in highly liquid money market funds and short term deposits with original maturities of three months or less at the time of purchase. Although our cash and cash equivalents are deposited with major international banks and financial institutions, concentrations of cash in certain foreign locations may increase credit risk. We monitor the creditworthiness of the banks and financial institutions with which we invest and review the securities underlying our investment accounts. Supplemental Cash Flow Information Supplemental statements of cash flow information is as follows: Year Ended December 31, (millions) 2019 2018 2017 Cash Paid During the Year For Interest, Net of Amount Capitalized (1) $ 208 $ 270 $ 346 Income Taxes Paid, Net 76 172 121 (1) Interest capitalized totaled $102 million in 2019 , $73 million in 2018 and $49 million in 2017 . See Note 9. Leases for supplemental cash flow information related to leases. Significant Purchasers Non-affiliated purchasers who accounted for 10% or more of our commodity sales were as follows: Year Ended December 31, 2019 2018 2017 Percentage of Crude Oil Sales Shell (1) 22 % 22 % 22 % BP (2) 18 % 31 % 15 % Percentage of Total Crude Oil, NGL & Natural Gas Sales Shell (1) 15 % 14 % 13 % BP (2) 14 % 17 % 10 % (1) Includes sales to Shell Energy North America and Shell Trading (US) Company (collectively, Shell). (2) Includes sales to BP America Production, BP Energy Co and BP Products North America, Inc (collectively, BP). Both Shell and BP purchased crude oil and condensate domestically from our US onshore operations. No other single purchaser accounted for 10% or more of our commodity sales in 2019 . We routinely monitor the credit worthiness of our purchasers. While we maintain credit insurance associated with certain purchasers, we do not carry credit insurance for all purchasers. We believe that the loss of any one significant purchaser would not have a material adverse effect on our financial position or results of operations as there are numerous potential purchasers of our US onshore production and generally production is sold under short-term contracts. |
Segment Information
Segment Information | 12 Months Ended |
Dec. 31, 2019 | |
Segment Reporting [Abstract] | |
Segment Information | Note 3. Segment Information We have the following reportable segments: United States (US onshore (Marcellus Shale until July 2017) and Gulf of Mexico (until April 2018)); Eastern Mediterranean (Israel and Cyprus); West Africa (Equatorial Guinea, Cameroon and Gabon); Other International (Suriname (until November 2018), Falkland Islands (until December 2018), Canada, Colombia and New Ventures); and Midstream. The Midstream segment includes the consolidated accounts of Noble Midstream Partners. The geographical reportable segments are in the business of crude oil and natural gas acquisition and exploration, development, and production (Oil and Gas Exploration and Production). The Midstream reportable segment develops, owns, and operates domestic midstream infrastructure assets, as well as invests in other financially attractive midstream projects, with current focus areas being the DJ and Delaware Basins. The chief operating decision maker analyzes income (loss) before income taxes to assess the performance of Noble Energy's reportable segments as management believes this measure provides useful information in assessing the Company's operating and financial performance across periods. Expenses related to debt, such as interest and other debt-related costs, headquarters depreciation, corporate general and administrative expenses, exit costs and certain costs associated with mitigating the effects of our retained Marcellus Shale firm transportation agreements, are recorded at the corporate level. Oil and Gas Exploration and Production Midstream (millions) Consolidated United States Eastern Mediter-ranean West Africa Other Int'l United States Intersegment Eliminations and Other (1) Corporate Year Ended December 31, 2019 Crude Oil Sales $ 2,736 $ 2,437 $ 6 $ 293 $ — $ — $ — $ — NGL Sales 354 354 — — — — — — Natural Gas Sales 814 345 451 18 — — — — Total Crude Oil, NGL and Natural Gas Sales 3,904 3,136 457 311 — — — — Sales of Purchased Oil and Gas 389 109 — — — 190 — 90 Income (Loss) from Equity Method Investments and Other 51 8 — 61 — (18 ) — — Midstream Services Revenues - Third Party 94 — — — — 94 — Intersegment Revenues — — — — — 427 (427 ) — Total Revenues 4,438 3,253 457 372 — 693 (427 ) 90 Lease Operating Expense 532 460 37 76 — 4 (45 ) — Production and Ad Valorem Taxes 175 169 — — — 6 — — Gathering, Transportation and Processing Expense 417 598 1 — — 110 (292 ) — Other Royalty Expense 13 13 — — — — — — Total Production Expense 1,137 1,240 38 76 — 120 (337 ) — Exploration Expense 202 57 109 13 23 — — — Depreciation, Depletion and Amortization 2,197 1,907 67 83 1 104 (29 ) 64 Asset Impairments 1,160 1,160 — — — — — — Cost of Purchased Oil and Gas 431 107 — — — 181 — 143 Firm Transportation Exit Cost 88 — — — — — — 88 Loss on Commodity Derivative Instruments 143 125 — 18 — — — — Loss on Debt Extinguishment 44 — — — — — — 44 (Loss) Income Before Income Taxes (1,776 ) (1,431 ) 199 164 (25 ) 258 (55 ) (886 ) Additions to Long-Lived Assets, Excluding Acquisitions 2,408 1,651 505 70 20 230 (92 ) 24 Additions to Equity Method Investments 799 — 189 — — 610 — — Property, Plant and Equipment, Net 17,451 11,859 3,041 793 44 1,721 (223 ) 216 Year Ended December 31, 2018 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 Crude Oil Sales $ 2,945 $ 2,548 $ 7 $ 390 $ — $ — $ — $ — NGL Sales 587 587 — — — — — — Natural Gas Sales 929 435 473 21 — — — — Total Crude Oil, NGL and Natural Gas Sales 4,461 3,570 480 411 — — — — Sales of Purchased Oil and Gas 275 20 — — — 142 — 113 Income from Equity Method Investments and Other 172 — — 132 — 40 — — Midstream Services Revenues - Third Party 78 — — — — 78 — — Intersegment Revenues — — — — — 351 (351 ) — Total Revenues 4,986 3,590 480 543 — 611 (351 ) 113 Lease Operating Expense 576 480 26 97 — — (27 ) — Production and Ad Valorem Taxes 190 184 — — — 6 — — Gathering, Transportation and Processing Expense 393 533 — — — 95 (235 ) — Other Royalty Expense 38 38 — — — — — — Total Production Expense 1,197 1,235 26 97 — 101 (262 ) — Exploration Expense 129 48 7 6 68 — — — Depreciation, Depletion and Amortization 1,934 1,642 60 115 2 87 (20 ) 48 (Gain) Loss on Divestitures, Net (843 ) 36 (376 ) — — (503 ) — — Asset Impairments 206 169 — — — 37 — — Goodwill Impairment 1,281 1,281 — — — — — — Cost of Purchased Oil and Gas 296 20 — — — 136 — 140 Gain on Asset Retirement Obligation Revision (25 ) — (8 ) — (17 ) — — — (Gain) Loss on Commodity Derivative Instruments (63 ) (70 ) — 7 — — — — Income (Loss) Before Income Taxes 140 (875 ) 742 305 (53 ) 726 (60 ) (645 ) Additions to Long Lived Assets, Excluding Acquisitions 3,253 2,115 671 12 — 521 (91 ) 25 Property, Plant and Equipment, Net 18,419 13,044 2,630 805 37 1,742 (145 ) 306 Year Ended December 31, 2017 Crude Oil Sales $ 2,346 $ 1,993 $ 6 $ 347 $ — $ — $ — $ — NGL Sales 493 493 — — — — — — Natural Gas Sales 1,221 670 528 23 — — — — Total Crude Oil, NGL and Natural Gas Sales 4,060 3,156 534 370 — — — — Income from Equity Method Investments and Other 177 — — 120 — 57 — — Midstream Services Revenues - Third Party 19 — — — — 19 — — Intersegment Revenues — — — — — 277 (277 ) — Oil and Gas Exploration and Production Midstream (millions) Consolidated United States Eastern Mediter-ranean West Africa Other Int'l United States Intersegment Eliminations and Other (1) Corporate Total Revenues 4,256 3,156 534 490 — 353 (277 ) — Lease Operating Expense 571 466 29 90 — — (14 ) — Production and Ad Valorem Taxes 118 115 — — — 3 — — Gathering, Transportation and Processing Expense 432 550 — — — 70 (188 ) — Other Royalty Expense 20 20 — — — — — — Total Production Expense 1,141 1,151 29 90 — 73 (202 ) — Exploration Expense 188 102 2 5 79 — — — Depreciation, Depletion and Amortization 2,053 1,739 76 146 4 30 (5 ) 63 Loss on Marcellus Shale Upstream Divestiture and Other 2,379 2,286 — — — — — 93 Gain on Divestitures, Net (326 ) (325 ) (1 ) — — — — — Asset Impairments 70 63 — — 7 — — — Clayton Williams Energy Acquisition Expenses 100 100 — — — — — — Gain on Asset Retirement Obligation Revision (42 ) — — — (42 ) — — — (Gain) Loss on Commodity Derivative Instruments (63 ) (92 ) — 29 — — — — Loss on Debt Extinguishment 98 — — — — — — 98 (Loss) Income Before Income Taxes (2,191 ) (2,365 ) 413 203 (54 ) 233 (62 ) (559 ) Additions to Long Lived Assets, Excluding Acquisitions 2,851 1,994 411 34 (34 ) 423 (79 ) 102 Property, Plant and Equipment, Net 17,502 13,348 2,005 863 25 1,027 (74 ) 308 (1) Intersegment eliminations related to income (loss) before income taxes are the result of Midstream expenditures. Certain of these expenditures are presented as property, plant and equipment within the E&P business on an unconsolidated basis, in accordance with the successful efforts method of accounting. Other expenditures are presented as production expense. Intercompany revenues and expenses are eliminated upon consolidation. |
Acquisitions and Divestitures
Acquisitions and Divestitures | 12 Months Ended |
Dec. 31, 2019 | |
Business Combinations [Abstract] | |
Acquisitions and Divestitures | Note 4. Acquisitions and Divestitures Year Ended December 31, 2019 Divestiture of Reeves County Assets In February 2019, we sold approximately 13,000 net proved and unproved non-core acres in the Reeves County, Texas area of the Delaware Basin. We received cash consideration of approximately $131 million , recognizing no gain or loss on the sale. Asset Sale to Noble Midstream Partners In November 2019, we sold substantially all of our remaining midstream interests and assets to Noble Midstream Partners. The value of the transaction, which also included the sale of our incentive distribution rights, totaled approximately $1.6 billion , comprised of $670 million of cash and 38.5 million of newly issued Noble Midstream Partners common units, valued at approximately $930 million . Noble Midstream Partners funded the cash portion of the consideration through $420 million of borrowings on the Noble Midstream Services Revolving Credit Facility (defined below) and approximately $250 million in gross proceeds from a private placement of approximately 12 million common units. At closing, we owned approximately 56.5 million common units, or 63% , of the outstanding units of Noble Midstream Partners. We are subject to a post-closing 180-day lock-up period applicable to the common units received. Sales proceeds were used to repay amounts outstanding under our commercial paper program. As we continue to consolidate Noble Midstream Partners, the activities related to these assets will continue to be reflected within our Midstream segment. Year Ended December 31, 2018 Divestiture of Gulf of Mexico Assets We sold substantially all of our Gulf of Mexico assets, including interests in producing properties and undeveloped acreage, for cash consideration of $480 million , along with the assumption, by the purchaser, of abandonment obligations associated with the properties sold. We recorded impairment expense of $168 million during first quarter 2018. We received net proceeds of approximately $384 million and recorded a loss of $24 million upon close. Divestiture of 7.5% Interest in Tamar Field In first quarter 2018, we sold 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 of $484 million and 38.5 million of Tamar Petroleum shares that had a publicly traded value of $224 million . Total consideration received from the sale was applied to the field's basis and resulted in the recognition of a pre-tax gain of $ 376 million . We incurred tax expense of $86 million in connection with the transaction. The Tamar Petroleum shares were subject to certain temporary lock-up provisions and had no voting rights. 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% less than the publicly traded value on the TASE. These shares were accounted for at fair value and we recorded decreases in fair value of $27 million and dividend income of $31 million during 2018. These amounts are included in other non-operating (income) expense, net, in our consolidated statements of operations. In fourth quarter 2018, we sold the Tamar Petroleum shares in over the counter transactions for pre-tax proceeds of $163 million , net of transaction expenses. Divestiture of Southwest Royalties In January 2018, we sold our investment in Southwest Royalties, Inc., which we acquired in the 2017 acquisition of Clayton Williams Energy (Clayton Williams Energy Acquisition). We received proceeds of $60 million , resulting in no gain or loss recognition on the sale of these assets. Divestiture of Greeley Crescent Assets In September 2018, we sold assets in the Greeley Crescent area of the DJ Basin and received proceeds of $68 million , resulting in no gain or loss recognition on the sale of these assets. Divestiture of Non-Core Delaware Basin Acreage In December 2018, we sold certain non-core acreage in the Delaware Basin, receiving proceeds of $63 million , resulting in a pre-tax loss of $16 million . DJ Acreage Exchange We closed a cashless acreage exchange in the DJ Basin receiving approximately 12,900 net undeveloped acres within core areas of our Mustang and Wells Ranch positions in exchange for approximately 12,300 net undeveloped acres in non-core areas of Mustang and Wells Ranch. No gain or loss was recognized. Noble Midstream Partners Saddle Butte Acquisition In January 2018, Noble Midstream Partners and its partner formed Black Diamond Gathering LLC (Black Diamond) to acquire Saddle Butte Rockies Midstream, LLC and affiliates, which own a large-scale integrated gathering system located in the DJ Basin. Consideration for the acquisition totaled $681 million , which included $663 million of cash and assumption of $18 million of liabilities. Our partner funded approximately $343 million of the purchase price, which is reflected as a contribution from noncontrolling interest within our consolidated statement of shareholders' equity, and Noble Midstream Partners funded the remainder. We accounted for the transaction as a business combination using the acquisition method and allocated the total purchase price to assets acquired and liabilities assumed based on the fair values at the acquisition date. Allocated fair values included: $206 million to property, plant and equipment; $340 million to customer-related intangible assets (acquired customer contracts); and $110 million to implied goodwill. We own a 54.4% interest in Black Diamond and consolidate the entity as a VIE, reflecting the third-party ownership within noncontrolling interests in our consolidated statements of shareholders' equity. Year Ended December 31, 2017 Clayton Williams Energy Acquisition We completed the Clayton Williams Energy Acquisition on April 24, 2017 . Total consideration of $ 2.5 billion included cash consideration of $637 million and proceeds from the issuance of approximately 56 million shares of Noble Energy common stock with a fair value of approximately $1.9 billion . In exchange, we received all outstanding Clayton Williams Energy shares, including stock options, restricted stock awards and warrants. In connection with the acquisition, we incurred acquisition-related costs of $100 million , including $64 million of severance, consulting, investment, advisory, legal and other merger-related fees and $36 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. The transaction was accounted for as a business combination using the acquisition method. The allocation of the total purchase price of Clayton Williams Energy to the assets acquired and the liabilities assumed was 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. The $1.3 billion of goodwill recorded as part of the transaction was fully impaired in fourth quarter 2018. The results of operations attributable to Clayton Williams Energy are included in our consolidated statements of operations for 2019 and 2018. Revenues of $99 million and pre-tax net loss of $19 million were generated from Clayton Williams Energy assets during the period April 24, 2017 to December 31, 2017. Marcellus Shale Upstream Divestiture In 2017, we sold all of our Marcellus Shale upstream assets, which were primarily natural gas properties. The sales price totaled $1.2 billion , and we received $1.0 billion of net cash proceeds, after consideration of customary closing adjustments. The sales price includes additional contingent consideration of up to $100 million structured as three separate payments of $33.3 million each for each annual period through 2020, should certain conditions be met. 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. We recognized a loss on divestiture of $2.3 billion , or $1.5 billion after-tax, and recorded exit costs for retained financial commitments of $93 million , discounted. The aggregate net book value of the properties sold was approximately $3.4 billion , which included approximately $883 million of undeveloped leasehold cost. After the property sale, we retained certain firm transportation commitments to flow Marcellus Shale natural gas production. See Note 11. Exit Cost – Transportation Commitments . Other US Onshore Transactions We conducted the following additional transactions in 2017: • sold certain US onshore properties receiving total proceeds of $671 million , including $568 million related to divestment of non-core acreage in the DJ Basin. Proceeds were applied to reduce field basis with no recognition of gain or loss. • received $335 million and recognized a gain of $334 million on the sale of mineral and royalty assets covering approximately 140,000 net mineral acres concentrated primarily in Texas, Oklahoma and North Dakota. • acquired Delaware Basin properties, including seven producing wells, increasing our contiguous acreage position in the Reeves County, Texas area. Consideration totaled $301 million , approximately $246 million of which was allocated to undeveloped leasehold cost. Asset Sale to Noble Midstream Partners In June 2017, we sold interests in certain midstream assets to Noble Midstream Partners for $270 million , which consisted of $245 million in cash and 562,430 Noble Midstream Partners common units. Noble Midstream Partners funded the cash consideration with approximately $138 million of net proceeds from a concurrent private placement of common units, $90 million of borrowings under the Noble Midstream Services Revolving Credit Facility and the remainder from cash on hand. See Supplemental Oil and Gas Information (Unaudited) for discussion of proved reserves acquired or divested in connection with the above transactions. |
Equity Method Investments
Equity Method Investments | 12 Months Ended |
Dec. 31, 2019 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Equity Method Investments | Note 5. Equity Method Investments The carrying values of our equity method investments, including the respective segments, are as follows: December 31, (millions, except percentages) Segment Ownership 2019 2018 Eastern Mediterranean Pipeline B.V. Eastern Mediterranean 25% $ 189 $ — Atlantic Methanol Production Company, LLC and Affiliates (1) West Africa 45% 160 146 Alba Plant LLC (2) West Africa 28% 56 58 EPIC Y-Grade, LP Midstream 15% 166 — EPIC Crude Holdings, LP Midstream 30% 339 — Delaware Crossing LLC Midstream 50% 69 — Advantage Pipeline, L.L.C. Midstream 50% 77 73 Other N/A N/A 10 9 Total Equity Method Investments (3) $ 1,066 $ 286 (1) Atlantic Methanol Production Company, LLC (AMPCO) owns and operates a methanol plant and related facilities in Equatorial Guinea. (2) Alba Plant LLC owns and operates a LPG processing plant in Equatorial Guinea. (3) At December 31, 2019 , total carrying values were $ 42 million higher than the underlying net assets of the investments, primarily due to capitalized interest which is amortized into earnings over the useful life of the related assets. At December 31, 2019 , consolidated retained earnings included $73 million related to the undistributed earnings of equity method investments. Acquisitions and Divestitures Year Ended December 31, 2019 EMED Pipeline B.V. During third quarter 2019, we acquired a 25% equity interest in Eastern Mediterranean Pipeline B.V. (EMED Pipeline B.V.). In fourth quarter 2019, EMED Pipeline B.V. acquired an approximate 39% equity interest in East Mediterranean Gas Company S.A.E. (EMG), which owns the EMG Pipeline. Upon closing of EMED Pipeline B.V.'s equity acquisition of EMG, we own an effective, indirect interest of approximately 10% , net, in EMG. The EMG Pipeline provides connection from the Israel pipeline network to Egyptian customers and supports delivery of natural gas from our producing fields offshore Israel into Egypt. During 2019, we made capital contributions of $ 189 million in EMED Pipeline B.V., primarily to fund the EMG equity acquisition. EPIC Pipelines In first quarter 2019, Noble Midstream Partners exercised and closed options with EPIC Midstream Holdings, LP (EPIC) to acquire a 15% equity interest in EPIC Y-Grade, LP (EPIC Y-Grade), which constructed the EPIC Y-Grade Pipeline, and a 30% equity interest in EPIC Crude Holdings, which is constructing the EPIC Crude Oil Pipeline. The pipelines support transportation of production from the Delaware Basin to Corpus Christi, Texas. Noble Midstream Partners made capital contributions of $ 169 million and $ 351 million in EPIC Y-Grade and EPIC Crude Holdings, respectively, in 2019. Delaware Crossing Joint Venture In February 2019, Noble Midstream Partners formed a 50 / 50 joint venture with Salt Creek Midstream LLC. The joint venture, Delaware Crossing LLC, is constructing a crude oil pipeline system in the Delaware Basin. Noble Midstream Partners made capital contributions of $ 70 million for its share of pipeline construction costs in 2019. Year Ended December 31, 2018 Divestiture of Marcellus Shale CONE Gathering In January 2018, we sold 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 $309 million in cash and recognized a pre-tax gain of $196 million . After the sale, we held 21.7 million common units, representing a 34.1% limited partner interest, in CNX Midstream Partners. During 2018, we sold our 21.7 million common units, receiving net proceeds of approximately $387 million , and recognized a gain of $307 million . The investment was previously accounted for under the equity method of accounting. Year Ended December 31, 2017 Noble Midstream Partners Advantage Joint Venture In April 2017, Noble Midstream Partners acquired a 50% interest in Advantage Pipeline, L.L.C. (Advantage Pipeline) for $67 million . Advantage Pipeline owns a crude oil pipeline system in the southern Delaware Basin from Reeves County, Texas to Crane County, Texas, for which we serve as operator. Combined Financial Information Summarized, 100% combined balance sheet information for equity method investments was as follows: December 31, (millions) 2019 2018 Current Assets $ 681 $ 387 Noncurrent Assets 5,306 575 Current Liabilities 607 198 Noncurrent Liabilities 2,243 81 Summarized, 100% combined statements of operations for equity method investments was as follows: Year Ended December 31, (millions) 2019 2018 2017 Operating Revenues $ 1,018 $ 855 $ 790 Operating Expenses 853 284 303 Operating Income 165 571 487 Other (Loss) Income, net (33 ) 3 15 Income Before Income Taxes 132 574 502 Income Tax Provision 72 152 136 Net Income $ 60 $ 422 $ 366 |
Capitalized Exploratory Well Co
Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs | 12 Months Ended |
Dec. 31, 2019 | |
Capitalized Exploratory Well Costs [Abstract] | |
Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs | Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs Capitalized Exploratory Well Costs We capitalize exploratory well costs until a determination is made that the well has found proved reserves or is deemed noncommercial. These costs are included in Oil and Gas Properties on our consolidated balance sheets. 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, excluding amounts that were capitalized and subsequently expensed in the same period, are as follows: Year Ended December 31, (millions) 2019 2018 2017 Capitalized Exploratory Well Costs, Beginning of Period $ 354 $ 520 $ 768 Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves 26 7 20 Divestitures (1) — (168 ) — Reclassified to Proved Oil and Gas Properties, Based on Determination of Proved Reserves, or to Assets Held for Sale (2) — (1 ) (203 ) Capitalized Exploratory Well Costs Charged to Expense (3) (100 ) (4 ) (65 ) Capitalized Exploratory Well Costs, End of Period $ 280 $ 354 $ 520 (1) The 2018 amount relates to the second quarter 2018 sale of our Gulf of Mexico assets. (2) The 2017 amount relates to the approval and sanction of the first phase of development of the Leviathan field. (3) In fourth quarter 2019, we recorded exploration expense of $100 million related to the Leviathan Deep prospect, offshore Israel, which was initially drilled in 2012 but did not reach the target interval. Throughout this time, we have evaluated seismic information and nearby discoveries in the region. Upon concluding we would not move forward with the project, we wrote off the entire amount of capitalized exploratory well costs associated with this prospect. The 2017 amount relates to a write-off of costs for a natural gas discovery in the Gulf of Mexico. See Note 10. Impairments . The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced: December 31, (millions, except number of projects) 2019 2018 2017 Exploratory Well Costs Capitalized for a Period of One Year or Less $ 22 $ 6 $ 10 Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling 258 348 510 Balance at End of Period $ 280 $ 354 $ 520 Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling 5 7 8 The following table provides a further aging of those exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling as of December 31, 2019 : Suspended Since (millions) Total 2017 - 2018 2015 - 2016 2014 & Prior Progress Offshore Eastern Mediterranean Dalit (Offshore Israel) $ 23 $ (9 ) $ 3 $ 29 Our future development plan for this 2008 natural gas discovery, consisting of a tie-in to existing infrastructure at Tamar, was approved by the Government of Israel in 2019. During 2019, we continued analyzing 3D seismic data to evaluate additional potential of the area. Cyprus (Offshore Cyprus) 100 3 15 82 During 2019, we received approval of our Plan of Development and Exploitation License from the Government of Cyprus. We continued to progress capital project cost improvement and regional natural gas marketing efforts. Offshore West Africa Felicita (Block O, Offshore Equatorial Guinea) 49 2 4 43 We are in the process of evaluating regional development scenarios for this 2008 natural gas discovery. The recent sanction of the Alen Gas Monetization project, which represents the initial step in establishing a regional natural gas hub, expands the options for development of this discovery through existing infrastructure. YoYo (YoYo Block, Offshore Cameroon) and Yolanda (Block I, Offshore Equatorial Guinea) 80 2 5 73 A data exchange agreement for these 2007 condensate and natural gas discoveries has been executed between the governments of Equatorial Guinea and Cameroon. Our development team is working with both governments to evaluate natural gas monetization options. The recent sanction of the Alen Gas Monetization project, which represents the initial step in establishing a regional natural gas hub, expands the options for development of this discovery through existing infrastructure. Other Projects less than $20 million 6 (1 ) (10 ) 17 Continuing to assess and evaluate wells. Total $ 258 $ (3 ) $ 17 $ 244 Undeveloped Leasehold Costs Changes in undeveloped leasehold costs, which are recorded in oil and gas properties on our consolidated balance sheets, were as follows: Year Ended December 31, (millions) 2019 2018 Undeveloped Leasehold Costs, Beginning of Period $ 2,373 $ 2,922 Additions to Undeveloped Leasehold Costs 59 47 Transfers to Proved Properties (1) (184 ) (453 ) Assets Sold (2) (96 ) (142 ) Impairment — (1 ) Undeveloped Leasehold Costs, End of Period $ 2,152 $ 2,373 (1) Transfers primarily relate to development of Delaware Basin assets. (2) Amounts primarily relate to Delaware Basin assets sold. See Note 4. Acquisitions and Divestitures . As of December 31, 2019 , undeveloped leasehold costs included $ 1.9 billion, $ 100 million, $ 79 million, and $ 58 million attributable to the Delaware Basin, Eagle Ford Shale, other US onshore properties, and international properties, respectively. Certain of these costs pertain to acquired leases or licenses that are subject to expiration over the next several years unless production is established on units containing the acreage. Other costs pertain to acreage that is being held by production. |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2019 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | Note 7. Asset Retirement Obligations Asset retirement obligations (ARO) consists 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: Year Ended December 31, (millions) 2019 2018 Asset Retirement Obligations, Beginning of Period $ 880 $ 875 Liabilities Incurred 70 25 Liabilities Settled (110 ) (345 ) Revisions of Estimates (69 ) 293 Reclassification to Liabilities Associated with Assets Held for Sale — (1 ) Accretion Expense 43 33 Asset Retirement Obligations, End of Period $ 814 $ 880 Year Ended December 31, 2019 Liabilities incurred included $43 million in Israel, primarily related to costs associated with the Leviathan field, and $20 million in US onshore, primarily related to the DJ and Delaware Basins. The majority of liabilities settled relate to abandonment of properties in the DJ Basin where we have engaged in a program to plug and abandon older vertical wells. Costs associated with these abandonment activities will be incurred over several years. Revisions of estimates include a decrease of $72 million in the DJ Basin as a result of improved cycle times and cost reductions for vertical wells. Year Ended December 31, 2018 Liabilities settled included $216 million and $24 million of liabilities assumed by the purchasers of the Gulf of Mexico properties and Greeley Crescent assets, respectively, and $104 million related to abandonment of US onshore properties, primarily in the DJ Basin, where we have engaged in a program to plug and abandon older vertical wells, as discussed above. Revisions of estimates were primarily related to increases in cost estimates and changes in timing estimates of $287 million for US onshore, primarily in the DJ Basin related to the abandonment activities noted above, $ 10 million for wells offshore Israel and $ 9 million for wells offshore Equatorial Guinea, partially offset by decreases in cost and timing estimates of $17 million associated with the North Sea abandonment project. |
Leases
Leases | 12 Months Ended |
Dec. 31, 2019 | |
Leases [Abstract] | |
Leases | Note 9. Leases In the normal course of business, we enter into operating and finance lease agreements to support our operations. Operating leases primarily include office space for our corporate and field locations, US onshore compressors and drilling rigs, vessels and helicopters for offshore operations, storage facilities, and other miscellaneous assets. Finance leases include corporate office space, a trunkline in the DJ Basin, a floating production, storage and offloading vessel (FPSO) in West Africa, and vehicles. Our leasing activity is recorded and presented on a gross basis, with the exception of the FPSO which is recorded net to our interest. Balance Sheet Information ROU assets and lease liabilities ar e as follows: (millions) Balance Sheet Location December 31, 2019 ROU Assets Operating Leases (1) Other Noncurrent Assets $ 227 Finance Leases (2) Total Property, Plant and Equipment, Net 172 Total ROU Assets $ 399 Lease Liabilities Current Liabilities Operating Leases Other Current Liabilities $ 88 Finance Leases Other Current Liabilities 42 Noncurrent Liabilities Operating Leases Other Noncurrent Liabilities 164 Finance Leases Long-Term Debt 163 Total Lease Liabilities $ 457 (1) Operating lease ROU assets include compressors of $ 89 million and office space of $80 million . (2) Finance lease ROU assets include office space of $90 million and a trunkline of $28 million , both net of accumulated amortization. Statement of Operations Information The components of lease cost are as follows: (millions) Statement of Operations Location Year Ended December 31, 2019 Operating Lease Cost Various (1) $ 110 Finance Lease Cost Amortization Expense Depreciation, Depletion and Amortization 38 Interest Expense Interest, Net of Amount Capitalized 13 Short-term Lease Cost (2) Various (1) 424 Sublease Income General and Administrative (5 ) Total Lease Cost $ 580 (1) Cost classifications vary depending on the leased asset. Costs are primarily included within production expense and general and administrative expense. In addition, in accordance with the successful efforts method of accounting, certain lease costs may be capitalized when incurred and therefore, are included as part of oil and gas properties on our consolidated balance sheets. (2) Costs primarily relate to hydraulic fracturing services, well-to-well drilling rig contracts and other miscellaneous lease agreements. Amount excludes costs for leases with an initial term of one month or less. Cash Flow Information Supplemental cash flow information is as follows: Year Ended December 31, 2019 (millions) Operating Leases Finance Leases Cash Paid for Amounts Included in the Measurement of Lease Liabilities Operating Cash Flows $ 74 $ 12 Investing Cash Flows 36 — Financing Cash Flows — 42 Non-Cash Activities ROU Assets Obtained in Exchange for Lease Liabilities (1) 127 26 (1) Amounts exclude the impact of adopting ASC 842 on January 1, 2019. See Note 1. Summary of Significant Accounting Policies . Annual Lease Maturities As of December 31, 2019 , maturities of lease liabilities were as follows: (millions) Operating Leases Finance Leases Total 2020 $ 100 $ 52 $ 152 2021 60 38 98 2022 41 27 68 2023 26 23 49 2024 15 21 36 2025 and Thereafter 37 86 123 Total Lease Liabilities, Undiscounted 279 247 526 Less: Imputed Interest 27 42 69 Total Lease Liabilities (1) $ 252 $ 205 $ 457 (1) Includes the current portions of $ 88 million and $ 42 million for operating and finance leases, respectively. Lease Commitments See Note 12. Commitments and Contingencies for lease commitments as of December 31, 2019 . Other Information As of December 31, 2019 , other information related to our leases is as follows: Operating Leases Finance Leases Weighted-Average Remaining Lease Term 4.9 years 7.5 years Weighted-Average Discount Rate 4.05 % 4.96 % |
Leases | Note 9. Leases In the normal course of business, we enter into operating and finance lease agreements to support our operations. Operating leases primarily include office space for our corporate and field locations, US onshore compressors and drilling rigs, vessels and helicopters for offshore operations, storage facilities, and other miscellaneous assets. Finance leases include corporate office space, a trunkline in the DJ Basin, a floating production, storage and offloading vessel (FPSO) in West Africa, and vehicles. Our leasing activity is recorded and presented on a gross basis, with the exception of the FPSO which is recorded net to our interest. Balance Sheet Information ROU assets and lease liabilities ar e as follows: (millions) Balance Sheet Location December 31, 2019 ROU Assets Operating Leases (1) Other Noncurrent Assets $ 227 Finance Leases (2) Total Property, Plant and Equipment, Net 172 Total ROU Assets $ 399 Lease Liabilities Current Liabilities Operating Leases Other Current Liabilities $ 88 Finance Leases Other Current Liabilities 42 Noncurrent Liabilities Operating Leases Other Noncurrent Liabilities 164 Finance Leases Long-Term Debt 163 Total Lease Liabilities $ 457 (1) Operating lease ROU assets include compressors of $ 89 million and office space of $80 million . (2) Finance lease ROU assets include office space of $90 million and a trunkline of $28 million , both net of accumulated amortization. Statement of Operations Information The components of lease cost are as follows: (millions) Statement of Operations Location Year Ended December 31, 2019 Operating Lease Cost Various (1) $ 110 Finance Lease Cost Amortization Expense Depreciation, Depletion and Amortization 38 Interest Expense Interest, Net of Amount Capitalized 13 Short-term Lease Cost (2) Various (1) 424 Sublease Income General and Administrative (5 ) Total Lease Cost $ 580 (1) Cost classifications vary depending on the leased asset. Costs are primarily included within production expense and general and administrative expense. In addition, in accordance with the successful efforts method of accounting, certain lease costs may be capitalized when incurred and therefore, are included as part of oil and gas properties on our consolidated balance sheets. (2) Costs primarily relate to hydraulic fracturing services, well-to-well drilling rig contracts and other miscellaneous lease agreements. Amount excludes costs for leases with an initial term of one month or less. Cash Flow Information Supplemental cash flow information is as follows: Year Ended December 31, 2019 (millions) Operating Leases Finance Leases Cash Paid for Amounts Included in the Measurement of Lease Liabilities Operating Cash Flows $ 74 $ 12 Investing Cash Flows 36 — Financing Cash Flows — 42 Non-Cash Activities ROU Assets Obtained in Exchange for Lease Liabilities (1) 127 26 (1) Amounts exclude the impact of adopting ASC 842 on January 1, 2019. See Note 1. Summary of Significant Accounting Policies . Annual Lease Maturities As of December 31, 2019 , maturities of lease liabilities were as follows: (millions) Operating Leases Finance Leases Total 2020 $ 100 $ 52 $ 152 2021 60 38 98 2022 41 27 68 2023 26 23 49 2024 15 21 36 2025 and Thereafter 37 86 123 Total Lease Liabilities, Undiscounted 279 247 526 Less: Imputed Interest 27 42 69 Total Lease Liabilities (1) $ 252 $ 205 $ 457 (1) Includes the current portions of $ 88 million and $ 42 million for operating and finance leases, respectively. Lease Commitments See Note 12. Commitments and Contingencies for lease commitments as of December 31, 2019 . Other Information As of December 31, 2019 , other information related to our leases is as follows: Operating Leases Finance Leases Weighted-Average Remaining Lease Term 4.9 years 7.5 years Weighted-Average Discount Rate 4.05 % 4.96 % |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2019 | |
Debt Disclosure [Abstract] | |
Long-term Debt | Note 8. Long-Term Debt Our debt consists of the following: December 31, 2019 December 31, 2018 (millions, except percentages) Debt Interest Rate Debt Interest Rate Noble Energy, Excluding Noble Midstream Partners Revolving Credit Facility, due March 9, 2023 $ — — % $ — — % Commercial Paper Borrowings — — % — — % Senior Notes, due December 15, 2021 — — % 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 October 15, 2029 500 3.25 % — — % 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 % Senior Notes, due October 15, 2049 500 4.20 % — — % Senior Debentures 84 7.25 % 92 7.13 % Finance Lease Obligations 205 — % 223 — % Total Noble Energy Debt, Excluding Noble Midstream Partners Debt 6,089 6,115 Noble Midstream Partners Noble Midstream Services Revolving Credit Facility, due March 9, 2023 595 3.11 % 60 3.67 % Noble Midstream Services Term Loan Credit Facility, due July 31, 2021 500 2.85 % 500 3.42 % Noble Midstream Services Term Loan Credit Facility, due August 23, 2022 400 2.74 % — — % Total Noble Midstream Partners Debt 1,495 560 Total Debt 7,584 6,675 Net Unamortized Discounts and Debt Issuance Costs (65 ) (60 ) Total Debt, Net of Unamortized Discounts and Debt Issuance Costs $ 7,519 $ 6,615 Less Amounts Due Within One Year: Finance Lease Obligations (42 ) (41 ) Long-Term Debt Due After One Year $ 7,477 $ 6,574 Revolving Credit Facility Our Credit Agreement, as amended, provides for a $ 4.0 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, 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. As of December 31, 2019 , we were in compliance with our debt covenants and no amounts were outstanding under our Revolving Credit Facility. Commercial Paper Program Our commercial paper program provides for short-term funding needs. The program allows Noble Energy to issue a maximum of $4.0 billion of unsecured commercial paper notes and is supported by Noble Energy’s $ 4.0 billion Revolving Credit Facility. Our commercial paper notes, which generally have a maturity of less than 30 days, are sold under customary terms in the commercial paper market and are generally issued at a discounted price relative to the principal face value. Such discount prices are dependent on market conditions and ratings assigned to the commercial paper program by credit rating agencies at the time of commercial paper issuance. As of December 31, 2019 , we had no outstanding commercial paper borrowings. Senior Notes Issuance and Completed Tender Offer On October 1, 2019, we issued $500 million of 3.25% senior notes due October 15, 2029 and $500 million of 4.20% senior notes due October 15, 2049. Interest on the notes is payable semi-annually beginning April 15, 2020. We may redeem some or all of the notes at any time at the applicable redemption price, plus accrued interest, if any. Proceeds from the issuance of the notes were used to fund the tender offer and redemption of our $1.0 billion 4.15% notes due December 15, 2021. In connection with the tender and redemption, in fourth quarter 2019, we recorded early debt extinguishment cost of approximately $44 million in our consolidated statements of operations. Noble Midstream Services Revolving Credit Facility Noble Midstream Services LLC (Noble Midstream Services), a subsidiary of Noble Midstream Partners, maintains a 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 fourth quarter 2019, the capacity of the facility was increased from $800 million to almost $ 1.2 billion. As of December 31, 2019 , $555 million was available for borrowing under the Noble Midstream Services Revolving Credit Facility. All obligations of Noble Midstream Services, as the borrower under the Noble Midstream Services Revolving Credit Facility, are guaranteed by Noble Midstream Partners and all wholly-owned material subsidiaries of Noble Midstream Partners. Noble Midstream Services was in compliance with the debt covenants for this facility as of December 31, 2019 . Noble Midstream Services 2019 Term Loan Credit Facility On August 23, 2019, Noble Midstream Services entered into a term loan agreement (Noble Midstream Services 2019 Term Credit Agreement), which provides for a three-year senior unsecured term loan credit facility due August 23, 2022 (2019 Term Loan Credit Facility) with permitted aggregate borrowings of up to $400 million . Proceeds from the 2019 Term Loan Credit Facility were primarily used to repay a portion of the outstanding borrowings under the Noble Midstream Services Revolving Credit Facility. Noble Midstream Services was in compliance with the debt covenants for this facility as of December 31, 2019 . Noble Midstream Services 2018 Term Loan Credit Facility In 2018, Noble Midstream Services entered into a term loan agreement (Noble Midstream Services 2018 Term Credit Agreement), which provides for a three-year senior unsecured term loan credit facility due July 31, 2021 (2018 Term Loan Credit Facility) with permitted aggregate borrowings of up to $ 500 million . Proceeds from the 2018 Term Loan Credit Facility were primarily used to repay a portion of the outstanding borrowings under the Noble Midstream Services Revolving Credit Facility. Noble Midstream Services was in compliance with the debt covenants for this facility as of December 31, 2019 . Fair Value of Debt The fair value of fixed-rate, public debt is estimated based on the published market prices. As such, we consider the fair value of this debt to be a Level 1 measurement on the fair value hierarchy. Our non-public debt, including our Revolving Credit Facility, commercial paper borrowings, Noble Midstream Services Revolving Credit Facility and Noble Midstream Services term loans are subject to variable interest rates. The fair value is estimated based on significant other observable inputs; thus, we consider the fair value to be a Level 2 measurement on the fair value hierarchy. Fair value information regarding our debt is as follows: December 31, 2019 December 31, 2018 (millions) Carrying Amount Fair Value Carrying Amount Fair Value Debt $ 7,379 $ 8,033 $ 6,452 $ 6,121 Annual Debt Maturities As of December 31, 2019 , annual maturities of outstanding debt, excluding finance lease obligations, were as follows: Debt Principal Payments (millions) Noble Energy Excluding Noble Midstream Partners Noble Midstream Partners Total 2020 $ — $ — $ — 2021 — 500 500 2022 — 400 400 2023 100 595 695 2024 650 — 650 Thereafter 5,134 — 5,134 Total $ 5,884 $ 1,495 $ 7,379 Finance Lease Obligations See Note 9. Leases . |
Impairments
Impairments | 12 Months Ended |
Dec. 31, 2019 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Impairments | Note 10. Impairments 2019 Impairments In fourth quarter 2019, we determined that the continued depressed commodity price environment and performance of certain of our US onshore basins indicated possible impairment of our proved oil and gas properties in our US onshore business. Following our impairment analysis, we recorded impairment expense of $ 1.2 billion to our Eagle Ford Shale proved properties, primarily as a result of significant decreases in NGL and natural gas prices, partially offset by lower capital and operating costs. The fair value of approximately $600 million was estimated using the income approach, utilizing a discounted cash flow model. The cash flow model included management's estimates of future production, commodity prices based on published forward commodity price curves, operating and development costs, and a risk-adjusted discount rate. As of December 31, 2019 , we had $ 100 million of undeveloped leasehold costs related to our Eagle Ford Shale unproved properties that were not impaired and for which we believe future development scenarios exist to recover these costs. 2018 Impairments In 2018, upon classification of the Gulf of Mexico properties as assets held for sale, we recognized impairment expense of $168 million . Additionally, in fourth quarter 2018, we recorded impairment expense of $38 million , $37 million of which related to changes in construction plans for certain midstream assets. In fourth quarter 2018, we considered changes to facts and circumstances, particularly the decline in WTI strip pricing, increases in operating and capital costs, as well as our development plans, and concluded that it was more likely than not that the fair value of our Texas reporting unit was less than its carrying amount. As a result, we recognized a goodwill impairment of $1.3 billion . 2017 Impairments In 2017, we recorded impairment expense of $70 million |
Exit Cost - Transportation Comm
Exit Cost - Transportation Commitments | 12 Months Ended |
Dec. 31, 2019 | |
Commitments and Contingencies Disclosure [Abstract] | |
Exit Cost — Transportation Commitments | Note 11. Exit Cost – Transportation Commitments In connection with the divestiture of Marcellus Shale upstream assets in 2017, we retained certain long-term financial commitments to pay transportation fees on certain pipelines in the Marcellus Basin. As of December 31, 2019 , our undiscounted financial commitment for the remaining obligations under these agreements, which have remaining terms of three to fourteen years , was approximately $1.0 billion , which excludes the impact of ongoing mitigation activities to reduce and offset this cost. See Note 4. Acquisitions and Divestitures and Note 12. Commitments and Contingencies . Our efforts to mitigate and thereby reduce these obligations primarily include permanent assignment of capacity, negotiation of capacity releases and utilization of capacity through purchase and transport of third-party natural gas. Revenues and expenses associated with mitigation activities are recorded in sales of purchased oil and gas and cost of purchased oil and gas, respectively, in our consolidated statements of operations. In the event we execute a permanent assignment of capacity, we no longer have a contractual obligation to the pipeline company and, as such, our gross financial commitment is reduced. In the event we execute a capacity release or utilize the capacity through the purchase and transport of third-party natural gas, we remain the primary obligor to the pipeline company. While our gross financial commitment is not reduced, except through use under those arrangements, we would receive future cash payments from the third-parties with whom we negotiated a capacity release or from the sale of purchased natural gas to third-parties. As a result of our mitigation activities, we reduced and offset our financial obligations by approximately $38 million and $8 million in 2019 and 2018, respectively. Leach Xpress and Rayne Xpress Permanent Assignment In January 2019, we executed agreements on the Leach Xpress and Rayne Xpress pipelines to permanently assign the remaining capacity to a third-party effective January 1, 2021, extending through the remainder of the contract. The permanent assignment reduced our total financial commitment by approximately $350 million , undiscounted. As a result of the assignment, we recorded firm transportation exit cost at a fair value $92 million , representing the discounted, present value of our remaining obligation to the third-party. We will continue efforts to mitigate the impact of these transportation agreements through 2020. Exit Costs Reconciliation of accrued exit costs at December 31, 2019 is as follows: December 31, (millions) 2019 2018 Balance at Beginning of Period $ 80 $ 90 Exit Cost Accrual (1) 88 — Payments, Net of Accretion (5 ) (10 ) Balance at End of Period $ 163 $ 80 Less Current Portion Included in Other Current Liabilities 34 13 Long-term Portion Included in Other Noncurrent Liabilities $ 129 $ 67 (1) Amount includes $92 million exit cost for the permanent assigned discussed above, offset by a gain of $4 million . Revenues and expenses associated with these long-term financial commitments, including mitigation activities discussed above, were as follows: Year Ended December 31, (millions) 2019 2018 2017 Sales of Purchased Gas $ 90 $ 113 $ — Cost of Purchased of Gas 85 108 — Utilized Firm Transportation Expense 57 29 — Unutilized Firm Transportation Expense 1 3 — Cost of Purchased Gas, Total $ 143 $ 140 $ — |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2019 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Note 12. Commitments and Contingencies Legal Proceedings We are involved in various legal proceedings in the ordinary course of business. These proceedings are subject to the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters and we believe that the ultimate disposition of such proceedings will not have a material adverse effect on our financial position, results of operations or cash flows. Colorado Air Matter In April 2015, we entered into a joint consent decree (Consent Decree) with the US Environmental Protection Agency (EPA), 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. Costs associated with the settlement consist of $5 million in civil penalties which were paid in 2015. Mitigation costs of $4 million and supplemental environmental project costs of $4 million are being expended in accordance with schedules established in the Consent Decree. Costs associated with the injunctive relief, including plugging and abandonment of certain wells and facilities, are also being expended in accordance with schedules established in the Consent Decree. We have concluded that the penalties, injunctive relief and mitigation expenditures that result from this settlement, based on currently available information, will not have a material adverse effect on our financial position, results of operations or cash flows. See Note 7. Asset Retirement Obligations . Colorado Water Quality Control Division Matter In October 2019, we resolved by Compliance Order on Consent (COC) with the Colorado Department of Public Health & Environment allegations of noncompliance with the Colorado Water Quality Act relating 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. The COC required us to pay a penalty of $57 thousand and to contribute $126 thousand toward a State-managed supplemental environmental project. We have concluded that the resolution of this action did not have a material adverse effect on our financial position, results of operations or cash flows. Colorado Clean Water Act Referral Notice In September 2018, we received a letter from the US Department of Justice providing notification of referral from the EPA of alleged Clean Water Act violations at an upstream production facility and a midstream gathering facility in Weld County, Colorado. In April 2019, we met with the DOJ and Environmental Protection Agency enforcement personnel to discuss potential settlement of the alleged violations. Given the ongoing status of settlement discussions, we are currently unable to predict the ultimate outcome of this action, but believe the resolution will not have a material adverse effect on our financial position, results of operations or cash flows. Marcellus Shale Firm Transportation Obligations As part of our Marcellus Shale upstream divestiture, we retained certain transportation obligations to flow Marcellus Shale natural gas production to various markets. See Note 11. Exit Cost – Transportation Commitments . Other Gathering and Transportation Obligations As part of our normal course of business, we enter into agreements to transport minimum volumes in the US onshore and Eastern Mediterranean. In the US onshore, primarily in the DJ Basin, 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 and will incur expense related to volume deficiencies and/or unutilized commitments. We expect to continue to incur expense related to deficiency and/or unutilized commitments in the near-term. These amounts are recorded as marketing expense in our consolidated statements of operations. In the Eastern Mediterranean, regional export contracts contain minimum transportation commitments. For US onshore and Eastern Mediterranean agreements, which have remaining terms of one to 12 years , our total financial commitment is approximately $ 921 million, undiscounted. The commitments are included in the table below. Mezzanine Equity Commitment In March 2019, Noble Midstream Partners obtained a $200 million preferred equity commitment. $100 million of the commitment funded immediately and the remaining $100 million is available for funding until March 2020, subject to certain conditions precedent. See Note 1. Summary of Significant Accounting Policies and Note 4. Acquisitions and Divestitures . Minimum Commitments Minimum commitments as of December 31, 2019 consist of the following: (millions) Purchase and Service Obligations Marcellus Shale Firm Transportation Obligations (1) Gathering, Transportation & Processing Obligations (2) Operating Lease Obligations (3) Finance Lease Obligations (3) Total 2020 $ 135 $ 143 $ 174 $ 100 $ 52 $ 604 2021 28 102 176 60 38 404 2022 14 85 156 41 27 323 2023 30 83 153 26 23 315 2024 2 92 149 15 21 279 2025 and Thereafter 72 675 334 37 86 1,204 Total $ 281 $ 1,180 $ 1,142 $ 279 $ 247 $ 3,129 (1) Amount includes exit cost obligations resulting from permanent capacity assignments. See Note 11. Exit Cost – Transportation Commitments . (2) Amount includes US onshore and Eastern Mediterranean transportation obligations of $ 921 million, undiscounted, and Noble Midstream Partners obligations of $221 million, undiscounted. (3) See Note 9. Leases . |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Note 13. Income Taxes Components of (loss) income from operations before income taxes are as follows: Year Ended December 31, (millions) 2019 2018 2017 Domestic $ (2,222 ) $ (953 ) $ (2,831 ) Foreign 446 1,093 640 Total $ (1,776 ) $ 140 $ (2,191 ) Income Tax Provision The income tax (benefit) provision consists of the following: Year Ended December 31, (millions, except percentages) 2019 2018 2017 Current Taxes Federal $ 1 $ 22 $ (11 ) State 3 2 1 Foreign 81 172 96 Total Current $ 85 $ 196 $ 86 Deferred Taxes Federal $ (413 ) $ (123 ) $ (1,258 ) State (25 ) (7 ) (8 ) Foreign 10 60 39 Total Deferred $ (428 ) $ (70 ) $ (1,227 ) Total Income Tax (Benefit) Provision Attributable to Noble Energy $ (343 ) $ 126 $ (1,141 ) Effective Tax Rate 19.3 % 90.0 % 52.1 % The 2019 deferred income tax benefit relates to the asset impairment recorded in fourth quarter 2019. See Note 10. Impairments . The 2018 income tax provision is primarily due to current income tax expense for foreign taxes on the gain recognized for the 2018 divestiture of a 7.5% working interest in the Tamar field, partially offset by a deferred income tax benefit. The 2017 income tax benefit is due to the significant deferred tax benefit associated with the revaluation of the US deferred tax liability as a result of the reduction in the federal corporate tax rate to 21%. Effective Tax Rate (ETR) A reconciliation of the federal statutory tax rate to the ETR is as follows: Year Ended December 31, (percentages) 2019 2018 2017 Federal Statutory Rate 21.0 % 21.0 % 35.0 % Effect of Goodwill Impairment — 192.5 — Change in Valuation Allowance (0.6 ) (170.2 ) (17.4 ) US and Foreign Statutory Rate Change — 80.7 23.5 Accumulated Undistributed Foreign Earnings — — 11.0 Transition Tax — — (4.8 ) Difference Between US and Foreign Rates (0.6 ) 17.9 1.8 Earnings of Equity Method Investments 0.7 (20.1 ) 1.9 Noncontrolling Interests 0.9 (12.1 ) 1.1 State Taxes 1.1 0.9 0.3 Foreign Exploration Loss — (35.6 ) — Global Intangible Low-Taxed Income (GILTI) (0.8 ) 24.2 — Return to Provision — (17.1 ) (0.1 ) Audit Settlement — 5.1 0.1 Oil Profits Tax - Israel (0.1 ) 3.3 (0.1 ) Other, Net (2.3 ) (0.5 ) (0.2 ) Effective Rate 19.3 % 90.0 % 52.1 % There were no material items impacting our 2019 ETR as compared to the federal statutory rate of 21%. Our 2018 ETR included a significant deferred tax benefit, discussed below, recorded as a result of the intent of the US Department of the Treasury (Treasury) and Internal Revenue Service (IRS) to issue additional regulatory guidance associated with the Tax Cuts and Jobs Act (Tax Reform Legislation) and the transition tax. In addition, the 2018 ETR was impacted by low earnings, goodwill impairment with no tax benefit, deferred tax expense of $34 million related to GILTI, discussed below, and a deferred tax benefit of $50 million associated with a write-off of foreign exploration losses. Our 2017 ETR was driven by the deferred tax benefit related to the Tax Reform Legislation, as we revalued the ending deferred tax liability at the reduced future tax rate. Deferred Tax Assets and Liabilities Deferred tax assets and liabilities resulted from the following: December 31, (millions) 2019 2018 Deferred Tax Assets Loss Carryforwards (1) $ 656 $ 589 Employee Compensation and Benefits 92 92 Mark to Market of Commodity Derivative Instruments 11 (27 ) Foreign Tax Credits 133 138 Other 126 157 Total Deferred Tax Assets $ 1,018 $ 949 Valuation Allowance - Foreign Loss Carryforwards and Foreign Tax Credits (327 ) (320 ) Net Deferred Tax Assets $ 691 $ 629 Deferred Tax Liabilities Property, Plant and Equipment, Principally Due to Differences in Depreciation, Amortization, Lease Impairment and Abandonments (1,338 ) (1,669 ) Total Deferred Tax Liability $ (1,338 ) $ (1,669 ) Net Deferred Tax Liability $ (647 ) $ (1,040 ) (1) At December 31, 2019, $459 million related to domestic tax (state and federal) and $197 million related to foreign tax. Net deferred tax assets and liabilities were classified in the consolidated balance sheets as follows: December 31, (millions) 2019 2018 Deferred Income Tax Asset - Noncurrent $ 15 $ 21 Deferred Income Tax Liability - Noncurrent (662 ) (1,061 ) Net Deferred Tax Liability $ (647 ) $ (1,040 ) Our estimated pre-tax net operating loss (NOL) carryforwards totaled approximately $2.7 billion at December 31, 2019 , of which US federal income tax NOL carryforwards totaled approximately $2.0 billion and foreign NOL carryforwards totaled $691 million . We currently have a valuation allowance on the deferred tax assets associated with foreign loss carryforwards and foreign tax credits. The valuation allowance on foreign loss carryforwards totaled $192 million and $187 million in 2019 and 2018 , respectively. The valuation allowance on foreign tax credits totaled $133 million and $132 million in 2019 and 2018 , respectively. Accumulated Undistributed Earnings of Foreign Subsidiaries As of December 31, 2019, there is no expected withholding tax impact upon actual distribution of earnings and as such, we have not recorded any tax associated with unremitted earnings. Tax Reform Legislation Updates Since the enactment of Tax Reform Legislation by the US Congress in December 2017, Treasury and the IRS have periodically issued guidance regarding various aspects of the new law. Global Intangible Low-Taxed Income (GILTI) Tax Reform Legislation introduced a new tax on GILTI. Further analysis and legal interpretation has resulted in identifying certain foreign oil related income (FORI) activity as GILTI income which will be offset by NOL carryforwards rather than the 50% deduction and related foreign tax credits. As a result of utilizing our NOL to offset the GILTI inclusion, for 2019 and 2018, we recognized tax expense of $14 million and $34 million , respectively, of GILTI associated with FORI from investments in Equatorial Guinea and Israel. In June 2019, Treasury and the IRS released new proposed regulations pertaining to GILTI, which include an election that would apply an elective high-tax exception to GILTI when the tax imposed on a tentative net tested income item exceeds an 18.5% corporate tax rate. The applicability of the high-tax exception would be tested at the level of a single qualified business unit (QBU) and would apply to all foreign corporations controlled by the same domestic shareholders. This regulation is applicable to taxable years beginning on or after the date that final regulations are published in the Federal Register. For us, this high tax exception would have the effect of reclassifying all GILTI into another classification of income, thus eliminating the GILTI/NOL offset item described above. We will continue to monitor the development of this proposed regulation. Transition Tax (Toll Tax) Tax Reform Legislation provided for a toll tax on a one-time “deemed repatriation” of accumulated foreign earnings for the year ended December 31, 2017. In April 2018, the Treasury and the IRS released Notice 2018-26, signaling intent to issue regulations related to the toll tax for the year ended December 31, 2017. This notice clarified that an Internal Revenue Code Section 965(n) election is available with respect to both current and prior year NOLs. As a result, we released $252 million of the valuation allowance recorded against foreign tax credits to be utilized against the estimated $268 million toll tax liability recorded as of December 31, 2017. This resulted in a $252 million tax benefit and a corresponding expense of $107 million for the tax rate change adjustment on the previously utilized NOLs. The impact on first quarter 2018 total tax expense, related to this additional guidance, was a net $145 million discrete tax benefit. During fourth quarter 2018, the toll tax calculations were finalized in conjunction with filing of the US tax return, resulting in a $261 million toll tax against which $240 million of foreign tax credits were utilized. This resulted in a $21 million liability payable in installments over eight years beginning in 2018. Other Provisions Tax Reform Legislation broadened the former Section 163(j) applying a net interest expense limitation equal to 30% of earnings before interest, taxes, depreciation, and amortization (EBITDA) for tax years beginning after December 31, 2017, and before January 1, 2022, after which the net interest expense limitation will be calculated as 30% of earnings before interest and taxes (EBIT). Disallowed interest may be carried forward indefinitely. In November 2018, Treasury and the IRS released proposed regulations pertaining to section 163(j) which state that any amount normally incurred as deductible DD&A, but included in a taxpayer’s cost of goods sold calculation pursuant to section 263A, is not a deduction for DD&A for purposes of determining Adjusted Taxable Income for years beginning prior to January 1, 2022. We have modified our 163(j) limitation calculation to comply and will continue to monitor the development of this proposed regulation. Israeli Tax Law Our Israeli operations are subject to the Natural Resources Profits Taxation Law, 2011 (the Law), which imposes a separate additional tax on profits from oil and gas activities (Oil Profits Tax). The Oil Profits Tax is calculated by dividing net accumulated revenue generated by each separate project by its cumulative investments as defined within the Law. Once the revenue factor (R Factor) reaches 1.5, a tax rate of 20% is imposed; as the ratio increases to a maximum of 2.3, the Oil Profits Tax increases progressively up to a maximum rate of 50%. The Oil Profits Tax provides for a corporate tax rate adjustment based on the corporate income tax rate, which is currently 23%. To the extent the corporate income tax rate exceeds 18%, a reduction in the Oil Profits Tax rate is calculated. At the current corporate tax rate, the Oil Profits Tax rate is 46.8% . The Oil Profits Tax is deductible for Israeli corporate tax purposes. Our Tamar and Leviathan projects are both subject to the Oil Profits Tax and are expected to pay at the maximum rate. Clayton Williams Energy Acquisition In April 2017, we completed the Clayton Williams Energy Acquisition, which qualified as a tax free merger, and acquired carryover tax basis in Clayton Williams Energy's assets and liabilities. As part of our purchase price allocation we recorded a deferred tax liability of $307 million , adjusted for the new US statutory rate, which includes a deferred tax asset for federal pre-tax NOLs of approximately $450 million . The merger resulted in a change of control for federal income tax purposes, and the NOL usage will be subject to an annual limitation in part based on Clayton Williams Energy's value at the date of the merger. Unrecognized Tax Benefits We file a consolidated income tax return in the US federal jurisdiction, and we file income tax returns in various states and foreign jurisdictions. Our income tax returns are routinely audited by the applicable revenue authorities, and provisions are made in the financial statements for differences between positions taken in tax returns and amounts recognized in the financial statements in anticipation of audit results. In our major tax jurisdictions, the earliest years remaining open to examination are: US - 2014 , Israel - 2015 (2013 with respect to Israel Oil Profits Tax) and Equatorial Guinea - 2013 . Our policy is to recognize any interest and penalties related to unrecognized tax benefits in income tax expense. As of December 31, 2019 and 2018 |
Derivative Instruments and Hedg
Derivative Instruments and Hedging Activities | 12 Months Ended |
Dec. 31, 2019 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Instruments and Hedging Activities | Note 14. Derivative Instruments and Hedging Activities Objective and Strategies for Using Derivative Instruments We enter into price hedging arrangements in an effort to mitigate the effects of commodity price volatility and enhance the predictability of cash flows relating to the marketing of a portion of our production. The derivative instruments we use may include variable to fixed price commodity swaps, enhanced swaps, collars and three-way collars, sold calls and sold puts, basis swaps, swaptions and/or put options. The fixed price swap and collar contracts entitle us (floating price payor) to receive settlement from the counterparty (fixed price payor) for each calculation period in amounts, if any, by which the settlement price for the scheduled trading days applicable for each calculation period is less than the fixed strike price or floor price. We would pay the counterparty if the settlement price for the scheduled trading days applicable for each calculation period is more than the fixed strike price or ceiling price. The amount payable by us, if the floating price is above the fixed or ceiling price, is the product of the notional quantity per calculation period and the excess of the floating price over the fixed or ceiling price in respect of each calculation period. The amount payable by the counterparty, if the floating price is below the fixed or floor price, is the product of the notional quantity per calculation period and the excess of the fixed or floor price over the floating price in respect of each calculation period. A three-way collar consists of a collar contract combined with a put option contract sold by us with a strike price below the floor price of the collar. We receive price protection at the purchased put option floor price of the collar if commodity prices are above the sold put option strike price. If commodity prices fall below the sold put option strike price, we receive the cash market price plus the difference between the two put option strike prices. This type of instrument allows us to capture more value in a rising commodity price environment, but limits our benefits in a downward commodity price environment. A swaption gives counterparties the right, but not the obligation, to enter into swap agreements with us on the option expiration dates. Sold calls are entered into to receive premiums for establishing a maximum price that would be settled for the notional volumes covered by the respective contracts. Sold puts are entered into to receive premiums for establishing a minimum price that would be settled for the notional volumes covered by basis swap contracts. While these instruments mitigate the cash flow risk of future reductions in commodity prices, they may also curtail benefits during periods of increasing commodity prices. Additionally, derivative instruments expose us to counterparty credit risk, especially during periods of falling prices. Our commodity derivative instruments are currently with a diversified group of major banks or market participants. We monitor the creditworthiness of these counterparties and our internal hedge policies provide for exposure limits. Unsettled Commodity Derivative Instruments As of December 31, 2019 , we had entered into the following crude oil derivative instruments: Swaps Collars Settlement Period Type of Contract Index Bbls per Day Weighted Average Differential Weighted Average Fixed Price Weighted Average Short Put Price Weighted Average Floor Price Weighted Average Ceiling Price 2020 Sold Calls NYMEX WTI 8,000 $ — $ 65.59 $ — $ — $ — 2020 Swaps NYMEX WTI 35,000 — 58.12 — — — 2020 Three-Way Collars NYMEX WTI 30,000 — — 48.33 57.87 64.27 Jan2020-Jun2020 Swaps NYMEX WTI 24,000 — 59.54 — — — Jul2020-Dec2020 Call Swaption NYMEX WTI 11,000 — 58.95 — — — 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. As of December 31, 2019 , we had entered into the following NGL derivative instruments: Swaps Settlement Period Type of Contract Index Bbls per Day Weighted Average Fixed Price Apr 2020-Sept 2020 Ethane Swaps Mont Belvieu 2,000 $ 7.77 Apr 2020-Sept 2020 Propane Swaps Mont Belvieu 5,000 21.04 Apr 2020-Sept 2020 Isobutane Swaps Mont Belvieu 1,000 25.36 Apr 2020-Sept 2020 Butane Swaps Mont Belvieu 1,500 24.31 As of December 31, 2019 , we had entered into the following natural gas derivative instruments: Swaps Collars Settlement Period Type of Contract Index MMBtu per Day Weighted Average Differential Weighted Average Fixed Price Weighted Average Short Put Price Weighted Average Floor Price Weighted Average Ceiling Price Apr2020-Dec2020 Swaps NYMEX HH 90,000 $ — $ 2.60 $ — $ — $ — Apr2020-Oct2020 Three-Way Collars NYMEX HH 40,000 — — 2.25 2.70 2.85 2020 Sold Puts NYMEX HH 90,000 — — 2.15 — — 2020 Basis Swaps CIG (1) 139,000 (0.56 ) — — — — 2020 Basis Swaps Waha (1) 49,500 (1.05 ) — — — — 2021 Basis Swaps CIG (1) 60,000 (0.52 ) — — — — 2021 Basis Swaps Waha (1) 14,000 (0.60 ) — — — — (1) We have entered into natural gas basis swap contracts in order to establish a fixed amount for the differential between index pricing for Colorado Interstate Gas (CIG) and Waha Hub versus NYMEX Henry Hub (HH). The weighted average differential represents the amount of reduction to NYMEX HH prices for the notional volumes covered by the basis swap contracts. Fair Value Amounts and Gains and Losses on Derivative Instruments The fair values of derivative instruments on our consolidated balance sheets were as follows (in millions): Asset Derivative Instruments Liability Derivative Instruments Balance Sheet Location December 31, 2019 December 31, 2018 Balance Sheet Location December 31, 2019 December 31, 2018 Other Current Assets $ 14 $ 180 Other Current Liabilities $ 36 $ 1 Other Noncurrent Assets 1 — Other Noncurrent Liabilities 1 26 Total Assets $ 15 $ 180 Total Liabilities $ 37 $ 27 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 London Inter-bank Offered Rate (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 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 considers market volatility, market prices and contract terms. Amounts include the impact of netting clauses within our master agreements that allow us to net cash settle asset and liability positions with the same counterparty. The effect of derivative instruments on our consolidated statements of operations was as follows: Year Ended December 31, (millions) 2019 2018 2017 Cash (Received) Paid in Settlement of Commodity Derivative Instruments Crude Oil $ (10 ) $ 162 $ (14 ) Natural Gas (22 ) (1 ) 1 Total Cash (Received) Paid in Settlement of Commodity Derivative Instruments (32 ) 161 (13 ) Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments Crude Oil 184 (225 ) 18 NGLs (3 ) — — Natural Gas (6 ) 1 (68 ) Total Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments 175 (224 ) (50 ) Loss (Gain) on Commodity Derivative Instruments Crude Oil 174 (63 ) 4 NGLs (3 ) — — Natural Gas (28 ) — (67 ) Total Loss (Gain) on Commodity Derivative Instruments $ 143 $ (63 ) $ (63 ) |
Additional Shareholders' Equity
Additional Shareholders' Equity Information | 12 Months Ended |
Dec. 31, 2019 | |
Equity [Abstract] | |
Additional Shareholders' Equity Information | Note 15. Additional Shareholders’ Equity Information Common Stock and Treasury Stock Activity in shares of our common stock and treasury stock was as follows: Year Ended December 31, 2019 2018 Shares of Common Stock Issued Shares, Beginning of Period 521,055,001 528,743,381 Exercise of Common Stock Options — 576,617 Restricted Stock Awarded, Net of Forfeitures 2,768,731 2,488,363 Purchase and Retirement of Common Stock (1) — (10,008,128 ) Adjustment to Shares Exchanged in Clayton Williams Energy Acquisition — (745,232 ) Shares, End of Period 523,823,732 521,055,001 Treasury Stock Shares, Beginning of Period 38,851,988 38,786,969 Shares Received in Payment of Withholding Taxes Due on Vesting of Shares of Restricted Stock 240,865 267,258 Rabbi Trust Shares Distributed and/or Sold (203,063 ) (202,239 ) Shares, End of Period 38,889,790 38,851,988 Additional Information Incremental Shares From Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust — — Number of Antidilutive Stock Options, Shares of Restricted Stock and Shares of Common Stock in Rabbi Trust excluded from Dilutive Earnings (Loss) per Share (2) 13,892,742 15,004,591 (1) On February 15, 2018, we announced that the Company's Board of Directors had authorized a share repurchase program of $750 million which expires December 31, 2020. In 2019, no shares were repurchased and retired. In 2018 , shares were repurchased and retired at an average price of $29.49 per share. (2) For the years ended December 31, 2019 and 2018 , all outstanding options and non-vested restricted shares have been excluded from the calculation of diluted earnings (loss) per share as Noble Energy incurred a loss. Therefore, inclusion of outstanding options and non-vested restricted shares in the calculation of diluted earnings (loss) per share would be anti-dilutive. Accumulated Other Comprehensive Loss (AOCL) AOCL in the shareholders’ equity section of the balance sheet included: (millions) Interest Rate Cash Flow Hedge Other Postretirement Benefit Plans Total December 31, 2016 $ (21 ) $ (10 ) $ (31 ) Realized Amounts Reclassified Into Earnings 1 4 5 Unrealized Change in Fair Value — (4 ) (4 ) December 31, 2017 (20 ) (10 ) (30 ) Realized Amounts Reclassified Into Earnings (3 ) 1 (2 ) December 31, 2018 (23 ) (9 ) (32 ) Realized Amounts Reclassified Into Earnings 1 — 1 December 31, 2019 $ (22 ) $ (9 ) $ (31 ) Items in AOCL were initially recorded net of tax, using an effective income tax rate of 35% . In fourth quarter 2018, we reclassified to retained earnings approximately $6 million representing the effect of the decrease in the income tax rate to 21% . AOCL at December 31, 2019 included deferred losses of $22 million |
Stock-Based and Other Compensat
Stock-Based and Other Compensation Plans | 12 Months Ended |
Dec. 31, 2019 | |
Share-based Payment Arrangement [Abstract] | |
Stock-Based and Other Compensation Plans | Note 16. Stock-Based and Other Compensation Plans We recognized total stock-based compensation expense as follows: Year Ended December 31, (millions) 2019 2018 2017 General and Administrative Expense $ 59 $ 54 $ 56 Exploration Expense and Other 9 8 48 Total Stock-Based Compensation Expense (1) $ 68 $ 62 $ 104 Tax Benefit Recognized $ (14 ) $ (13 ) $ (36 ) (1) 2019 amount excludes $8 million capitalized to property, plant and equipment. Stock Option and Restricted Stock Plans Our stock option and restricted stock plans are described below. 2017 Long-Term Incentive Plan On April 25, 2017, our shareholders approved the Noble Energy, Inc. 2017 Long-Term Incentive Plan (the 2017 Plan). Upon shareholder approval, the 2017 Plan superseded and replaced the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan, as amended (the 1992 Plan) which was frozen so that no future grants would be made under the 1992 Plan. The 1992 Plan continues to govern awards that were outstanding as of the date of its suspension, which remain in effect pursuant to their terms. Under the 2017 Plan, the Compensation, Benefits and Stock Option Committee of the Board of Directors (the Committee) may grant stock options, stock appreciation rights, restricted stock, restricted stock units, performance awards, stock awards and other incentive awards to our officers or other employees and those of our subsidiaries. The maximum number of shares that may be granted under the 2017 Plan is 44 million shares of common stock. At December 31, 2019 , 39,693,735 shares of our common stock were reserved for issuance, including 28,407,839 shares available for future grants and awards, under the 2017 Plan. Stock options are issued with an exercise price equal to the fair market value of our common stock on the date of grant, and are subject to such other terms and conditions as may be determined by the Committee. Unless granted by the Committee for a shorter term, the options expire 10 years from the grant date. Option grants generally vest ratably over a three -year period. Restricted stock awards made under the 2017 Plan are subject to such restrictions, terms and conditions, including forfeitures, if any, as may be determined by the Committee. During the period in which such restrictions apply, unless specifically provided otherwise in accordance with the terms of the 2017 Plan, the recipient of restricted stock would be the record owner of the shares and have all the rights of a shareholder with respect to the shares, including the right to vote and the right to receive dividends or other distributions made or paid with respect to the shares. The dividends or other distributions pertaining to the restricted shares will be held by the Company until the restriction period ends and the shares vest or forfeit. If the restricted shares forfeit, then the recipient shall not be entitled to receive the dividend or distribution, which will transfer to the Company. Restricted stock awards with a time-vested restriction vest over a two or three -year period. Performance share awards cliff vest after a three -year period if the Company achieves certain levels of total shareholder return relative to a pre-determined industry peer group. 2015 Stock Plan for Non-Employee Directors The 2015 Stock Plan for Non-Employee Directors of Noble Energy, Inc., as amended (the 2015 Plan) provides for grants of stock options and awards of restricted stock to our non-employee directors. The 2015 Plan superseded and replaced the 2005 Stock Plan for Non-Employee Directors of Noble Energy, Inc. The total number of shares of our common stock that may be issued under the 2015 Plan is 708,996 . At December 31, 2019 , 485,062 shares of our common stock were reserved for issuance, including 306,243 shares available for future grants and awards, under the 2015 Plan. Stock Option Grants The fair value of each stock option granted is estimated on the date of grant using a Black-Scholes-Merton option valuation model that used the assumptions described below: • Expected term Represents the period of time that options granted are expected to be outstanding, which is the grant date to the date of expected exercise or other expected settlement for options granted. The hypothetical midpoint scenario we use considers our actual exercise and post-vesting cancellation history and expectations for future periods, which assumes that all vested, outstanding options are settled halfway between the current date and their expiration date. • Expected volatility Represents the extent to which our stock price is expected to fluctuate between the grant date and the expected term of the award. We use the historical volatility of our common stock for a period equal to the expected term of the option prior to the date of grant. We believe that historical volatility produces an estimate that is representative of our expectations about the future volatility of our common stock over the expected term. • Risk-free rate Represents the implied yield available on US Treasury securities with a remaining term equal to the expected term of the option. We base our risk-free rate on a weighting of five and seven year US Treasury securities as of the date of grant. • Dividend yield Represents the value of our stock’s annualized dividend as compared to our stock’s average price for the three -year period ended prior to the date of grant. It is calculated by dividing one full year of our expected dividends by our average stock price over the three -year period ended prior to the date of grant. The assumptions used in valuing stock options granted were as follows: Year Ended December 31, (weighted averages) 2019 2018 2017 Expected Term (in Years) 6.9 6.7 6.4 Expected Volatility 33.8 % 33.4 % 33.2 % Risk-Free Rate 2.7 % 2.6 % 2.2 % Expected Dividend Yield 1.4 % 1.2 % 0.9 % Weighted Average Grant-Date Fair Value $ 7.57 $ 10.47 $ 13.26 Stock option activity was as follows: Options Weighted Average Exercise Price Weighted Average Remaining Contractual Term Aggregate Intrinsic Value (per share) (years) (millions) Outstanding at December 31, 2018 13,852,020 $ 44.04 Granted 461,311 22.15 Forfeited (51,100 ) 34.72 Expired (1,686,478 ) 35.26 Outstanding at December 31, 2019 12,575,753 $ 44.62 4.2 $ 1 Exercisable at December 31, 2019 11,373,846 $ 46.11 3.7 $ — There were no options exercised in 2019. The total intrinsic value of options exercised was $5 million in 2018 and $4 million in 2017 . As of December 31, 2019 , $5 million of compensation cost related to unvested stock options granted under the Plans remained to be recognized. The cost is expected to be recognized over a weighted-average period of 1.2 years. We issue new shares of our common stock to settle option exercises. Dividends are not paid on unexercised options. Restricted Stock Awards Awards of time-vested restricted stock (shares subject to service conditions) are valued at the price of our common stock at the date of award. The fair value of the market based restricted stock awards was estimated on the date of award using a Monte Carlo valuation model that uses the assumptions in the following table. The Monte Carlo valuation model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility represents the extent to which our stock price is expected to fluctuate between now and the award’s anticipated term. We use the historical volatility of Noble Energy common stock for the three -year period ended prior to the date of award. The risk-free rate is based on a three-year period for US Treasury securities as of the year ended prior to the date of award. The assumptions used in valuing market based restricted stock awards granted were as follows: Year Ended December 31, 2019 2018 2017 Number of Simulations 10,000,000 10,000,000 500,000 Expected Volatility 37.5 % 35.0 % 35.0 % Risk-Free Rate 2.5 % 2.3 % 1.5 % Restricted stock activity was as follows: Subject to Time Vesting Subject to Market Conditions Number of Shares Weighted Average Award Date Fair Value Number of Shares Weighted Average Award Date Fair Value (per share) (per share) Outstanding at December 31, 2018 3,172,891 $ 32.72 1,385,634 $ 21.74 Awarded 2,464,682 22.33 1,138,730 13.50 Vested (906,485 ) 34.11 — — Forfeited (486,733 ) 27.97 (347,948 ) 21.20 Outstanding at December 31, 2019 4,244,355 $ 27.02 2,176,416 $ 17.52 The total fair value of restricted stock that vested was $20 million in 2019 , $29 million in 2018 , and $34 million in 2017 . The weighted average award-date fair value per share of restricted stock awarded was $19.54 in 2019 , $27.96 in 2018 , and $35.45 in 2017 . As of December 31, 2019 , $74 million of compensation cost related to all of our unvested restricted stock awarded under the Plans remained to be recognized. The cost is expected to be recognized over a weighted-average period of 1.4 years. Common stock dividends accrue on restricted stock awards and are paid upon vesting. We issue new shares of our common stock when awarding restricted stock. Cash-Settled Awards Periodically, we issue cash-settled awards (so called phantom units, the nomenclature used in accounting literature) to certain employees in lieu of a portion of restricted stock and stock options. These phantom units represented a hypothetical interest in the Company and, once vested, are settled in cash. Common stock dividends accrue on phantom units and are paid upon vesting. On February 1, 2016, we issued one million phantom units under the 1992 Plan, a portion of which were subject to the Company's achievement of certain levels of total shareholder return relative to a pre-determined industry peer group. The phantom units vested during 2019 at $ 31.65 per share which was equal to the grant date fair value. The fair value of the market based phantom unit awards was estimated on the date of award using a Monte Carlo valuation model and assumed 500,000 simulations, 38% expected volatility and a risk-free rate of 0.9% . These awards vested at 0% as performance was not achieved. On February 19, 2019, we issued 803,606 phantom units under the 2017 Plan. The units had a grant date fair value of $22.39 and vest ratably over three years . The value at vesting will equal the fair market value of a share of common stock of the Company as of the vesting date. Phantom unit activity was as follows: Subject to Time Vesting Subject to Market Conditions Number of Units Weighted Average Award Date Fair Value Number of Units Weighted Average Award Date Fair Value (per share) (per share) Outstanding at December 31, 2018 467,365 $ 31.65 150,296 $ 6.82 Awarded 803,606 22.39 — — Vested (462,823 ) 31.65 — — Forfeited (92,762 ) 22.55 (150,296 ) 6.82 Outstanding at December 31, 2019 715,386 $ 22.39 — $ — As of December 31, 2019 , $ 11 million of compensation cost related to phantom units remained to be recognized. The cost is expected to be recognized over a weighted-average period of 2.1 years. The total fair value of phantom units that vested in 2019 was $ 10 million. We accrued a liability of $ 5 million in 2019 related to the phantom units. Other Compensation Plans 401(k) Plan We sponsor a 401(k) savings plan. All regular employees are eligible to participate. We make contributions to match employee contributions up to the first 6% of compensation deferred into the plan, and certain profit sharing contributions for employees hired on or after May 1, 2006, based upon their ages and salaries. We made cash contributions of $32 million in 2019 , $31 million in 2018 and $31 million in 2017 . Deferred Compensation Plans We have a non-qualified deferred compensation plan for which participant-directed investments are held in a rabbi trust and are available to satisfy the claims of our creditors in the event of bankruptcy or insolvency. Participants may elect to receive distributions in either cash or shares of our common stock. Assets within the rabbi trust primarily consist of mutual fund investments, which include various publicly-traded mutual funds that, in turn, include investments ranging from equities to money market instruments and totaled $ 27 million at December 31, 2019 . The fair values are based on quoted market prices for identical assets. The liability associated with the deferred compensation plan, which is dependent upon the fair values of the mutual fund investments and common stock held in the rabbi trust, was $29 million and $43 million at December 31, 2019 and 2018 , respectively. The rabbi trust included 64,729 and 267,792 shares of our common stock at December 31, 2019 and 2018 , respectively, which are accounted for as treasury stock. Distributions of 200,000 shares were made in each of 2019 , 2018 and 2017 and were valued at $23 million in 2019 , $18 million in 2018 and $21 million in 2017 . All fluctuations in market value of the deferred compensation liability have been reflected in other non-operating (income) expense, net in the consolidated statements of operations. We recognized deferred compensation expense of $9 million in 2019 , $2 million in 2018 and $9 million in 2017 . We also maintain other nonqualified deferred compensation plans for the benefit of certain of our employees. Deferred compensation liabilities under these plans were $99 million and $104 million at December 31, 2019 and 2018 , respectively. |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2019 | |
Accounting Policies [Abstract] | |
Basis of Presentation and Consolidation | Basis of Presentation and Consolidation We use accounting policies that conform to US GAAP. Our consolidated accounts include our accounts and the accounts of our wholly-owned subsidiaries. Intercompany balances and transactions have been eliminated upon consolidation. For the periods presented, net income or loss is materially consistent with comprehensive income or loss. Certain prior-period amounts have been reclassified to conform to the current period presentation. Segment Information Accounting policies are consistent across geographical segments. Transfers between segments are accounted for at market value. See Note 3. Segment Information . Noble Midstream Partners Noble Energy has determined that the partners with equity at risk in Noble Midstream Partners LP (Noble Midstream Partners, Nasdaq: NBLX) lack the authority, through voting rights or similar rights, to direct the activities that most significantly impact Noble Midstream Partners' economic performance; therefore, Noble Midstream Partners is considered a variable interest entity (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. Noncontrolling Interests Our consolidated financial statements include both noncontrolling interests and a redeemable noncontrolling interest. The noncontrolling interests represent the public's ownership in Noble Midstream Partners and third-party ownership in Noble Midstream Partners' consolidated non-wholly owned subsidiaries. The redeemable noncontrolling interest represents third-party preferred equity secured by Noble Midstream Partners in March 2019. The entire equity commitment totals $200 million , of which $100 million was funded and the remaining $100 million is available for a one year period, subject to certain conditions precedent. The preferred equity is perpetual and has a 6.5% |
Equity Method of Accounting | Equity Method of Accounting |
Use of Estimates | Use of Estimates The preparation of consolidated financial statements in conformity with US GAAP requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Estimated quantities of crude oil, NGL and natural gas reserves are the most significant of our estimates. See Supplemental Oil and Gas Information (Unaudited) . Other items subject to estimates and assumptions include the carrying amounts of inventory, property, plant and equipment, equity method investments, goodwill, intangible assets, exit cost liabilities and AROs, valuation |
Fair Value Measurements | Fair Value Measurements Certain assets and liabilities are measured at fair value on a recurring basis on our consolidated balance sheets. Other assets and liabilities are measured at fair value on a nonrecurring basis. Fair value measurements are based on a hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three levels. The fair value hierarchy is as follows: • Level 1 measurements are fair value measurements which use quoted market prices (unadjusted) in active markets for identical assets or liabilities. • 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. • Level 3 measurements are fair value measurements which use unobservable inputs. The fair value hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. We use Level 1 inputs when available, as Level 1 inputs generally provide the most reliable evidence of fair value. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-term nature or maturity of the instruments. |
Cash and Cash Equivalents | Cash and Cash Equivalents For purposes of reporting cash flows, cash and cash equivalents include unrestricted cash on hand and investments with original maturities of three months or less at the time of purchase. |
Accounts Receivable and Allowance for Expected Credit Losses | Accounts Receivable and Allowance for Expected Credit Losses Our accounts receivable result primarily from sales of crude oil, NGL and natural gas production and joint interest billings to our partners for their share of expenses on joint venture projects for which we are the operator. The majority of these receivables have payment terms of 30 days or less . Our accounts receivable reflects broad national and international customer base, which limits our exposure to concentrations of credit risk. We continually monitor the creditworthiness of the counterparties and have obtained credit enhancements from some parties in the form of parental guarantees or letters of credit. |
Property, Plant and Equipment | Property, Plant and Equipment Significant accounting policies for our property, plant and equipment are as follows: Oil and Gas Properties (Successful Efforts Method of Accounting) We account for crude oil and natural gas properties under the successful efforts method of accounting. Under this method, costs to acquire mineral interests in crude oil and natural gas properties, drill and equip exploratory wells that find proved reserves, and drill and equip development wells are capitalized. Capitalized costs of producing crude oil and natural gas properties, along with support equipment and facilities, are depleted using the unit-of-production method based on proved crude oil, NGL and natural gas reserves on a field-by-field basis, as estimated by our qualified petroleum engineers. Costs of certain gathering facilities or processing plants serving a number of properties or used for third-party processing are depreciated using the straight-line method over the useful lives of the assets ranging from three to thirty years . Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A is eliminated and we either adjust the basis of the respective asset or recognize a gain or loss. Costs related to repair and maintenance activities are expensed as incurred. Proved Property Impairment For our proved properties, we routinely assess whether impairment indicators exist and have processes in place to ensure that we become aware of such indicators. Impairment indicators include, but are not limited to, sustained decreases in commodity prices, negative revisions of proved reserves, and increases in development or operating costs. We conduct an impairment test in the event impairment indicators exist. Under such test, we estimate future net cash flows expected in connection with the property and compare such future net cash flows to the carrying amount of the property to determine if the carrying amount is recoverable. Other long-lived assets, such as our midstream assets, are evaluated in a manner consistent with our policy for proved property. When the carrying amount of the proved property exceeds its estimated undiscounted future net cash flows, an impairment is indicated and the fair value of the asset is then estimated. Fair value inputs, which are level 3 on the fair value hierarchy, may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future net cash flows are based on management’s expectations for the future and include estimates of future crude oil and natural gas production, commodity prices based on published forward commodity price curves or contract prices as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate. In the event of an impairment, the carrying amount of the proved property is reduced to estimated fair value. See Note 10. Impairments . Unproved Property Our unproved properties consist of leasehold costs and allocated value to probable and possible reserves resulting from acquisitions. Undeveloped leasehold costs are derived from allocated fair values as a result of business combinations or other purchases of unproved properties and are subject to impairment testing. 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. We assess individually significant unproved properties for impairment on a quarterly basis and recognize a loss at the time of impairment. In determining whether a significant unproved property is impaired, we consider numerous factors including, but not limited to, current exploration plans, favorable or unfavorable exploration activity on the property being evaluated and/or adjacent properties, our geologists' evaluation of the property, and the remaining months in the lease term for the property. When we have allocated fair value to an unproved property as the result of a transaction accounted for as a business combination, we use a future net cash flow analysis to assess the unproved property for impairment. Cash flows used in the impairment analysis are determined based on management’s estimates of crude oil, NGL and natural gas reserves, future commodity prices and future costs to produce the reserves. Reserves volumes are reduced by risk adjustments applied to probable and possible reserves. See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs . Properties Acquired in Business Combinations When sufficient market data is not available, we determine the fair values of proved and unproved oil and gas properties acquired in transactions accounted for as business combinations by preparing estimates of cash flows from the production of crude oil, NGL and natural gas reserves. We estimate future prices to apply to the estimated reserves quantities acquired, and estimate future operating and development costs, to arrive at estimates of future net cash flows. For the fair value assigned to proved reserves, future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the business combination. When estimating and valuing unproved reserves, discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors. For other assets acquired in business combinations, we use a combination of available cost and market data and/or estimated cash flows to determine the fair values. Assets Held for Sale At the end of each reporting period, we evaluate properties being marketed for sale to determine whether any should be reclassified as held for sale. If the held-for-sale criteria are met, the property is reclassified as held for sale on our consolidated balance sheets and valued at the lower of net book value or anticipated sales proceeds less costs to sell. Impairment expense is recorded for any excess of net book value over anticipated sales proceeds less costs to sell. Exploration Costs Geological and geophysical costs, delay rentals, amortization of unproved leasehold costs, and costs to drill exploratory wells that do not find proved reserves are expensed as oil and gas exploration. We carry the costs of an exploratory well as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as we are making sufficient progress assessing the reserves and the economic and operating viability of the project. For certain capital-intensive international projects, it may take us more than one year to evaluate the future potential of the exploratory well and make a determination of its economic viability. Our ability to move forward on a project may be dependent on gaining access to transportation or processing facilities or obtaining permits and government or partner approval, the timing of which is beyond our control. In such cases, exploratory well costs remain suspended as long as we are actively pursuing access to necessary facilities, permits and approvals and we believe they will be obtained. We assess the status of suspended exploratory well costs on a quarterly basis. See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs . Property, Plant and Equipment, Other Other property includes automobiles, trucks, an airplane, office furniture, computer equipment, buildings, leasehold improvements and other fixed assets. These items are recorded at cost and are depreciated using the straight-line method based on expected lives of the individual assets or group of assets, ranging from three to thirty years . Other property also includes linefill, which is recorded at cost to produce into the production line. Linefill is not subject to depreciation but is reviewed for impairment. Capitalization of Interest We capitalize interest costs associated with the development and construction of significant properties or projects to bring them to a condition and location necessary for their intended use, which for crude oil and natural gas assets is at first production from the field. Interest is capitalized using an interest rate equivalent to the weighted average interest rate we pay on long-term debt, including our unsecured revolving credit facilities, term loan credit facilities and Senior Notes. Capitalized interest is included in the cost of oil and gas assets and is amortized with other costs on a unit-of-production basis. Asset Retirement Obligations |
Intangible Assets | Intangible Assets Intangible assets consist of customer contracts and relationships that were recorded at their estimated fair values at the date of acquisition. Amortization is calculated using the straight-line method, which reflects the pattern in which the estimated economic benefit is expected to be received over the estimated useful life of the intangible assets, which is currently over periods of seven to 13 years. As of December 31, 2019 , the net book value of our intangible assets was $ 278 million, net of accumulated amortization of $62 million |
Exit Costs | Exit Costs |
Derivative Instruments and Hedging Activities | Derivative Instruments and Hedging Activities All derivative instruments are recorded on our consolidated balance sheets as either an asset or liability and are measured at fair value. We account for our commodity derivative instruments using mark-to-market accounting and recognize all gains and losses in earnings during the period in which they occur. |
Stock-Based Compensation | Stock-Based Compensation |
Contingencies | Contingencies |
Income Taxes | Income Taxes We are subject to income and other taxes in numerous taxing jurisdictions worldwide. For financial reporting purposes, we provide taxes at rates applicable for the appropriate tax jurisdictions. We account for income taxes using the asset and liability method. Deferred tax assets and liabilities are recognized when items of income and expense are recognized in the financial statements in different periods than when recognized in the applicable tax return. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the date when the change in the tax rate was enacted. In assessing the realizability of deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income in the appropriate tax jurisdictions during the periods in which those temporary differences become deductible. We consider the scheduled reversal of deferred tax liabilities, current financial position, results of operations, projected future taxable income and tax planning strategies as well as current and forecasted business economics in the oil and gas industry. The |
Treasury Stock | Treasury Stock We record treasury stock purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as reductions in shareholders’ equity in the consolidated balance sheets. |
Revenue Recognition | Revenue Recognition Our revenues are derived primarily from the sale of crude oil, NGL and natural gas production to crude oil refining companies, midstream marketing companies, marketers, industrial companies, electric utility companies, independent power producers and cogeneration facilities, among others. We recognize revenues based on the amount of product sold to a customer when control transfers to the customer. Our revenue arrangements include the following: Crude Oil Sale Arrangements – US We sell our share of crude oil production under both short-term and long-term contracts at market-based prices, adjusted for location, quality and transportation charges. Revenue is measured based on the index-based contract price, and may include adjustments for market differentials and downstream costs incurred by the customer, including gathering, transportation, and fuel costs. Crude Oil Sale Arrangements – West Africa We sell our share of crude oil and condensate at market-based prices and recognize revenue at the time a crude oil cargo is loaded onto the tanker. Natural Gas and NGLs Sale Arrangements – US We evaluate these arrangements to determine whether the processor is a service provider or a customer. In arrangements where we determine that the processor is a customer, we record revenue when the processor takes control of the 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 arrangements, we receive natural gas and NGL products “in-kind” after processing at the tailgate of the plant. In these arrangements, where we determine that the processor is a service provider, we record revenue and applicable gathering, processing, transportation and fractionation fees on a gross basis at the time the product is delivered to the end customer. Natural Gas Sale Arrangements – West Africa We sell our share of natural gas production under a 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 – Eastern Mediterranean We sell our share of natural gas production primarily based on long-term contracts with fixed volume commitments. Performance obligations 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 these sales contracts contain take-or-pay provisions whereby the customers are required to purchase a contractual minimum over varying time periods. We record revenues related to the volumes delivered at the contract price at the time of delivery. The following table provides estimated future revenues for remaining performance obligations under fixed volume natural gas sales agreements using the contractual fixed base or floor price provision in effect. Actual future sales volumes under these agreements may exceed future minimum volume commitments. In addition, future sales revenues will vary due to components of variable consideration above the contractual base or floor provision, such as index-based escalations and market price changes. Certain of these contracts contain embedded derivatives for which we have elected the normal purchases and normal sales scope exception, which excludes the derivatives from mark-to-market accounting. Estimated future revenues related to remaining performance obligations were as follows as of December 31, 2019: (millions) 2020 2021 2022 2023 2024 Thereafter Total Natural Gas Revenues (1) $ 743 $ 768 $ 583 $ 583 $ 583 $ 5,259 $ 8,519 (1) Includes amounts related to the Tamar and Leviathan fields, offshore Israel. Oil and Gas Purchase and Sale Arrangements We enter into separate third-party purchase and sale transactions at prevailing market prices to mitigate unutilized pipeline transportation commitments. We recognize associated revenues and expenses 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. We also enter into crude oil buy/sell arrangements that effect a change in location and/or grade with required repurchase of crude oil at a delivery point. We account for these transactions on a net basis and record the residual transportation fee within gathering, transportation and processing expense in the consolidated statements of operations. Midstream Services Arrangements |
Basic and Diluted Earnings (Loss) Per Share Attributable to Noble Energy | Basic and Diluted Earnings (Loss) Per Share Attributable to Noble Energy |
Recently Adopted Accounting Standards and Recently Issued Accounting Standards | Recently Adopted Accounting Standards Leases Effective January 1, 2019, we adopted Accounting Standards Update No. 2016-02 (ASU 2016-02), which created Topic 842 – Leases (ASC 842). The standard requires lessees to recognize a right-of-use (ROU) asset and lease liability on the balance sheet for the rights and obligations created by leases. This standard does not apply to leases to explore for or use minerals, oil, natural gas or similar nonregenerative resources, including the intangible right to explore for those resources and rights to use the land in which those natural resources are contained. Upon adoption, we elected the following optional practical expedients: • transition “practical expedients,” permitting us not to reassess our prior conclusions about lease identification, lease classification and initial direct costs; • the practical expedient pertaining to land easements, allowing us to account for existing land easements under our previous accounting policy; and • the practical expedient to not separate lease and non-lease components for the majority of our leases (elected by asset class). We adopted ASC 842 using the modified retrospective method and recorded ROU assets and lease liabilities of $282 million and $287 million , respectively, primarily related to operating leases. ROU assets and corresponding liabilities are based on the present value of the minimum lease payments. Our accounting for finance leases remains substantially unchanged. Adoption of ASC 842 did not materially impact our consolidated statement of operations and comprehensive income and had no impact on our consolidated statement of cash flows. Additional information related to our accounting policies for leases is as follows: • Most of our leases do not provide implicit borrowing rates; therefore, using the portfolio approach, we determine the present value of lease payments using hypothetical secured borrowing rates based on information available at lease commencement. • Leases with an initial term of 12 months or less are not recorded on the balance sheet and we recognize lease expense for these leases on a straight-line basis over the lease term. Most leases include one or more options to renew, with renewal terms that can extend the lease term from one month to one year or more. Additionally, some of our leases include an option for early termination. We include renewal periods and exclude termination periods from our lease term if, at commencement, it is reasonably likely that we will exercise the option. • Certain of our lease agreements include rental payments that are adjusted periodically for inflation or passage of time. These step payments are included within our present value calculation as they are known adjustments at commencement. Variable payments related to lease agreements are not material. • We have lease agreements that include lease and non-lease components, such as equipment maintenance, that are generally accounted for as a single lease component. For these leases, lease payments include all fixed payments stated within the contract. For other leases, such as office space, lease and non-lease components are accounted for separately. While some lease agreements include residual value guarantees, there are no material guarantees that impact our lease payments. • ROU assets are reviewed for impairment when events or changes in circumstances indicate that the carrying amounts of such assets may not be recoverable. See Note 9. Leases . Financial Instruments: Credit Losses In June 2016, the FASB issued ASU 2016-13, which replaces the incurred loss impairment methodology with an expected credit loss methodology for financial instruments, including financial assets measured at amortized cost, such as trade and joint interest billing receivables, and off-balance sheet credit exposures not accounted for as insurance, such as financial guarantees and other unfunded loan commitments. The amended standard is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. We early adopted this ASU in fourth quarter 2019. This adoption did not have a material impact on our financial statements. Income Taxes In December 2019, the FASB released Accounting Standards Update No. 2019-12 (ASU 2019-12): Income Taxes (Topic 740) – Simplifying the Accounting for Income Taxes, which removes certain exceptions for recognizing deferred taxes for investments, performing intraperiod allocation and calculating income taxes in interim periods. The ASU also adds guidance to reduce complexity in certain areas, including recognizing deferred taxes for tax goodwill and allocating taxes to members of a consolidated group. The amended standard is effective for fiscal years beginning after December 15, 2020, with early adoption permitted. We early adopted this ASU in fourth quarter 2019. This adoption did not have a material impact on our financial statements. Recently Issued Accounting Standards None that are expected to have a material impact on our financial statements. |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Accounting Policies [Abstract] | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | Estimated future revenues related to remaining performance obligations were as follows as of December 31, 2019: (millions) 2020 2021 2022 2023 2024 Thereafter Total Natural Gas Revenues (1) $ 743 $ 768 $ 583 $ 583 $ 583 $ 5,259 $ 8,519 (1) Includes amounts related to the Tamar and Leviathan fields, offshore Israel. |
Additional Financial Statemen_2
Additional Financial Statement Information (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Additional Financial Statement Information [Abstract] | |
Statement of Operations Information | Other statements of operations information is as follows: Year Ended December 31, (millions) 2019 2018 2017 Other Revenue Income from Equity Method Investments and Other $ 51 $ 172 $ 177 Midstream Services Revenues - Third Party 94 78 19 Total $ 145 $ 250 $ 196 Production Expense Lease Operating Expense $ 532 $ 576 $ 571 Production and Ad Valorem Taxes 175 190 118 Gathering, Transportation and Processing Expense 417 393 432 Other Royalty Expense 13 38 20 Total $ 1,137 $ 1,197 $ 1,141 Exploration Expense Leasehold Impairment and Amortization $ — $ 1 $ 62 Dry Hole Cost (1) 100 1 9 Seismic, Geological and Geophysical 21 22 27 Staff Expense 48 54 55 Other 33 51 35 Total $ 202 $ 129 $ 188 Loss on Marcellus Shale Upstream Divestiture and Other Loss on Sale $ — $ — $ 2,270 Exit Cost — — 93 Other — — 16 Total $ — $ — $ 2,379 Other Operating Expense, Net Marketing Expense $ 34 $ 40 $ 47 Firm Transportation Exit Cost (2) 88 — — Clayton Williams Energy Acquisition Expenses — — 100 Loss (Gain) on Asset Retirement Obligation Revisions 9 (25 ) (42 ) Other, Net 83 35 33 Total $ 214 $ 50 $ 138 (1) See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs . (2) See Note 11. Exit Cost – Transportation Commitments . |
Balance Sheet Information Table | Other balance sheet information is as follows: December 31, (millions) 2019 2018 Accounts Receivable, Net Commodity Sales $ 446 $ 383 Joint Interest Billings 164 137 Other 128 111 Allowance (8 ) (15 ) Total $ 730 $ 616 Other Current Assets Commodity Derivative Assets $ 14 $ 180 Inventories, Materials and Supplies 59 55 Assets Held for Sale (1) 14 133 Prepaid Expenses and Other Current Assets 61 50 Total $ 148 $ 418 Other Noncurrent Assets Equity Method Investments (2) $ 1,066 $ 286 Operating Lease Right-of-Use Assets (3) 227 — Customer-Related Intangible Assets, Net 278 310 Goodwill 110 110 Mutual Fund Investments 27 38 Other Noncurrent Assets 126 97 Total $ 1,834 $ 841 Other Current Liabilities Production and Ad Valorem Taxes $ 118 $ 103 Asset Retirement Obligations 84 118 Interest Payable 74 66 Operating Lease Liabilities (3) 88 — Compensation and Benefits Payable 126 83 Other Current Liabilities 229 149 Total $ 719 $ 519 Other Noncurrent Liabilities Deferred Compensation Liabilities $ 133 $ 147 Asset Retirement Obligations 730 762 Operating Lease Liabilities (3) 164 — Firm Transportation Exit Cost Accrual (4) 129 67 Other Noncurrent Liabilities 222 189 Total $ 1,378 $ 1,165 (1) Amounts relate to divestitures of non-core assets and acreage in Reeves County, Texas. See Note 4. Acquisitions and Divestitures . (2) See Note 5. Equity Method Investments . (3) Amounts relate to assets and liabilities recorded as a result of ASC 842 adoption. See Note 9. Leases . (4) See Note 11. Exit Cost – Transportation Commitments . |
Schedule of Cash and Cash Equivalents | We define total cash as cash, cash equivalents and restricted cash. The following table provides a reconciliation of total cash: December 31, (millions) 2019 2018 Cash and Cash Equivalents at Beginning of Period $ 716 $ 675 Restricted Cash at Beginning of Period 3 38 Cash, Cash Equivalents, and Restricted Cash at Beginning of Period $ 719 $ 713 Cash and Cash Equivalents at End of Period $ 484 $ 716 Restricted Cash at End of Period — 3 Cash, Cash Equivalents, and Restricted Cash at End of Period $ 484 $ 719 |
Schedule of Restricted Cash | We define total cash as cash, cash equivalents and restricted cash. The following table provides a reconciliation of total cash: December 31, (millions) 2019 2018 Cash and Cash Equivalents at Beginning of Period $ 716 $ 675 Restricted Cash at Beginning of Period 3 38 Cash, Cash Equivalents, and Restricted Cash at Beginning of Period $ 719 $ 713 Cash and Cash Equivalents at End of Period $ 484 $ 716 Restricted Cash at End of Period — 3 Cash, Cash Equivalents, and Restricted Cash at End of Period $ 484 $ 719 |
Supplemental Cash Flow Disclosure | Supplemental statements of cash flow information is as follows: Year Ended December 31, (millions) 2019 2018 2017 Cash Paid During the Year For Interest, Net of Amount Capitalized (1) $ 208 $ 270 $ 346 Income Taxes Paid, Net 76 172 121 (1) Interest capitalized totaled $102 million in 2019 , $73 million in 2018 and $49 million in 2017 . |
Non-affiliated Purchasers Accounting for 10% or more of Commodity Sales | Non-affiliated purchasers who accounted for 10% or more of our commodity sales were as follows: Year Ended December 31, 2019 2018 2017 Percentage of Crude Oil Sales Shell (1) 22 % 22 % 22 % BP (2) 18 % 31 % 15 % Percentage of Total Crude Oil, NGL & Natural Gas Sales Shell (1) 15 % 14 % 13 % BP (2) 14 % 17 % 10 % (1) Includes sales to Shell Energy North America and Shell Trading (US) Company (collectively, Shell). (2) Includes sales to BP America Production, BP Energy Co and BP Products North America, Inc (collectively, BP). |
Segment Information (Tables)
Segment Information (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Segment Reporting [Abstract] | |
Segment Information | 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 Year Ended December 31, 2019 Crude Oil Sales $ 2,736 $ 2,437 $ 6 $ 293 $ — $ — $ — $ — NGL Sales 354 354 — — — — — — Natural Gas Sales 814 345 451 18 — — — — Total Crude Oil, NGL and Natural Gas Sales 3,904 3,136 457 311 — — — — Sales of Purchased Oil and Gas 389 109 — — — 190 — 90 Income (Loss) from Equity Method Investments and Other 51 8 — 61 — (18 ) — — Midstream Services Revenues - Third Party 94 — — — — 94 — Intersegment Revenues — — — — — 427 (427 ) — Total Revenues 4,438 3,253 457 372 — 693 (427 ) 90 Lease Operating Expense 532 460 37 76 — 4 (45 ) — Production and Ad Valorem Taxes 175 169 — — — 6 — — Gathering, Transportation and Processing Expense 417 598 1 — — 110 (292 ) — Other Royalty Expense 13 13 — — — — — — Total Production Expense 1,137 1,240 38 76 — 120 (337 ) — Exploration Expense 202 57 109 13 23 — — — Depreciation, Depletion and Amortization 2,197 1,907 67 83 1 104 (29 ) 64 Asset Impairments 1,160 1,160 — — — — — — Cost of Purchased Oil and Gas 431 107 — — — 181 — 143 Firm Transportation Exit Cost 88 — — — — — — 88 Loss on Commodity Derivative Instruments 143 125 — 18 — — — — Loss on Debt Extinguishment 44 — — — — — — 44 (Loss) Income Before Income Taxes (1,776 ) (1,431 ) 199 164 (25 ) 258 (55 ) (886 ) Additions to Long-Lived Assets, Excluding Acquisitions 2,408 1,651 505 70 20 230 (92 ) 24 Additions to Equity Method Investments 799 — 189 — — 610 — — Property, Plant and Equipment, Net 17,451 11,859 3,041 793 44 1,721 (223 ) 216 Year Ended December 31, 2018 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 Crude Oil Sales $ 2,945 $ 2,548 $ 7 $ 390 $ — $ — $ — $ — NGL Sales 587 587 — — — — — — Natural Gas Sales 929 435 473 21 — — — — Total Crude Oil, NGL and Natural Gas Sales 4,461 3,570 480 411 — — — — Sales of Purchased Oil and Gas 275 20 — — — 142 — 113 Income from Equity Method Investments and Other 172 — — 132 — 40 — — Midstream Services Revenues - Third Party 78 — — — — 78 — — Intersegment Revenues — — — — — 351 (351 ) — Total Revenues 4,986 3,590 480 543 — 611 (351 ) 113 Lease Operating Expense 576 480 26 97 — — (27 ) — Production and Ad Valorem Taxes 190 184 — — — 6 — — Gathering, Transportation and Processing Expense 393 533 — — — 95 (235 ) — Other Royalty Expense 38 38 — — — — — — Total Production Expense 1,197 1,235 26 97 — 101 (262 ) — Exploration Expense 129 48 7 6 68 — — — Depreciation, Depletion and Amortization 1,934 1,642 60 115 2 87 (20 ) 48 (Gain) Loss on Divestitures, Net (843 ) 36 (376 ) — — (503 ) — — Asset Impairments 206 169 — — — 37 — — Goodwill Impairment 1,281 1,281 — — — — — — Cost of Purchased Oil and Gas 296 20 — — — 136 — 140 Gain on Asset Retirement Obligation Revision (25 ) — (8 ) — (17 ) — — — (Gain) Loss on Commodity Derivative Instruments (63 ) (70 ) — 7 — — — — Income (Loss) Before Income Taxes 140 (875 ) 742 305 (53 ) 726 (60 ) (645 ) Additions to Long Lived Assets, Excluding Acquisitions 3,253 2,115 671 12 — 521 (91 ) 25 Property, Plant and Equipment, Net 18,419 13,044 2,630 805 37 1,742 (145 ) 306 Year Ended December 31, 2017 Crude Oil Sales $ 2,346 $ 1,993 $ 6 $ 347 $ — $ — $ — $ — NGL Sales 493 493 — — — — — — Natural Gas Sales 1,221 670 528 23 — — — — Total Crude Oil, NGL and Natural Gas Sales 4,060 3,156 534 370 — — — — Income from Equity Method Investments and Other 177 — — 120 — 57 — — Midstream Services Revenues - Third Party 19 — — — — 19 — — Intersegment Revenues — — — — — 277 (277 ) — Oil and Gas Exploration and Production Midstream (millions) Consolidated United States Eastern Mediter-ranean West Africa Other Int'l United States Intersegment Eliminations and Other (1) Corporate Total Revenues 4,256 3,156 534 490 — 353 (277 ) — Lease Operating Expense 571 466 29 90 — — (14 ) — Production and Ad Valorem Taxes 118 115 — — — 3 — — Gathering, Transportation and Processing Expense 432 550 — — — 70 (188 ) — Other Royalty Expense 20 20 — — — — — — Total Production Expense 1,141 1,151 29 90 — 73 (202 ) — Exploration Expense 188 102 2 5 79 — — — Depreciation, Depletion and Amortization 2,053 1,739 76 146 4 30 (5 ) 63 Loss on Marcellus Shale Upstream Divestiture and Other 2,379 2,286 — — — — — 93 Gain on Divestitures, Net (326 ) (325 ) (1 ) — — — — — Asset Impairments 70 63 — — 7 — — — Clayton Williams Energy Acquisition Expenses 100 100 — — — — — — Gain on Asset Retirement Obligation Revision (42 ) — — — (42 ) — — — (Gain) Loss on Commodity Derivative Instruments (63 ) (92 ) — 29 — — — — Loss on Debt Extinguishment 98 — — — — — — 98 (Loss) Income Before Income Taxes (2,191 ) (2,365 ) 413 203 (54 ) 233 (62 ) (559 ) Additions to Long Lived Assets, Excluding Acquisitions 2,851 1,994 411 34 (34 ) 423 (79 ) 102 Property, Plant and Equipment, Net 17,502 13,348 2,005 863 25 1,027 (74 ) 308 (1) Intersegment eliminations related to income (loss) before income taxes are the result of Midstream expenditures. Certain of these expenditures are presented as property, plant and equipment within the E&P business on an unconsolidated basis, in accordance with the successful efforts method of accounting. Other expenditures are presented as production expense. Intercompany revenues and expenses are eliminated upon consolidation. |
Equity Method Investments (Tabl
Equity Method Investments (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Equity method investments | The carrying values of our equity method investments, including the respective segments, are as follows: December 31, (millions, except percentages) Segment Ownership 2019 2018 Eastern Mediterranean Pipeline B.V. Eastern Mediterranean 25% $ 189 $ — Atlantic Methanol Production Company, LLC and Affiliates (1) West Africa 45% 160 146 Alba Plant LLC (2) West Africa 28% 56 58 EPIC Y-Grade, LP Midstream 15% 166 — EPIC Crude Holdings, LP Midstream 30% 339 — Delaware Crossing LLC Midstream 50% 69 — Advantage Pipeline, L.L.C. Midstream 50% 77 73 Other N/A N/A 10 9 Total Equity Method Investments (3) $ 1,066 $ 286 (1) Atlantic Methanol Production Company, LLC (AMPCO) owns and operates a methanol plant and related facilities in Equatorial Guinea. (2) Alba Plant LLC owns and operates a LPG processing plant in Equatorial Guinea. (3) At December 31, 2019 , total carrying values were $ 42 million higher than the underlying net assets of the investments, primarily due to capitalized interest which is amortized into earnings over the useful life of the related assets. Summarized, 100% combined balance sheet information for equity method investments was as follows: December 31, (millions) 2019 2018 Current Assets $ 681 $ 387 Noncurrent Assets 5,306 575 Current Liabilities 607 198 Noncurrent Liabilities 2,243 81 Summarized, 100% combined statements of operations for equity method investments was as follows: Year Ended December 31, (millions) 2019 2018 2017 Operating Revenues $ 1,018 $ 855 $ 790 Operating Expenses 853 284 303 Operating Income 165 571 487 Other (Loss) Income, net (33 ) 3 15 Income Before Income Taxes 132 574 502 Income Tax Provision 72 152 136 Net Income $ 60 $ 422 $ 366 |
Capitalized Exploratory Well _2
Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Capitalized Exploratory Well Costs [Abstract] | |
Changes in Capitalized Exploratory Well Costs | Changes in capitalized exploratory well costs, excluding amounts that were capitalized and subsequently expensed in the same period, are as follows: Year Ended December 31, (millions) 2019 2018 2017 Capitalized Exploratory Well Costs, Beginning of Period $ 354 $ 520 $ 768 Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves 26 7 20 Divestitures (1) — (168 ) — Reclassified to Proved Oil and Gas Properties, Based on Determination of Proved Reserves, or to Assets Held for Sale (2) — (1 ) (203 ) Capitalized Exploratory Well Costs Charged to Expense (3) (100 ) (4 ) (65 ) Capitalized Exploratory Well Costs, End of Period $ 280 $ 354 $ 520 (1) The 2018 amount relates to the second quarter 2018 sale of our Gulf of Mexico assets. (2) The 2017 amount relates to the approval and sanction of the first phase of development of the Leviathan field. (3) In fourth quarter 2019, we recorded exploration expense of $100 million related to the Leviathan Deep prospect, offshore Israel, which was initially drilled in 2012 but did not reach the target interval. Throughout this time, we have evaluated seismic information and nearby discoveries in the region. Upon concluding we would not move forward with the project, we wrote off the entire amount of capitalized exploratory well costs associated with this prospect. The 2017 amount relates to a write-off of costs for a natural gas discovery in the Gulf of Mexico. See Note 10. Impairments . |
Aging of Capitalized Well Costs | The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced: December 31, (millions, except number of projects) 2019 2018 2017 Exploratory Well Costs Capitalized for a Period of One Year or Less $ 22 $ 6 $ 10 Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling 258 348 510 Balance at End of Period $ 280 $ 354 $ 520 Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling 5 7 8 |
Aging of Exploratory Well Costs | The following table provides a further aging of those exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling as of December 31, 2019 : Suspended Since (millions) Total 2017 - 2018 2015 - 2016 2014 & Prior Progress Offshore Eastern Mediterranean Dalit (Offshore Israel) $ 23 $ (9 ) $ 3 $ 29 Our future development plan for this 2008 natural gas discovery, consisting of a tie-in to existing infrastructure at Tamar, was approved by the Government of Israel in 2019. During 2019, we continued analyzing 3D seismic data to evaluate additional potential of the area. Cyprus (Offshore Cyprus) 100 3 15 82 During 2019, we received approval of our Plan of Development and Exploitation License from the Government of Cyprus. We continued to progress capital project cost improvement and regional natural gas marketing efforts. Offshore West Africa Felicita (Block O, Offshore Equatorial Guinea) 49 2 4 43 We are in the process of evaluating regional development scenarios for this 2008 natural gas discovery. The recent sanction of the Alen Gas Monetization project, which represents the initial step in establishing a regional natural gas hub, expands the options for development of this discovery through existing infrastructure. YoYo (YoYo Block, Offshore Cameroon) and Yolanda (Block I, Offshore Equatorial Guinea) 80 2 5 73 A data exchange agreement for these 2007 condensate and natural gas discoveries has been executed between the governments of Equatorial Guinea and Cameroon. Our development team is working with both governments to evaluate natural gas monetization options. The recent sanction of the Alen Gas Monetization project, which represents the initial step in establishing a regional natural gas hub, expands the options for development of this discovery through existing infrastructure. Other Projects less than $20 million 6 (1 ) (10 ) 17 Continuing to assess and evaluate wells. Total $ 258 $ (3 ) $ 17 $ 244 |
Rollforward Of Undeveloped Lease Costs | Changes in undeveloped leasehold costs, which are recorded in oil and gas properties on our consolidated balance sheets, were as follows: Year Ended December 31, (millions) 2019 2018 Undeveloped Leasehold Costs, Beginning of Period $ 2,373 $ 2,922 Additions to Undeveloped Leasehold Costs 59 47 Transfers to Proved Properties (1) (184 ) (453 ) Assets Sold (2) (96 ) (142 ) Impairment — (1 ) Undeveloped Leasehold Costs, End of Period $ 2,152 $ 2,373 (1) Transfers primarily relate to development of Delaware Basin assets. (2) Amounts primarily relate to Delaware Basin assets sold. See Note 4. Acquisitions and Divestitures . |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of Change in Asset Retirement Obligation | Asset retirement obligations (ARO) consists 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: Year Ended December 31, (millions) 2019 2018 Asset Retirement Obligations, Beginning of Period $ 880 $ 875 Liabilities Incurred 70 25 Liabilities Settled (110 ) (345 ) Revisions of Estimates (69 ) 293 Reclassification to Liabilities Associated with Assets Held for Sale — (1 ) Accretion Expense 43 33 Asset Retirement Obligations, End of Period $ 814 $ 880 |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Leases [Abstract] | |
Summary of Operating and Finance Lease | ROU assets and lease liabilities ar e as follows: (millions) Balance Sheet Location December 31, 2019 ROU Assets Operating Leases (1) Other Noncurrent Assets $ 227 Finance Leases (2) Total Property, Plant and Equipment, Net 172 Total ROU Assets $ 399 Lease Liabilities Current Liabilities Operating Leases Other Current Liabilities $ 88 Finance Leases Other Current Liabilities 42 Noncurrent Liabilities Operating Leases Other Noncurrent Liabilities 164 Finance Leases Long-Term Debt 163 Total Lease Liabilities $ 457 (1) Operating lease ROU assets include compressors of $ 89 million and office space of $80 million . (2) Finance lease ROU assets include office space of $90 million and a trunkline of $28 million |
Lease Cost, Cash Flow and Other Information | The components of lease cost are as follows: (millions) Statement of Operations Location Year Ended December 31, 2019 Operating Lease Cost Various (1) $ 110 Finance Lease Cost Amortization Expense Depreciation, Depletion and Amortization 38 Interest Expense Interest, Net of Amount Capitalized 13 Short-term Lease Cost (2) Various (1) 424 Sublease Income General and Administrative (5 ) Total Lease Cost $ 580 (1) Cost classifications vary depending on the leased asset. Costs are primarily included within production expense and general and administrative expense. In addition, in accordance with the successful efforts method of accounting, certain lease costs may be capitalized when incurred and therefore, are included as part of oil and gas properties on our consolidated balance sheets. (2) Costs primarily relate to hydraulic fracturing services, well-to-well drilling rig contracts and other miscellaneous lease agreements. Amount excludes costs for leases with an initial term of one month or less. Cash Flow Information Supplemental cash flow information is as follows: Year Ended December 31, 2019 (millions) Operating Leases Finance Leases Cash Paid for Amounts Included in the Measurement of Lease Liabilities Operating Cash Flows $ 74 $ 12 Investing Cash Flows 36 — Financing Cash Flows — 42 Non-Cash Activities ROU Assets Obtained in Exchange for Lease Liabilities (1) 127 26 (1) Amounts exclude the impact of adopting ASC 842 on January 1, 2019. See Note 1. Summary of Significant Accounting Policies As of December 31, 2019 , other information related to our leases is as follows: Operating Leases Finance Leases Weighted-Average Remaining Lease Term 4.9 years 7.5 years Weighted-Average Discount Rate 4.05 % 4.96 % |
Operating Lease Liability Maturity | As of December 31, 2019 , maturities of lease liabilities were as follows: (millions) Operating Leases Finance Leases Total 2020 $ 100 $ 52 $ 152 2021 60 38 98 2022 41 27 68 2023 26 23 49 2024 15 21 36 2025 and Thereafter 37 86 123 Total Lease Liabilities, Undiscounted 279 247 526 Less: Imputed Interest 27 42 69 Total Lease Liabilities (1) $ 252 $ 205 $ 457 (1) Includes the current portions of $ 88 million and $ 42 million for operating and finance leases, respectively. |
Finance Lease Liability Maturity | As of December 31, 2019 , maturities of lease liabilities were as follows: (millions) Operating Leases Finance Leases Total 2020 $ 100 $ 52 $ 152 2021 60 38 98 2022 41 27 68 2023 26 23 49 2024 15 21 36 2025 and Thereafter 37 86 123 Total Lease Liabilities, Undiscounted 279 247 526 Less: Imputed Interest 27 42 69 Total Lease Liabilities (1) $ 252 $ 205 $ 457 (1) Includes the current portions of $ 88 million and $ 42 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Debt Disclosure [Abstract] | |
Debt | Our debt consists of the following: December 31, 2019 December 31, 2018 (millions, except percentages) Debt Interest Rate Debt Interest Rate Noble Energy, Excluding Noble Midstream Partners Revolving Credit Facility, due March 9, 2023 $ — — % $ — — % Commercial Paper Borrowings — — % — — % Senior Notes, due December 15, 2021 — — % 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 October 15, 2029 500 3.25 % — — % 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 % Senior Notes, due October 15, 2049 500 4.20 % — — % Senior Debentures 84 7.25 % 92 7.13 % Finance Lease Obligations 205 — % 223 — % Total Noble Energy Debt, Excluding Noble Midstream Partners Debt 6,089 6,115 Noble Midstream Partners Noble Midstream Services Revolving Credit Facility, due March 9, 2023 595 3.11 % 60 3.67 % Noble Midstream Services Term Loan Credit Facility, due July 31, 2021 500 2.85 % 500 3.42 % Noble Midstream Services Term Loan Credit Facility, due August 23, 2022 400 2.74 % — — % Total Noble Midstream Partners Debt 1,495 560 Total Debt 7,584 6,675 Net Unamortized Discounts and Debt Issuance Costs (65 ) (60 ) Total Debt, Net of Unamortized Discounts and Debt Issuance Costs $ 7,519 $ 6,615 Less Amounts Due Within One Year: Finance Lease Obligations (42 ) (41 ) Long-Term Debt Due After One Year $ 7,477 $ 6,574 |
Additional fair value disclosures | Fair value information regarding our debt is as follows: December 31, 2019 December 31, 2018 (millions) Carrying Amount Fair Value Carrying Amount Fair Value Debt $ 7,379 $ 8,033 $ 6,452 $ 6,121 |
Annual maturities of outstanding debt | As of December 31, 2019 , annual maturities of outstanding debt, excluding finance lease obligations, were as follows: Debt Principal Payments (millions) Noble Energy Excluding Noble Midstream Partners Noble Midstream Partners Total 2020 $ — $ — $ — 2021 — 500 500 2022 — 400 400 2023 100 595 695 2024 650 — 650 Thereafter 5,134 — 5,134 Total $ 5,884 $ 1,495 $ 7,379 |
Exit Cost - Transportation Co_2
Exit Cost - Transportation Commitments (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Commitments and Contingencies Disclosure [Abstract] | |
Summary of Financial Commitments | Exit Costs Reconciliation of accrued exit costs at December 31, 2019 is as follows: December 31, (millions) 2019 2018 Balance at Beginning of Period $ 80 $ 90 Exit Cost Accrual (1) 88 — Payments, Net of Accretion (5 ) (10 ) Balance at End of Period $ 163 $ 80 Less Current Portion Included in Other Current Liabilities 34 13 Long-term Portion Included in Other Noncurrent Liabilities $ 129 $ 67 (1) Amount includes $92 million exit cost for the permanent assigned discussed above, offset by a gain of $4 million . Revenues and expenses associated with these long-term financial commitments, including mitigation activities discussed above, were as follows: Year Ended December 31, (millions) 2019 2018 2017 Sales of Purchased Gas $ 90 $ 113 $ — Cost of Purchased of Gas 85 108 — Utilized Firm Transportation Expense 57 29 — Unutilized Firm Transportation Expense 1 3 — Cost of Purchased Gas, Total $ 143 $ 140 $ — |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Commitments and Contingencies Disclosure [Abstract] | |
Minimum commitments | Minimum commitments as of December 31, 2019 consist of the following: (millions) Purchase and Service Obligations Marcellus Shale Firm Transportation Obligations (1) Gathering, Transportation & Processing Obligations (2) Operating Lease Obligations (3) Finance Lease Obligations (3) Total 2020 $ 135 $ 143 $ 174 $ 100 $ 52 $ 604 2021 28 102 176 60 38 404 2022 14 85 156 41 27 323 2023 30 83 153 26 23 315 2024 2 92 149 15 21 279 2025 and Thereafter 72 675 334 37 86 1,204 Total $ 281 $ 1,180 $ 1,142 $ 279 $ 247 $ 3,129 (1) Amount includes exit cost obligations resulting from permanent capacity assignments. See Note 11. Exit Cost – Transportation Commitments . (2) Amount includes US onshore and Eastern Mediterranean transportation obligations of $ 921 million, undiscounted, and Noble Midstream Partners obligations of $221 million, undiscounted. (3) See Note 9. Leases . |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | |
Components of Income Before Income Taxes Table | Components of (loss) income from operations before income taxes are as follows: Year Ended December 31, (millions) 2019 2018 2017 Domestic $ (2,222 ) $ (953 ) $ (2,831 ) Foreign 446 1,093 640 Total $ (1,776 ) $ 140 $ (2,191 ) |
Components of Income Tax Provision Table | The income tax (benefit) provision consists of the following: Year Ended December 31, (millions, except percentages) 2019 2018 2017 Current Taxes Federal $ 1 $ 22 $ (11 ) State 3 2 1 Foreign 81 172 96 Total Current $ 85 $ 196 $ 86 Deferred Taxes Federal $ (413 ) $ (123 ) $ (1,258 ) State (25 ) (7 ) (8 ) Foreign 10 60 39 Total Deferred $ (428 ) $ (70 ) $ (1,227 ) Total Income Tax (Benefit) Provision Attributable to Noble Energy $ (343 ) $ 126 $ (1,141 ) Effective Tax Rate 19.3 % 90.0 % 52.1 % |
Tax Rate Reconciliation Table | A reconciliation of the federal statutory tax rate to the ETR is as follows: Year Ended December 31, (percentages) 2019 2018 2017 Federal Statutory Rate 21.0 % 21.0 % 35.0 % Effect of Goodwill Impairment — 192.5 — Change in Valuation Allowance (0.6 ) (170.2 ) (17.4 ) US and Foreign Statutory Rate Change — 80.7 23.5 Accumulated Undistributed Foreign Earnings — — 11.0 Transition Tax — — (4.8 ) Difference Between US and Foreign Rates (0.6 ) 17.9 1.8 Earnings of Equity Method Investments 0.7 (20.1 ) 1.9 Noncontrolling Interests 0.9 (12.1 ) 1.1 State Taxes 1.1 0.9 0.3 Foreign Exploration Loss — (35.6 ) — Global Intangible Low-Taxed Income (GILTI) (0.8 ) 24.2 — Return to Provision — (17.1 ) (0.1 ) Audit Settlement — 5.1 0.1 Oil Profits Tax - Israel (0.1 ) 3.3 (0.1 ) Other, Net (2.3 ) (0.5 ) (0.2 ) Effective Rate 19.3 % 90.0 % 52.1 % There were no material items impacting our 2019 ETR as compared to the federal statutory rate of 21%. Our 2018 ETR included a significant deferred tax benefit, discussed below, recorded as a result of the intent of the US Department of the Treasury (Treasury) and Internal Revenue Service (IRS) to issue additional regulatory guidance associated with the Tax Cuts and Jobs Act (Tax Reform Legislation) and the transition tax. In addition, the 2018 ETR was impacted by low earnings, goodwill impairment with no tax benefit, deferred tax expense of $34 million related to GILTI, discussed below, and a deferred tax benefit of $50 million associated with a write-off of foreign exploration losses. Our 2017 ETR was driven by the deferred tax benefit related to the Tax Reform Legislation, as we revalued the ending deferred tax liability at the reduced future tax rate. |
Deferred Tax Assets and Liabilities | Deferred tax assets and liabilities resulted from the following: December 31, (millions) 2019 2018 Deferred Tax Assets Loss Carryforwards (1) $ 656 $ 589 Employee Compensation and Benefits 92 92 Mark to Market of Commodity Derivative Instruments 11 (27 ) Foreign Tax Credits 133 138 Other 126 157 Total Deferred Tax Assets $ 1,018 $ 949 Valuation Allowance - Foreign Loss Carryforwards and Foreign Tax Credits (327 ) (320 ) Net Deferred Tax Assets $ 691 $ 629 Deferred Tax Liabilities Property, Plant and Equipment, Principally Due to Differences in Depreciation, Amortization, Lease Impairment and Abandonments (1,338 ) (1,669 ) Total Deferred Tax Liability $ (1,338 ) $ (1,669 ) Net Deferred Tax Liability $ (647 ) $ (1,040 ) (1) At December 31, 2019, $459 million related to domestic tax (state and federal) and $197 million related to foreign tax. Net deferred tax assets and liabilities were classified in the consolidated balance sheets as follows: December 31, (millions) 2019 2018 Deferred Income Tax Asset - Noncurrent $ 15 $ 21 Deferred Income Tax Liability - Noncurrent (662 ) (1,061 ) Net Deferred Tax Liability $ (647 ) $ (1,040 ) |
Derivative Instruments and He_2
Derivative Instruments and Hedging Activities (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Unsettled Derivative Instruments | As of December 31, 2019 , we had entered into the following crude oil derivative instruments: Swaps Collars Settlement Period Type of Contract Index Bbls per Day Weighted Average Differential Weighted Average Fixed Price Weighted Average Short Put Price Weighted Average Floor Price Weighted Average Ceiling Price 2020 Sold Calls NYMEX WTI 8,000 $ — $ 65.59 $ — $ — $ — 2020 Swaps NYMEX WTI 35,000 — 58.12 — — — 2020 Three-Way Collars NYMEX WTI 30,000 — — 48.33 57.87 64.27 Jan2020-Jun2020 Swaps NYMEX WTI 24,000 — 59.54 — — — Jul2020-Dec2020 Call Swaption NYMEX WTI 11,000 — 58.95 — — — 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. As of December 31, 2019 , we had entered into the following NGL derivative instruments: Swaps Settlement Period Type of Contract Index Bbls per Day Weighted Average Fixed Price Apr 2020-Sept 2020 Ethane Swaps Mont Belvieu 2,000 $ 7.77 Apr 2020-Sept 2020 Propane Swaps Mont Belvieu 5,000 21.04 Apr 2020-Sept 2020 Isobutane Swaps Mont Belvieu 1,000 25.36 Apr 2020-Sept 2020 Butane Swaps Mont Belvieu 1,500 24.31 As of December 31, 2019 , we had entered into the following natural gas derivative instruments: Swaps Collars Settlement Period Type of Contract Index MMBtu per Day Weighted Average Differential Weighted Average Fixed Price Weighted Average Short Put Price Weighted Average Floor Price Weighted Average Ceiling Price Apr2020-Dec2020 Swaps NYMEX HH 90,000 $ — $ 2.60 $ — $ — $ — Apr2020-Oct2020 Three-Way Collars NYMEX HH 40,000 — — 2.25 2.70 2.85 2020 Sold Puts NYMEX HH 90,000 — — 2.15 — — 2020 Basis Swaps CIG (1) 139,000 (0.56 ) — — — — 2020 Basis Swaps Waha (1) 49,500 (1.05 ) — — — — 2021 Basis Swaps CIG (1) 60,000 (0.52 ) — — — — 2021 Basis Swaps Waha (1) 14,000 (0.60 ) — — — — (1) We have entered into natural gas basis swap contracts in order to establish a fixed amount for the differential between index pricing for Colorado Interstate Gas (CIG) and Waha Hub versus NYMEX Henry Hub (HH). The weighted average differential represents the amount of reduction to NYMEX HH prices for the notional volumes covered by the basis swap contracts. |
Fair Value of Derivative Instruments | The fair values of derivative instruments on our consolidated balance sheets were as follows (in millions): Asset Derivative Instruments Liability Derivative Instruments Balance Sheet Location December 31, 2019 December 31, 2018 Balance Sheet Location December 31, 2019 December 31, 2018 Other Current Assets $ 14 $ 180 Other Current Liabilities $ 36 $ 1 Other Noncurrent Assets 1 — Other Noncurrent Liabilities 1 26 Total Assets $ 15 $ 180 Total Liabilities $ 37 $ 27 |
Effect of derivative instruments on consolidated statement of operations | The effect of derivative instruments on our consolidated statements of operations was as follows: Year Ended December 31, (millions) 2019 2018 2017 Cash (Received) Paid in Settlement of Commodity Derivative Instruments Crude Oil $ (10 ) $ 162 $ (14 ) Natural Gas (22 ) (1 ) 1 Total Cash (Received) Paid in Settlement of Commodity Derivative Instruments (32 ) 161 (13 ) Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments Crude Oil 184 (225 ) 18 NGLs (3 ) — — Natural Gas (6 ) 1 (68 ) Total Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments 175 (224 ) (50 ) Loss (Gain) on Commodity Derivative Instruments Crude Oil 174 (63 ) 4 NGLs (3 ) — — Natural Gas (28 ) — (67 ) Total Loss (Gain) on Commodity Derivative Instruments $ 143 $ (63 ) $ (63 ) |
Additional Shareholders' Equi_2
Additional Shareholders' Equity Information (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Equity [Abstract] | |
Common Stock and Treasury Stock | Common Stock and Treasury Stock Activity in shares of our common stock and treasury stock was as follows: Year Ended December 31, 2019 2018 Shares of Common Stock Issued Shares, Beginning of Period 521,055,001 528,743,381 Exercise of Common Stock Options — 576,617 Restricted Stock Awarded, Net of Forfeitures 2,768,731 2,488,363 Purchase and Retirement of Common Stock (1) — (10,008,128 ) Adjustment to Shares Exchanged in Clayton Williams Energy Acquisition — (745,232 ) Shares, End of Period 523,823,732 521,055,001 Treasury Stock Shares, Beginning of Period 38,851,988 38,786,969 Shares Received in Payment of Withholding Taxes Due on Vesting of Shares of Restricted Stock 240,865 267,258 Rabbi Trust Shares Distributed and/or Sold (203,063 ) (202,239 ) Shares, End of Period 38,889,790 38,851,988 Additional Information Incremental Shares From Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust — — Number of Antidilutive Stock Options, Shares of Restricted Stock and Shares of Common Stock in Rabbi Trust excluded from Dilutive Earnings (Loss) per Share (2) 13,892,742 15,004,591 (1) On February 15, 2018, we announced that the Company's Board of Directors had authorized a share repurchase program of $750 million which expires December 31, 2020. In 2019, no shares were repurchased and retired. In 2018 , shares were repurchased and retired at an average price of $29.49 per share. (2) For the years ended December 31, 2019 and 2018 , all outstanding options and non-vested restricted shares have been excluded from the calculation of diluted earnings (loss) per share as Noble Energy incurred a loss. Therefore, inclusion of outstanding options and non-vested restricted shares in the calculation of diluted earnings (loss) per share would be anti-dilutive. |
Accumulated Other Comprehensive Loss (AOCL) | Accumulated Other Comprehensive Loss (AOCL) AOCL in the shareholders’ equity section of the balance sheet included: (millions) Interest Rate Cash Flow Hedge Other Postretirement Benefit Plans Total December 31, 2016 $ (21 ) $ (10 ) $ (31 ) Realized Amounts Reclassified Into Earnings 1 4 5 Unrealized Change in Fair Value — (4 ) (4 ) December 31, 2017 (20 ) (10 ) (30 ) Realized Amounts Reclassified Into Earnings (3 ) 1 (2 ) December 31, 2018 (23 ) (9 ) (32 ) Realized Amounts Reclassified Into Earnings 1 — 1 December 31, 2019 $ (22 ) $ (9 ) $ (31 ) |
Stock-Based and Other Compens_2
Stock-Based and Other Compensation Plans (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Share-based Payment Arrangement [Abstract] | |
Stock-based compensation expense | We recognized total stock-based compensation expense as follows: Year Ended December 31, (millions) 2019 2018 2017 General and Administrative Expense $ 59 $ 54 $ 56 Exploration Expense and Other 9 8 48 Total Stock-Based Compensation Expense (1) $ 68 $ 62 $ 104 Tax Benefit Recognized $ (14 ) $ (13 ) $ (36 ) (1) 2019 amount excludes $8 million capitalized to property, plant and equipment. |
Valuation Assumptions, Options | The assumptions used in valuing stock options granted were as follows: Year Ended December 31, (weighted averages) 2019 2018 2017 Expected Term (in Years) 6.9 6.7 6.4 Expected Volatility 33.8 % 33.4 % 33.2 % Risk-Free Rate 2.7 % 2.6 % 2.2 % Expected Dividend Yield 1.4 % 1.2 % 0.9 % Weighted Average Grant-Date Fair Value $ 7.57 $ 10.47 $ 13.26 |
Award Activity, Options | Stock option activity was as follows: Options Weighted Average Exercise Price Weighted Average Remaining Contractual Term Aggregate Intrinsic Value (per share) (years) (millions) Outstanding at December 31, 2018 13,852,020 $ 44.04 Granted 461,311 22.15 Forfeited (51,100 ) 34.72 Expired (1,686,478 ) 35.26 Outstanding at December 31, 2019 12,575,753 $ 44.62 4.2 $ 1 Exercisable at December 31, 2019 11,373,846 $ 46.11 3.7 $ — |
Valuation Assumptions, Restricted Stock | The assumptions used in valuing market based restricted stock awards granted were as follows: Year Ended December 31, 2019 2018 2017 Number of Simulations 10,000,000 10,000,000 500,000 Expected Volatility 37.5 % 35.0 % 35.0 % Risk-Free Rate 2.5 % 2.3 % 1.5 % |
Award Activity, Restricted Stock | Restricted stock activity was as follows: Subject to Time Vesting Subject to Market Conditions Number of Shares Weighted Average Award Date Fair Value Number of Shares Weighted Average Award Date Fair Value (per share) (per share) Outstanding at December 31, 2018 3,172,891 $ 32.72 1,385,634 $ 21.74 Awarded 2,464,682 22.33 1,138,730 13.50 Vested (906,485 ) 34.11 — — Forfeited (486,733 ) 27.97 (347,948 ) 21.20 Outstanding at December 31, 2019 4,244,355 $ 27.02 2,176,416 $ 17.52 |
Award Activity, Phantom Units | Phantom unit activity was as follows: Subject to Time Vesting Subject to Market Conditions Number of Units Weighted Average Award Date Fair Value Number of Units Weighted Average Award Date Fair Value (per share) (per share) Outstanding at December 31, 2018 467,365 $ 31.65 150,296 $ 6.82 Awarded 803,606 22.39 — — Vested (462,823 ) 31.65 — — Forfeited (92,762 ) 22.55 (150,296 ) 6.82 Outstanding at December 31, 2019 715,386 $ 22.39 — $ — |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies - Narrative (Details) $ in Millions | 1 Months Ended | 12 Months Ended | |||
Mar. 31, 2019USD ($) | Dec. 31, 2019USD ($)$ / MMBTU | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Jan. 01, 2019USD ($) | |
Property, Plant and Equipment [Line Items] | |||||
Proceeds from issuance of mezzanine equity, net of offering costs | $ 97 | $ 0 | $ 0 | ||
Preferred stock, dividend rate, percentage | 6.50% | ||||
Intangible assets, net | $ 278 | $ 310 | |||
Intangible assets, accumulated amortization | $ 62 | ||||
Long-term contract sales price per unit (usd per MMBtu) | $ / MMBTU | 0.25 | ||||
Operating lease, right-of-use asset | $ 227 | ||||
Lease liabilities | $ 252 | ||||
Accounting Standards Update 2016-02 | |||||
Property, Plant and Equipment [Line Items] | |||||
Operating lease, right-of-use asset | $ 282 | ||||
Lease liabilities | $ 287 | ||||
Minimum | |||||
Property, Plant and Equipment [Line Items] | |||||
Useful lives of gathering facilitates and processing plants (in years) | 3 years | ||||
Intangible asset, useful life | 7 years | ||||
Lease renewal term | 1 month | ||||
Maximum | |||||
Property, Plant and Equipment [Line Items] | |||||
Useful lives of gathering facilitates and processing plants (in years) | 30 years | ||||
Intangible asset, useful life | 13 years | ||||
Lease renewal term | 1 year | ||||
Noble Midstream | |||||
Property, Plant and Equipment [Line Items] | |||||
Redeemable convertible preferred stock | $ 200 | ||||
Proceeds from issuance of mezzanine equity, net of offering costs | 100 | ||||
Redeemable convertible preferred stock, remaining over next year | $ 100 |
Summary of Significant Accoun_5
Summary of Significant Accounting Policies - Remaining Performance Obligation (Details) $ in Millions | Dec. 31, 2019USD ($) |
Accounting Policies [Abstract] | |
Remaining performance obligation amount | $ 8,519 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | |
Accounting Policies [Abstract] | |
Remaining performance obligation amount | $ 743 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Remaining performance obligation, expected timing of satisfaction | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | |
Accounting Policies [Abstract] | |
Remaining performance obligation amount | $ 768 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Remaining performance obligation, expected timing of satisfaction | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | |
Accounting Policies [Abstract] | |
Remaining performance obligation amount | $ 583 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Remaining performance obligation, expected timing of satisfaction | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | |
Accounting Policies [Abstract] | |
Remaining performance obligation amount | $ 583 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Remaining performance obligation, expected timing of satisfaction | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | |
Accounting Policies [Abstract] | |
Remaining performance obligation amount | $ 583 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Remaining performance obligation, expected timing of satisfaction | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | |
Accounting Policies [Abstract] | |
Remaining performance obligation amount | $ 5,259 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Remaining performance obligation, expected timing of satisfaction |
Additional Financial Statemen_3
Additional Financial Statement Information - Additional Income Statement Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Other Revenue | |||
Revenue from Sales | $ 4,438 | $ 4,986 | $ 4,256 |
Production Expense | |||
Lease Operating Expense | 532 | ||
Lease Operating Expense | 576 | 571 | |
Production and Ad Valorem Taxes | 175 | 190 | 118 |
Gathering, Transportation and Processing Expense | 417 | 393 | 432 |
Other Royalty Expense | 13 | 38 | 20 |
Total Production Expense | 1,137 | 1,197 | 1,141 |
Exploration Expense | |||
Leasehold Impairment and Amortization | 0 | 1 | 62 |
Dry Hole Cost | 100 | 1 | 9 |
Seismic, Geological and Geophysical | 21 | 22 | 27 |
Staff Expense | 48 | 54 | 55 |
Other | 33 | 51 | 35 |
Total | 202 | 129 | 188 |
Loss on Marcellus Shale Upstream Divestiture and Other | |||
Loss on Sale | 0 | 0 | 2,270 |
Exit Cost | 0 | 0 | 93 |
Other | 0 | 0 | 16 |
Total | 0 | 0 | (2,379) |
Other Operating Expense, Net | |||
Marketing Expense | 34 | 40 | 47 |
Firm Transportation Exit Cost | 88 | 0 | 0 |
Clayton Williams Energy Acquisition Expenses | 0 | 0 | 100 |
Loss (Gain) on Asset Retirement Obligation Revisions | 9 | (25) | (42) |
Other, Net | 83 | 35 | 33 |
Total | 214 | 50 | 138 |
Income from Equity Method Investments and Other | |||
Other Revenue | |||
Revenue from Sales | 51 | 172 | 177 |
Midstream Services Revenues - Third Party | |||
Other Revenue | |||
Revenue from Sales | 94 | 78 | 19 |
Other Revenue | |||
Other Revenue | |||
Revenue from Sales | $ 145 | $ 250 | $ 196 |
Additional Financial Statemen_4
Additional Financial Statement Information - Additional Balance Sheet Information (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Accounts Receivable, Net | ||
Commodity Sales | $ 446 | $ 383 |
Joint Interest Billings | 164 | 137 |
Other | 128 | 111 |
Allowance | (8) | (15) |
Total | 730 | 616 |
Other Current Assets | ||
Commodity Derivative Assets | 14 | 180 |
Inventories, Materials and Supplies | 59 | 55 |
Assets Held for Sale | 14 | 133 |
Prepaid Expenses and Other Current Assets | 61 | 50 |
Total | 148 | 418 |
Other Noncurrent Assets | ||
Total Equity Method Investments | 1,066 | 286 |
Operating Lease Right-of-Use Assets | 227 | |
Customer-Related Intangible Assets, Net | 278 | 310 |
Goodwill | 110 | 110 |
Mutual Fund Investments | 27 | 38 |
Other Noncurrent Assets | 126 | 97 |
Total | 1,834 | 841 |
Other Current Liabilities | ||
Production and Ad Valorem Taxes | 118 | 103 |
Asset Retirement Obligations | 84 | 118 |
Interest Payable | 74 | 66 |
Operating Lease Liabilities | 88 | |
Compensation and Benefits Payable | 126 | 83 |
Other Current Liabilities | 229 | 149 |
Total | 719 | 519 |
Other Noncurrent Liabilities | ||
Deferred Compensation Liabilities | 133 | 147 |
Asset Retirement Obligations | 730 | 762 |
Operating Lease Liabilities | 164 | |
Firm Transportation Exit Cost Accrual | 129 | 67 |
Other Noncurrent Liabilities | 222 | 189 |
Total | $ 1,378 | $ 1,165 |
Additional Financial Statemen_5
Additional Financial Statement Information - Reconciliation of Total Cash (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Additional Financial Statement Information [Abstract] | ||||
Cash and Cash Equivalents | $ 484 | $ 716 | $ 675 | |
Restricted Cash | 0 | 3 | 38 | |
Cash, Cash Equivalents, and Restricted Cash | $ 484 | $ 719 | $ 713 | $ 1,210 |
Additional Financial Statemen_6
Additional Financial Statement Information - Supplemental Cash Flow Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Cash Paid During the Year For | |||
Interest, Net of Amount Capitalized | $ 208 | $ 270 | $ 346 |
Income Taxes Paid, Net | 76 | 172 | 121 |
Interest Capitalized | $ 102 | $ 73 | $ 49 |
Additional Financial Statemen_7
Additional Financial Statement Information - Non-Affiliated Purchasers Accounting for 10% or More of Commodity Sales (Details) - Sales - Customer Concentration Risk | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Crude Oil | Shell | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 22.00% | 22.00% | 22.00% |
Crude Oil | BP | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 18.00% | 31.00% | 15.00% |
Total Crude Oil, NGL & Natural Gas Sales | Shell | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 15.00% | 14.00% | 13.00% |
Total Crude Oil, NGL & Natural Gas Sales | BP | |||
Concentration Risk [Line Items] | |||
Concentration risk, percentage | 14.00% | 17.00% | 10.00% |
Segment Information (Details)
Segment Information (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Segment Reporting Information [Line Items] | |||||
Total Revenues | $ 4,438 | $ 4,986 | $ 4,256 | ||
Lease Operating Expense | 532 | ||||
Lease Operating Expense | 576 | 571 | |||
Production and Ad Valorem Taxes | 175 | 190 | 118 | ||
Gathering, Transportation and Processing Expense | 417 | 393 | 432 | ||
Other Royalty Expense | 13 | 38 | 20 | ||
Total Production Expense | 1,137 | 1,197 | 1,141 | ||
Exploration Expense | 202 | 129 | 188 | ||
Depreciation, Depletion and Amortization | 2,197 | 1,934 | 2,053 | ||
Loss on Marcellus Shale Upstream Divestiture and Other | 0 | 0 | 2,379 | ||
(Gain) Loss on Divestitures, Net | 0 | (843) | (326) | ||
Asset Impairments | 1,160 | 206 | 70 | ||
Goodwill Impairment | $ 1,300 | 0 | 1,281 | 0 | |
Clayton Williams Energy Acquisition Expenses | 0 | 0 | 100 | ||
Cost of Purchased Oil and Gas | 431 | 296 | 0 | ||
Firm Transportation Exit Cost | 88 | 0 | 0 | ||
Gain on Asset Retirement Obligation Revision | 9 | (25) | (42) | ||
Loss (Gain) on Commodity Derivative Instruments | 143 | (63) | (63) | ||
Loss on Debt Extinguishment | $ 44 | 44 | 8 | 98 | |
(Loss) Income Before Income Taxes | (1,776) | 140 | (2,191) | ||
Additions to Long Lived Assets, Excluding Acquisitions | 2,408 | 3,253 | 2,851 | ||
Additions to Equity Method Investments | 799 | 0 | 68 | ||
Property, Plant and Equipment, Net | 17,451 | 17,451 | |||
Property, Plant and Equipment, Net | 18,419 | 18,419 | 17,502 | ||
Oil, NGL and Gas Sales | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 3,904 | 4,461 | 4,060 | ||
Crude Oil Sales | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 2,736 | 2,945 | 2,346 | ||
NGL Sales | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 354 | 587 | 493 | ||
Natural Gas Sales | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 814 | 929 | 1,221 | ||
Sales of Purchased Oil and Gas | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 389 | 275 | 0 | ||
Cost of Purchased Oil and Gas | 85 | 108 | 0 | ||
Income (Loss) from Equity Method Investments and Other | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 51 | 172 | 177 | ||
Midstream Services Revenues - Third Party | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 94 | 78 | 19 | ||
Operating Segments | United States | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 3,253 | 3,590 | 3,156 | ||
Lease Operating Expense | 460 | ||||
Lease Operating Expense | 480 | 466 | |||
Production and Ad Valorem Taxes | 169 | 184 | 115 | ||
Gathering, Transportation and Processing Expense | 598 | 533 | 550 | ||
Other Royalty Expense | 13 | 38 | 20 | ||
Total Production Expense | 1,240 | 1,235 | 1,151 | ||
Exploration Expense | 57 | 48 | 102 | ||
Depreciation, Depletion and Amortization | 1,907 | 1,642 | 1,739 | ||
Loss on Marcellus Shale Upstream Divestiture and Other | 2,286 | ||||
(Gain) Loss on Divestitures, Net | 36 | (325) | |||
Asset Impairments | 1,160 | 169 | 63 | ||
Goodwill Impairment | 1,281 | ||||
Clayton Williams Energy Acquisition Expenses | 100 | ||||
Cost of Purchased Oil and Gas | 107 | 20 | |||
Firm Transportation Exit Cost | 0 | ||||
Gain on Asset Retirement Obligation Revision | 0 | 0 | |||
Loss (Gain) on Commodity Derivative Instruments | 125 | (70) | (92) | ||
Loss on Debt Extinguishment | 0 | 0 | |||
(Loss) Income Before Income Taxes | (1,431) | (875) | (2,365) | ||
Additions to Long Lived Assets, Excluding Acquisitions | 1,651 | 2,115 | 1,994 | ||
Additions to Equity Method Investments | 0 | ||||
Property, Plant and Equipment, Net | 11,859 | 11,859 | |||
Property, Plant and Equipment, Net | 13,044 | 13,044 | 13,348 | ||
Operating Segments | United States | Oil, NGL and Gas Sales | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 3,136 | 3,570 | 3,156 | ||
Operating Segments | United States | Crude Oil Sales | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 2,437 | 2,548 | 1,993 | ||
Operating Segments | United States | NGL Sales | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 354 | 587 | 493 | ||
Operating Segments | United States | Natural Gas Sales | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 345 | 435 | 670 | ||
Operating Segments | United States | Sales of Purchased Oil and Gas | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 109 | 20 | |||
Operating Segments | United States | Income (Loss) from Equity Method Investments and Other | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 8 | 0 | 0 | ||
Operating Segments | United States | Midstream Services Revenues - Third Party | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 0 | 0 | 0 | ||
Operating Segments | Eastern Mediterranean | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 457 | 480 | 534 | ||
Lease Operating Expense | 37 | ||||
Lease Operating Expense | 26 | 29 | |||
Production and Ad Valorem Taxes | 0 | 0 | 0 | ||
Gathering, Transportation and Processing Expense | 1 | 0 | 0 | ||
Other Royalty Expense | 0 | 0 | 0 | ||
Total Production Expense | 38 | 26 | 29 | ||
Exploration Expense | 109 | 7 | 2 | ||
Depreciation, Depletion and Amortization | 67 | 60 | 76 | ||
Loss on Marcellus Shale Upstream Divestiture and Other | 0 | ||||
(Gain) Loss on Divestitures, Net | (376) | (1) | |||
Asset Impairments | 0 | 0 | 0 | ||
Goodwill Impairment | 0 | ||||
Clayton Williams Energy Acquisition Expenses | 0 | ||||
Cost of Purchased Oil and Gas | 0 | 0 | |||
Firm Transportation Exit Cost | 0 | ||||
Gain on Asset Retirement Obligation Revision | (8) | 0 | |||
Loss (Gain) on Commodity Derivative Instruments | 0 | 0 | 0 | ||
Loss on Debt Extinguishment | 0 | 0 | |||
(Loss) Income Before Income Taxes | 199 | 742 | 413 | ||
Additions to Long Lived Assets, Excluding Acquisitions | 505 | 671 | 411 | ||
Additions to Equity Method Investments | 189 | ||||
Property, Plant and Equipment, Net | 3,041 | 3,041 | |||
Property, Plant and Equipment, Net | 2,630 | 2,630 | 2,005 | ||
Operating Segments | Eastern Mediterranean | Oil, NGL and Gas Sales | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 457 | 480 | 534 | ||
Operating Segments | Eastern Mediterranean | Crude Oil Sales | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 6 | 7 | 6 | ||
Operating Segments | Eastern Mediterranean | NGL Sales | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 0 | 0 | 0 | ||
Operating Segments | Eastern Mediterranean | Natural Gas Sales | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 451 | 473 | 528 | ||
Operating Segments | Eastern Mediterranean | Sales of Purchased Oil and Gas | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 0 | 0 | |||
Operating Segments | Eastern Mediterranean | Income (Loss) from Equity Method Investments and Other | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 0 | 0 | 0 | ||
Operating Segments | Eastern Mediterranean | Midstream Services Revenues - Third Party | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 0 | 0 | 0 | ||
Operating Segments | West Africa | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 372 | 543 | 490 | ||
Lease Operating Expense | 76 | ||||
Lease Operating Expense | 97 | 90 | |||
Production and Ad Valorem Taxes | 0 | 0 | 0 | ||
Gathering, Transportation and Processing Expense | 0 | 0 | 0 | ||
Other Royalty Expense | 0 | 0 | 0 | ||
Total Production Expense | 76 | 97 | 90 | ||
Exploration Expense | 13 | 6 | 5 | ||
Depreciation, Depletion and Amortization | 83 | 115 | 146 | ||
Loss on Marcellus Shale Upstream Divestiture and Other | 0 | ||||
(Gain) Loss on Divestitures, Net | 0 | 0 | |||
Asset Impairments | 0 | 0 | 0 | ||
Goodwill Impairment | 0 | ||||
Clayton Williams Energy Acquisition Expenses | 0 | ||||
Cost of Purchased Oil and Gas | 0 | 0 | |||
Firm Transportation Exit Cost | 0 | ||||
Gain on Asset Retirement Obligation Revision | 0 | 0 | |||
Loss (Gain) on Commodity Derivative Instruments | 18 | 7 | 29 | ||
Loss on Debt Extinguishment | 0 | 0 | |||
(Loss) Income Before Income Taxes | 164 | 305 | 203 | ||
Additions to Long Lived Assets, Excluding Acquisitions | 70 | 12 | 34 | ||
Additions to Equity Method Investments | 0 | ||||
Property, Plant and Equipment, Net | 793 | 793 | |||
Property, Plant and Equipment, Net | 805 | 805 | 863 | ||
Operating Segments | West Africa | Oil, NGL and Gas Sales | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 311 | 411 | 370 | ||
Operating Segments | West Africa | Crude Oil Sales | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 293 | 390 | 347 | ||
Operating Segments | West Africa | NGL Sales | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 0 | 0 | 0 | ||
Operating Segments | West Africa | Natural Gas Sales | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 18 | 21 | 23 | ||
Operating Segments | West Africa | Sales of Purchased Oil and Gas | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 0 | 0 | |||
Operating Segments | West Africa | Income (Loss) from Equity Method Investments and Other | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 61 | 132 | 120 | ||
Operating Segments | West Africa | Midstream Services Revenues - Third Party | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 0 | 0 | 0 | ||
Operating Segments | Other Int'l | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 0 | 0 | 0 | ||
Lease Operating Expense | 0 | ||||
Lease Operating Expense | 0 | 0 | |||
Production and Ad Valorem Taxes | 0 | 0 | 0 | ||
Gathering, Transportation and Processing Expense | 0 | 0 | 0 | ||
Other Royalty Expense | 0 | 0 | 0 | ||
Total Production Expense | 0 | 0 | 0 | ||
Exploration Expense | 23 | 68 | 79 | ||
Depreciation, Depletion and Amortization | 1 | 2 | 4 | ||
Loss on Marcellus Shale Upstream Divestiture and Other | 0 | ||||
(Gain) Loss on Divestitures, Net | 0 | 0 | |||
Asset Impairments | 0 | 0 | 7 | ||
Goodwill Impairment | 0 | ||||
Clayton Williams Energy Acquisition Expenses | 0 | ||||
Cost of Purchased Oil and Gas | 0 | 0 | |||
Firm Transportation Exit Cost | 0 | ||||
Gain on Asset Retirement Obligation Revision | (17) | (42) | |||
Loss (Gain) on Commodity Derivative Instruments | 0 | 0 | 0 | ||
Loss on Debt Extinguishment | 0 | 0 | |||
(Loss) Income Before Income Taxes | (25) | (53) | (54) | ||
Additions to Long Lived Assets, Excluding Acquisitions | 20 | 0 | (34) | ||
Additions to Equity Method Investments | 0 | ||||
Property, Plant and Equipment, Net | 44 | 44 | |||
Property, Plant and Equipment, Net | 37 | 37 | 25 | ||
Operating Segments | Other Int'l | Oil, NGL and Gas Sales | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 0 | 0 | 0 | ||
Operating Segments | Other Int'l | Crude Oil Sales | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 0 | 0 | 0 | ||
Operating Segments | Other Int'l | NGL Sales | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 0 | 0 | 0 | ||
Operating Segments | Other Int'l | Natural Gas Sales | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 0 | 0 | 0 | ||
Operating Segments | Other Int'l | Sales of Purchased Oil and Gas | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 0 | 0 | |||
Operating Segments | Other Int'l | Income (Loss) from Equity Method Investments and Other | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 0 | 0 | 0 | ||
Operating Segments | Other Int'l | Midstream Services Revenues - Third Party | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 0 | 0 | 0 | ||
Noble Midstream Partners | Midstream | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 693 | 611 | 353 | ||
Lease Operating Expense | 4 | ||||
Lease Operating Expense | 0 | 0 | |||
Production and Ad Valorem Taxes | 6 | 6 | 3 | ||
Gathering, Transportation and Processing Expense | 110 | 95 | 70 | ||
Other Royalty Expense | 0 | 0 | 0 | ||
Total Production Expense | 120 | 101 | 73 | ||
Exploration Expense | 0 | 0 | 0 | ||
Depreciation, Depletion and Amortization | 104 | 87 | 30 | ||
Loss on Marcellus Shale Upstream Divestiture and Other | 0 | ||||
(Gain) Loss on Divestitures, Net | (503) | 0 | |||
Asset Impairments | 0 | 37 | 0 | ||
Goodwill Impairment | 0 | ||||
Clayton Williams Energy Acquisition Expenses | 0 | ||||
Cost of Purchased Oil and Gas | 181 | 136 | |||
Firm Transportation Exit Cost | 0 | ||||
Gain on Asset Retirement Obligation Revision | 0 | 0 | |||
Loss (Gain) on Commodity Derivative Instruments | 0 | 0 | 0 | ||
Loss on Debt Extinguishment | 0 | 0 | |||
(Loss) Income Before Income Taxes | 258 | 726 | 233 | ||
Additions to Long Lived Assets, Excluding Acquisitions | 230 | 521 | 423 | ||
Additions to Equity Method Investments | 610 | ||||
Property, Plant and Equipment, Net | 1,721 | 1,721 | |||
Property, Plant and Equipment, Net | 1,742 | 1,742 | 1,027 | ||
Noble Midstream Partners | Midstream | Oil, NGL and Gas Sales | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 0 | 0 | 0 | ||
Noble Midstream Partners | Midstream | Crude Oil Sales | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 0 | 0 | 0 | ||
Noble Midstream Partners | Midstream | NGL Sales | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 0 | 0 | 0 | ||
Noble Midstream Partners | Midstream | Natural Gas Sales | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 0 | 0 | 0 | ||
Noble Midstream Partners | Midstream | Sales of Purchased Oil and Gas | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 190 | 142 | |||
Noble Midstream Partners | Midstream | Income (Loss) from Equity Method Investments and Other | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | (18) | 40 | 57 | ||
Noble Midstream Partners | Midstream | Midstream Services Revenues - Third Party | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 94 | 78 | 19 | ||
Intersegment Eliminations and Other | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | (427) | (351) | (277) | ||
Lease Operating Expense | (45) | ||||
Lease Operating Expense | (27) | (14) | |||
Production and Ad Valorem Taxes | 0 | 0 | 0 | ||
Gathering, Transportation and Processing Expense | (292) | (235) | (188) | ||
Other Royalty Expense | 0 | 0 | 0 | ||
Total Production Expense | (337) | (262) | (202) | ||
Exploration Expense | 0 | 0 | 0 | ||
Depreciation, Depletion and Amortization | (29) | (20) | (5) | ||
Loss on Marcellus Shale Upstream Divestiture and Other | 0 | ||||
(Gain) Loss on Divestitures, Net | 0 | 0 | |||
Asset Impairments | 0 | 0 | 0 | ||
Goodwill Impairment | 0 | ||||
Clayton Williams Energy Acquisition Expenses | 0 | ||||
Cost of Purchased Oil and Gas | 0 | 0 | |||
Firm Transportation Exit Cost | 0 | ||||
Gain on Asset Retirement Obligation Revision | 0 | 0 | |||
Loss (Gain) on Commodity Derivative Instruments | 0 | 0 | 0 | ||
Loss on Debt Extinguishment | 0 | 0 | |||
(Loss) Income Before Income Taxes | (55) | (60) | (62) | ||
Additions to Long Lived Assets, Excluding Acquisitions | (92) | (91) | (79) | ||
Additions to Equity Method Investments | 0 | ||||
Property, Plant and Equipment, Net | (223) | (223) | |||
Property, Plant and Equipment, Net | (145) | (145) | (74) | ||
Intersegment Eliminations and Other | Oil, NGL and Gas Sales | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 0 | 0 | 0 | ||
Intersegment Eliminations and Other | Crude Oil Sales | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 0 | 0 | 0 | ||
Intersegment Eliminations and Other | NGL Sales | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 0 | 0 | 0 | ||
Intersegment Eliminations and Other | Natural Gas Sales | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 0 | 0 | 0 | ||
Intersegment Eliminations and Other | Sales of Purchased Oil and Gas | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 0 | 0 | |||
Intersegment Eliminations and Other | Income (Loss) from Equity Method Investments and Other | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 0 | 0 | 0 | ||
Intersegment Eliminations and Other | Midstream Services Revenues - Third Party | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 0 | 0 | |||
Corporate | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 90 | 113 | 0 | ||
Lease Operating Expense | 0 | ||||
Lease Operating Expense | 0 | 0 | |||
Production and Ad Valorem Taxes | 0 | 0 | 0 | ||
Gathering, Transportation and Processing Expense | 0 | 0 | 0 | ||
Other Royalty Expense | 0 | 0 | 0 | ||
Total Production Expense | 0 | 0 | 0 | ||
Exploration Expense | 0 | 0 | 0 | ||
Depreciation, Depletion and Amortization | 64 | 48 | 63 | ||
Loss on Marcellus Shale Upstream Divestiture and Other | 93 | ||||
(Gain) Loss on Divestitures, Net | 0 | 0 | |||
Asset Impairments | 0 | 0 | 0 | ||
Goodwill Impairment | 0 | ||||
Clayton Williams Energy Acquisition Expenses | 0 | ||||
Cost of Purchased Oil and Gas | 143 | 140 | |||
Firm Transportation Exit Cost | 88 | ||||
Gain on Asset Retirement Obligation Revision | 0 | 0 | |||
Loss (Gain) on Commodity Derivative Instruments | 0 | 0 | 0 | ||
Loss on Debt Extinguishment | 44 | 98 | |||
(Loss) Income Before Income Taxes | (886) | (645) | (559) | ||
Additions to Long Lived Assets, Excluding Acquisitions | 24 | 25 | 102 | ||
Additions to Equity Method Investments | 0 | ||||
Property, Plant and Equipment, Net | $ 216 | 216 | |||
Property, Plant and Equipment, Net | $ 306 | 306 | 308 | ||
Corporate | Oil, NGL and Gas Sales | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 0 | 0 | 0 | ||
Corporate | Crude Oil Sales | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 0 | 0 | 0 | ||
Corporate | NGL Sales | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 0 | 0 | 0 | ||
Corporate | Natural Gas Sales | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 0 | 0 | 0 | ||
Corporate | Sales of Purchased Oil and Gas | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 90 | 113 | |||
Corporate | Income (Loss) from Equity Method Investments and Other | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | 0 | 0 | 0 | ||
Corporate | Midstream Services Revenues - Third Party | |||||
Segment Reporting Information [Line Items] | |||||
Total Revenues | $ 0 | $ 0 | $ 0 |
Acquisitions and Divestitures (
Acquisitions and Divestitures (Details) | Jan. 31, 2018USD ($) | Apr. 24, 2017USD ($)shares | Nov. 30, 2019USD ($)shares | Feb. 28, 2019USD ($)a | Dec. 31, 2018USD ($) | Sep. 30, 2018USD ($) | Jan. 31, 2018USD ($) | Jun. 30, 2017USD ($)shares | Dec. 31, 2018USD ($) | Mar. 31, 2018USD ($)shares | Dec. 31, 2017USD ($)well | Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($)a | Dec. 31, 2017USD ($)apaymentwell |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Gain (loss) on sale | $ 0 | $ 843,000,000 | $ 326,000,000 | |||||||||||
Proceeds from divestitures | 173,000,000 | 1,999,000,000 | 2,073,000,000 | |||||||||||
Pre-tax loss on divestiture | 88,000,000 | 0 | 0 | |||||||||||
Goodwill | $ 110,000,000 | $ 110,000,000 | 110,000,000 | 110,000,000 | ||||||||||
Severance, consulting, investment, advisory, legal and other related merger-related fees | 0 | 0 | 100,000,000 | |||||||||||
Goodwill impairment | 1,300,000,000 | 0 | 1,281,000,000 | 0 | ||||||||||
Exit costs | 88,000,000 | 0 | 0 | |||||||||||
Proceeds from issuance of common limited partners units | $ 243,000,000 | 0 | $ 312,000,000 | |||||||||||
Noble Midstream Partners LP | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Proceeds from debt | $ 420,000,000 | |||||||||||||
Saddle Butte | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Consideration transferred | $ 681,000,000 | |||||||||||||
Cash paid | 663,000,000 | |||||||||||||
Total purchase price plus liabilities assumed | 18,000,000 | $ 18,000,000 | ||||||||||||
Property, plant and equipment assumed | 206,000,000 | 206,000,000 | 206,000,000 | |||||||||||
Finite-lived intangible assets assumed | $ 340,000,000 | $ 340,000,000 | $ 340,000,000 | |||||||||||
Clayton Williams Energy | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Consideration transferred | $ 2,500,000,000 | |||||||||||||
Cash paid | $ 637,000,000 | |||||||||||||
Business acquisition, equity interest issued or issuable, number of shares | shares | 56,000,000 | |||||||||||||
Fair value of common stock issued | $ 1,900,000,000 | |||||||||||||
Severance, consulting, investment, advisory, legal and other related merger-related fees | 100,000,000 | |||||||||||||
Severance, consulting, investment, advisory, legal, and other merger related fees | 64,000,000 | |||||||||||||
Noncash share-based compensation expense | $ 36,000,000 | |||||||||||||
Revenue since acquisition | $ 99,000,000 | |||||||||||||
Pre-tax loss since acquisition | $ 19,000,000 | |||||||||||||
Stock issued (shares) | shares | 56,000,000 | |||||||||||||
Immaterial acquisitions | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Number of productive wells | well | 7 | 7 | ||||||||||||
Delaware Basin | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Consideration transferred | $ 301,000,000 | |||||||||||||
Proceeds allocated to undeveloped leasehold cost | 246,000,000 | |||||||||||||
Certain midstream assets | Noble Midstream Partners LP | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Proceeds from debt | $ 90,000,000 | |||||||||||||
Consideration transferred | 270,000,000 | |||||||||||||
Cash paid | $ 245,000,000 | |||||||||||||
Business acquisition, equity interest issued or issuable, number of shares | shares | 562,430 | |||||||||||||
Stock issued (shares) | shares | 562,430 | |||||||||||||
Proceeds from issuance of common limited partners units | $ 138,000,000 | |||||||||||||
Noble Midstream Partners LP | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Common unit, outstanding (shares) | shares | 56,500,000 | |||||||||||||
Common unit outstanding percentage | 63.00% | |||||||||||||
Greendfield Midstream | Saddle Butte | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Cash paid | $ 343,000,000 | |||||||||||||
Black Diamond | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Ownership interest in equity method investments | 54.40% | 54.40% | 54.40% | |||||||||||
Ownership Percentage | 54.40% | 54.40% | 54.40% | |||||||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations | DJ Basin | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Acreage exchange | a | 12,900 | |||||||||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Mustang and Wells Ranch | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Gain (loss) on sale | $ 0 | |||||||||||||
Acreage exchange | a | 12,300 | |||||||||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Reeves County Assets | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Oil and gas producing properties (acres) | a | 13,000 | |||||||||||||
Sales proceeds | $ 131,000,000 | |||||||||||||
Gain (loss) on sale | $ 0 | |||||||||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Remaining Midstream Interests And Assets | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Total consideration value | $ 1,600,000,000 | |||||||||||||
Proceeds from divestitures | $ 670,000,000 | |||||||||||||
Business acquisition, equity interest issued or issuable, value assigned | shares | 38,500,000 | |||||||||||||
Partners' capital account, units, contributed | $ 930,000,000 | |||||||||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Gulf of Mexico | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Gain (loss) on sale | $ (24,000,000) | |||||||||||||
Total consideration value | 480,000,000 | |||||||||||||
Proceeds from divestitures | 384,000,000 | |||||||||||||
Impairment charge | 168,000,000 | |||||||||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Tamar and Dalit Fields | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Gain (loss) on sale | $ 376,000,000 | |||||||||||||
Ownership interest sold | 7.50% | |||||||||||||
Pre-tax proceeds | $ 163,000,000 | $ 484,000,000 | ||||||||||||
Shares received in divestiture of interest in equity method investment (in shares) | shares | 38,500,000 | |||||||||||||
Consideration, shares issued, value | $ 224,000,000 | |||||||||||||
Tax effect of gain | 86,000,000 | |||||||||||||
Change in fair value | $ 190,000,000 | |||||||||||||
Discount rate for impairment model | 15.00% | |||||||||||||
Gross unrealized loss | $ 27,000,000 | |||||||||||||
Dividend income | 31,000,000 | |||||||||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Southwest Royalties | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Gain (loss) on sale | 0 | |||||||||||||
Net proceeds | $ 60,000,000 | |||||||||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Greeley Crescent Assets | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Gain (loss) on sale | $ 0 | |||||||||||||
Proceeds from divestitures | $ 68,000,000 | |||||||||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Ward County | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Proceeds from divestitures | $ 63,000,000 | |||||||||||||
Pre-tax loss on divestiture | 16,000,000 | |||||||||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Marcellus Shale | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Sales proceeds | 1,000,000,000 | |||||||||||||
Total consideration value | $ 1,200,000,000 | 1,200,000,000 | ||||||||||||
Consideration adjustment | $ 100,000,000 | |||||||||||||
Additional consideration, number of payments, divestiture | payment | 3 | |||||||||||||
Additional consideration, Individual payment amounts | $ 33,300,000 | |||||||||||||
Amounts accrued related to contingent consideration | 0 | |||||||||||||
Loss on sale, before tax | 2,300,000,000 | |||||||||||||
Loss on sale of property, after tax | 1,500,000,000 | |||||||||||||
Exit costs | 93,000,000 | |||||||||||||
Asset consideration | 3,400,000,000 | 3,400,000,000 | ||||||||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Marcellus Shale | Leaseholds and Leasehold Improvements | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Asset consideration | $ 883,000,000 | 883,000,000 | ||||||||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations | US Onshore | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Proceeds from divestitures | 671,000,000 | |||||||||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations | DJ Basin | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Proceeds from divestitures | 568,000,000 | |||||||||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Mineral and Royalty Assets | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Sales proceeds | 335,000,000 | |||||||||||||
Gain on disposition of assets | $ 334,000,000 | |||||||||||||
Mineral and royalty assets, area | a | 140,000 | |||||||||||||
Midstream | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Goodwill | $ 110,000,000 | $ 110,000,000 | $ 110,000,000 | |||||||||||
Private Placement | Noble Midstream Partners LP | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Proceeds from issuance of private placement | $ 250,000,000 | |||||||||||||
Number of common units issued (in shares) | shares | 12,000,000 |
Equity Method Investments - Sum
Equity Method Investments - Summary of Equity Method Investments (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Schedule of Equity Method Investments [Line Items] | ||
Total Equity Method Investments | $ 1,066 | $ 286 |
Difference between the carrying value of an equity method investment and the underlying net assets of the investee | $ 42 | |
Eastern Mediterranean Pipeline B.V. | ||
Schedule of Equity Method Investments [Line Items] | ||
Ownership Percentage | 25.00% | |
Total Equity Method Investments | $ 189 | 0 |
Atlantic Methanol Production Company, LLC and Affiliates | ||
Schedule of Equity Method Investments [Line Items] | ||
Ownership Percentage | 45.00% | |
Total Equity Method Investments | $ 160 | 146 |
Alba Plant LLC | ||
Schedule of Equity Method Investments [Line Items] | ||
Ownership Percentage | 28.00% | |
Total Equity Method Investments | $ 56 | 58 |
EPIC Y-Grade, LP | ||
Schedule of Equity Method Investments [Line Items] | ||
Ownership Percentage | 15.00% | |
Total Equity Method Investments | $ 166 | 0 |
EPIC Crude Holdings, LP | ||
Schedule of Equity Method Investments [Line Items] | ||
Ownership Percentage | 30.00% | |
Total Equity Method Investments | $ 339 | 0 |
Delaware Crossing LLC | ||
Schedule of Equity Method Investments [Line Items] | ||
Ownership Percentage | 50.00% | |
Total Equity Method Investments | $ 69 | 0 |
Advantage Pipeline, L.L.C. | ||
Schedule of Equity Method Investments [Line Items] | ||
Ownership Percentage | 50.00% | |
Total Equity Method Investments | $ 77 | 73 |
Other | ||
Schedule of Equity Method Investments [Line Items] | ||
Total Equity Method Investments | $ 10 | $ 9 |
Equity Method Investments - Nar
Equity Method Investments - Narrative (Details) - USD ($) shares in Millions, $ in Millions | 1 Months Ended | 12 Months Ended | |||||||
Jan. 31, 2018 | Apr. 30, 2017 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Nov. 30, 2019 | Sep. 30, 2019 | Mar. 31, 2019 | Feb. 28, 2019 | |
Equity Method Investments and Joint Ventures [Abstract] | |||||||||
Retained earnings related to undistributed earnings of equity method investees | $ 73 | ||||||||
Schedule of Equity Method Investments [Line Items] | |||||||||
Capital contributions | 189 | ||||||||
Proceeds from divestitures | 173 | $ 1,999 | $ 2,073 | ||||||
Gain on sale | $ 0 | $ 843 | $ 326 | ||||||
EMED Pipeline B.V. | |||||||||
Schedule of Equity Method Investments [Line Items] | |||||||||
Ownership interest in equity method investments | 25.00% | ||||||||
EMG | |||||||||
Schedule of Equity Method Investments [Line Items] | |||||||||
Ownership interest in equity method investments | 10.00% | ||||||||
EPIC Crude Holdings, LP | |||||||||
Schedule of Equity Method Investments [Line Items] | |||||||||
Ownership interest in equity method investments | 30.00% | ||||||||
Delaware Crossing LLC | |||||||||
Schedule of Equity Method Investments [Line Items] | |||||||||
Ownership interest in equity method investments | 50.00% | ||||||||
CONE Gathering LLC | |||||||||
Schedule of Equity Method Investments [Line Items] | |||||||||
Ownership interest in equity method investments | 34.10% | ||||||||
Eastern Mediterranean Pipeline B.V. | |||||||||
Schedule of Equity Method Investments [Line Items] | |||||||||
Ownership interest in equity method investments | 25.00% | ||||||||
Advantage Joint Venture | |||||||||
Schedule of Equity Method Investments [Line Items] | |||||||||
Payments to acquire interest in joint venture | $ 67 | ||||||||
EPIC Y-Grade, LP | |||||||||
Schedule of Equity Method Investments [Line Items] | |||||||||
Ownership interest in equity method investments | 15.00% | ||||||||
Eastern Mediterranean Pipeline B.V. | EMG | |||||||||
Schedule of Equity Method Investments [Line Items] | |||||||||
Ownership interest in equity method investments | 39.00% | ||||||||
Noble Midstream | EPIC Crude Holdings, LP | |||||||||
Schedule of Equity Method Investments [Line Items] | |||||||||
Capital contributions | $ 351 | ||||||||
Ownership interest acquired, step acquisition | 30.00% | ||||||||
Noble Midstream | Delaware Crossing LLC | |||||||||
Schedule of Equity Method Investments [Line Items] | |||||||||
Ownership interest in equity method investments | 50.00% | ||||||||
Capital contributions | 70 | ||||||||
Noble Midstream | EPIC Y-Grade, LP | |||||||||
Schedule of Equity Method Investments [Line Items] | |||||||||
Capital contributions | $ 169 | ||||||||
Ownership interest acquired, step acquisition | 15.00% | ||||||||
Salt Creek Midstream LLC | Delaware Crossing LLC | |||||||||
Schedule of Equity Method Investments [Line Items] | |||||||||
Ownership interest in equity method investments | 50.00% | ||||||||
CONE Gathering LLC | |||||||||
Schedule of Equity Method Investments [Line Items] | |||||||||
Ownership percentage | 50.00% | ||||||||
Proceeds from divestitures | $ 309 | ||||||||
Gain on sale | $ 196 | ||||||||
Common units owned (shares) | 21.7 | ||||||||
Net proceeds | $ 387 | ||||||||
Realized gain on sale | $ 307 | ||||||||
Noble Midstream Partners LP | |||||||||
Schedule of Equity Method Investments [Line Items] | |||||||||
Common units owned (shares) | 56.5 | ||||||||
Advantage Pipeline | Noble Midstream Partners LP | |||||||||
Schedule of Equity Method Investments [Line Items] | |||||||||
Ownership percentage | 50.00% |
Equity Method Investments - S_2
Equity Method Investments - Summarized Financial Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Balance Sheet Information | |||
Current Assets | $ 681 | $ 387 | |
Noncurrent Assets | 5,306 | 575 | |
Current Liabilities | 607 | 198 | |
Noncurrent Liabilities | 2,243 | 81 | |
Statements of Operations Information | |||
Operating Revenues | 1,018 | 855 | $ 790 |
Operating Expenses | 853 | 284 | 303 |
Operating Income | 165 | 571 | 487 |
Other (Loss) Income, net | (33) | 3 | 15 |
Income Before Income Taxes | 132 | 574 | 502 |
Income Tax Provision | 72 | 152 | 136 |
Net Income | $ 60 | $ 422 | $ 366 |
Capitalized Exploratory Well _3
Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs - Changes in Capitalized Exploratory Well Costs (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward] | ||||
Capitalized Exploratory Well Costs, Beginning of Period | $ 354 | $ 520 | $ 768 | |
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves | 26 | 7 | 20 | |
Divestitures | 0 | (168) | 0 | |
Reclassified to Proved Oil and Gas Properties, Based on Determination of Proved Reserves, or to Assets Held for Sale | 0 | (1) | (203) | |
Capitalized Exploratory Well Costs Charged to Expense | $ (100) | (100) | (4) | (65) |
Capitalized Exploratory Well Costs, End of Period | $ 280 | $ 280 | $ 354 | $ 520 |
Capitalized Exploratory Well _4
Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs - Aging of Capitalized Exploratory Well Costs (Details) $ in Millions | Dec. 31, 2019USD ($)project | Dec. 31, 2018USD ($)project | Dec. 31, 2017USD ($)project | Dec. 31, 2016USD ($) |
Capitalized Exploratory Well Costs [Abstract] | ||||
Exploratory Well Costs Capitalized for a Period of One Year or Less | $ 22 | $ 6 | $ 10 | |
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 258 | 348 | 510 | |
Balance at End of Period | $ 280 | $ 354 | $ 520 | $ 768 |
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling | project | 5 | 7 | 8 |
Capitalized Exploratory Well _5
Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs - Aging of Exploratory Well Costs for Greater than One Year (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 |
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling | $ 258 | $ 348 | $ 510 |
Dalit (Offshore Israel) | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling | 23 | ||
Cyprus (Offshore Cyprus) | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling | 100 | ||
Felicita (Block O, Offshore Equatorial Guinea) | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling | 49 | ||
YoYo (YoYo Block, Offshore Cameroon) and Yolanda (Block I, Offshore Equatorial Guinea) | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling | 80 | ||
Projects less than $20 million | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling | 6 | ||
Suspended Since 2017 and 2018 | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling | (3) | ||
Suspended Since 2017 and 2018 | Dalit (Offshore Israel) | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling | (9) | ||
Suspended Since 2017 and 2018 | Cyprus (Offshore Cyprus) | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling | 3 | ||
Suspended Since 2017 and 2018 | Felicita (Block O, Offshore Equatorial Guinea) | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling | 2 | ||
Suspended Since 2017 and 2018 | YoYo (YoYo Block, Offshore Cameroon) and Yolanda (Block I, Offshore Equatorial Guinea) | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling | 2 | ||
Suspended Since 2017 and 2018 | Projects less than $20 million | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling | (1) | ||
Suspended Since 2015 and 2016 | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling | 17 | ||
Suspended Since 2015 and 2016 | Dalit (Offshore Israel) | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling | 3 | ||
Suspended Since 2015 and 2016 | Cyprus (Offshore Cyprus) | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling | 15 | ||
Suspended Since 2015 and 2016 | Felicita (Block O, Offshore Equatorial Guinea) | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling | 4 | ||
Suspended Since 2015 and 2016 | YoYo (YoYo Block, Offshore Cameroon) and Yolanda (Block I, Offshore Equatorial Guinea) | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling | 5 | ||
Suspended Since 2015 and 2016 | Projects less than $20 million | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling | (10) | ||
Suspended Since 2014 and Prior | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling | 244 | ||
Suspended Since 2014 and Prior | Dalit (Offshore Israel) | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling | 29 | ||
Suspended Since 2014 and Prior | Cyprus (Offshore Cyprus) | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling | 82 | ||
Suspended Since 2014 and Prior | Felicita (Block O, Offshore Equatorial Guinea) | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling | 43 | ||
Suspended Since 2014 and Prior | YoYo (YoYo Block, Offshore Cameroon) and Yolanda (Block I, Offshore Equatorial Guinea) | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling | 73 | ||
Suspended Since 2014 and Prior | Projects less than $20 million | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling | $ 17 |
Capitalized Exploratory Well _6
Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs - Rollforward of Undeveloped Lease Costs (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Proved Developed and Undeveloped Reserves [Roll Forward] | ||
Undeveloped Leasehold Costs, Beginning of Period | $ 2,373 | $ 2,922 |
Additions to Undeveloped Leasehold Costs | 59 | 47 |
Transfers to Proved Properties | (184) | (453) |
Assets Sold | (96) | (142) |
Impairment | 0 | (1) |
Undeveloped Leasehold Costs, End of Period | $ 2,152 | $ 2,373 |
Capitalized Exploratory Well _7
Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs - Narrative (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 |
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Undeveloped leasehold costs, net | $ 2,152 | $ 2,373 | $ 2,922 |
Domestic | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Undeveloped leasehold costs, net | 79 | ||
International | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Undeveloped leasehold costs, net | 58 | ||
Delaware Basin | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Undeveloped leasehold costs, net | 1,900 | ||
Eagle Ford | |||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | |||
Undeveloped leasehold costs, net | $ 100 |
Asset Retirement Obligations -
Asset Retirement Obligations - Change in AROs (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Asset Retirement Obligations, Beginning of Period | $ 880 | $ 875 |
Liabilities Incurred | 70 | 25 |
Liabilities Settled | (110) | (345) |
Revisions of Estimates | (69) | 293 |
Reclassification to Liabilities Associated with Assets Held for Sale | 0 | (1) |
Accretion Expense | 43 | 33 |
Asset Retirement Obligations, End of Period | $ 814 | $ 880 |
Asset Retirement Obligations _2
Asset Retirement Obligations - Narrative (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Liabilities Incurred | $ 70 | $ 25 |
Liabilities Settled | 110 | 345 |
Revisions of Estimates | (69) | 293 |
Gulf of Mexico | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Liabilities Settled | 216 | |
Greeley Crescent Assets | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Liabilities Settled | 24 | |
US Onshore | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Liabilities Settled | 104 | |
Revisions of Estimates | 287 | |
Wells Offshore Israel | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Revisions of Estimates | 10 | |
Equatorial Guinea | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Revisions of Estimates | 9 | |
North Sea | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Revisions of Estimates | $ (17) | |
Israel | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Liabilities Incurred | 43 | |
US Onshore | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Liabilities Incurred | 20 | |
DJ Basin | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Revisions of Estimates | $ (72) |
Leases - Balance Sheet Informat
Leases - Balance Sheet Information (Details) $ in Millions | Dec. 31, 2019USD ($) |
ROU Assets | |
Operating Leases | $ 227 |
Finance Leases | 172 |
Total ROU Assets | 399 |
Current Liabilities | |
Operating Leases | 88 |
Finance Leases | 42 |
Noncurrent Liabilities | |
Operating Leases | 164 |
Finance Leases | 163 |
Total Lease Liabilities | 457 |
Compressors | |
ROU Assets | |
Operating Leases | 89 |
Office Space | |
ROU Assets | |
Operating Leases | 80 |
Finance Leases | 90 |
Trunklines | |
ROU Assets | |
Finance Leases | $ 28 |
Long-Term Debt - Summary of Deb
Long-Term Debt - Summary of Debt (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Debt Instrument [Line Items] | ||
Finance Lease Obligations | $ 205 | |
Total Debt | 7,584 | $ 6,675 |
Net Unamortized Discounts and Debt Issuance Costs | (65) | (60) |
Total Debt, Net of Unamortized Discounts and Debt Issuance Costs | 7,519 | 6,615 |
Finance Lease Obligations | (42) | |
Finance Lease Obligations | (41) | |
Long-Term Debt Due After One Year | 7,477 | 6,574 |
Noble Energy | ||
Debt Instrument [Line Items] | ||
Finance Lease Obligations | 205 | |
Finance Lease Obligations | 223 | |
Total Debt | 6,089 | 6,115 |
Noble Energy | Revolving Credit Facility | Revolving Credit Facility, due March 9, 2023 | ||
Debt Instrument [Line Items] | ||
Debt | 0 | 0 |
Noble Energy | Commercial Paper | ||
Debt Instrument [Line Items] | ||
Debt | 0 | 0 |
Noble Energy | Senior Notes | Senior Notes, due December 15, 2021 | ||
Debt Instrument [Line Items] | ||
Debt | $ 0 | $ 1,000 |
Interest Rate | 0.00% | 4.15% |
Noble Energy | Senior Notes | Senior Notes, due October 15, 2023 | ||
Debt Instrument [Line Items] | ||
Debt | $ 100 | $ 100 |
Interest Rate | 7.25% | 7.25% |
Noble Energy | Senior Notes | Senior Notes, due November 15, 2024 | ||
Debt Instrument [Line Items] | ||
Debt | $ 650 | $ 650 |
Interest Rate | 3.90% | 3.90% |
Noble Energy | Senior Notes | Senior Notes, due April 1, 2027 | ||
Debt Instrument [Line Items] | ||
Debt | $ 250 | $ 250 |
Interest Rate | 8.00% | 8.00% |
Noble Energy | Senior Notes | Senior Notes, due January 15, 2028 | ||
Debt Instrument [Line Items] | ||
Debt | $ 600 | $ 600 |
Interest Rate | 3.85% | 3.85% |
Noble Energy | Senior Notes | Senior Notes, due October 15, 2029 | ||
Debt Instrument [Line Items] | ||
Debt | $ 500 | $ 0 |
Interest Rate | 3.25% | 0.00% |
Noble Energy | Senior Notes | Senior Notes, due March 1, 2041 | ||
Debt Instrument [Line Items] | ||
Debt | $ 850 | $ 850 |
Interest Rate | 6.00% | 6.00% |
Noble Energy | Senior Notes | Senior Notes, due November 15, 2043 | ||
Debt Instrument [Line Items] | ||
Debt | $ 1,000 | $ 1,000 |
Interest Rate | 5.25% | 5.25% |
Noble Energy | Senior Notes | Senior Notes, due November 15, 2044 | ||
Debt Instrument [Line Items] | ||
Debt | $ 850 | $ 850 |
Interest Rate | 5.05% | 5.05% |
Noble Energy | Senior Notes | Senior Notes, due August 15, 2047 | ||
Debt Instrument [Line Items] | ||
Debt | $ 500 | $ 500 |
Interest Rate | 4.95% | 4.95% |
Noble Energy | Senior Notes | Senior Notes, due October 15, 2049 | ||
Debt Instrument [Line Items] | ||
Debt | $ 500 | $ 0 |
Interest Rate | 4.20% | 0.00% |
Noble Energy | Senior Notes | Senior Debentures | ||
Debt Instrument [Line Items] | ||
Debt | $ 84 | $ 92 |
Interest Rate | 7.25% | 7.13% |
Noble Midstream | ||
Debt Instrument [Line Items] | ||
Total Debt | $ 1,495 | $ 560 |
Noble Midstream | Revolving Credit Facility | Noble Midstream Services Revolving Credit Facility, due March 9, 2023 | ||
Debt Instrument [Line Items] | ||
Debt | $ 595 | $ 60 |
Interest Rate | 3.11% | 3.67% |
Noble Midstream | Revolving Credit Facility | Noble Midstream Services Term Loan Credit Facility, due July 31, 2021 | ||
Debt Instrument [Line Items] | ||
Debt | $ 500 | $ 500 |
Interest Rate | 2.85% | 3.42% |
Noble Midstream | Revolving Credit Facility | Noble Midstream Services Term Loan Credit Facility, due August 23, 2022 | ||
Debt Instrument [Line Items] | ||
Debt | $ 400 | $ 0 |
Interest Rate | 2.74% | 0.00% |
Leases - Lease Expense (Details
Leases - Lease Expense (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2019USD ($) | |
Leases [Abstract] | |
Operating Lease Cost | $ 110 |
Finance Lease Cost | |
Amortization Expense | 38 |
Interest Expense | 13 |
Short-term Lease Cost | 424 |
Sublease Income | (5) |
Total Lease Cost | $ 580 |
Long-Term Debt - Narrative (Det
Long-Term Debt - Narrative (Details) - USD ($) | Oct. 01, 2019 | Dec. 31, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2019 | Jul. 31, 2018 |
Debt Instrument [Line Items] | |||||||
Maximum borrowing capacity | $ 1,200,000,000 | $ 1,200,000,000 | $ 800,000,000 | ||||
Debt extinguishment cost | 44,000,000 | 44,000,000 | $ 8,000,000 | $ 98,000,000 | |||
Revolving credit facility | 555,000,000 | 555,000,000 | |||||
Noble Midstream | Revolving Credit Facility | |||||||
Debt Instrument [Line Items] | |||||||
Maximum borrowing capacity | 500,000,000 | 500,000,000 | |||||
Line of Credit | Noble Midstream | |||||||
Debt Instrument [Line Items] | |||||||
Maximum borrowing capacity | $ 500,000,000 | ||||||
Revolving Credit Facility, due March 9, 2023 | |||||||
Debt Instrument [Line Items] | |||||||
Maximum borrowing capacity | $ 4,000,000,000 | $ 4,000,000,000 | |||||
Noble Midstream Services Term Loan Credit Facility, due August 23, 2022 | Noble Midstream | Revolving Credit Facility | |||||||
Debt Instrument [Line Items] | |||||||
Interest rate | 2.74% | 2.74% | 0.00% | ||||
Debt | $ 400,000,000 | $ 400,000,000 | $ 0 | ||||
Debt instrument, term | 3 years | ||||||
Senior Notes October 2029 | |||||||
Debt Instrument [Line Items] | |||||||
Face amount | $ 500,000,000 | ||||||
Interest rate | 3.25% | ||||||
Senior Notes October 2049 | |||||||
Debt Instrument [Line Items] | |||||||
Face amount | $ 500,000,000 | ||||||
Interest rate | 4.20% | ||||||
Senior Notes December 2021 | |||||||
Debt Instrument [Line Items] | |||||||
Interest rate | 4.15% | ||||||
Extinguishment of debt, amount | $ 1,000,000,000 | ||||||
Minimum | Revolving Credit Facility, due March 9, 2023 | |||||||
Debt Instrument [Line Items] | |||||||
Credit facility fee rate basis points | 0.10% | ||||||
Maximum | Revolving Credit Facility, due March 9, 2023 | |||||||
Debt Instrument [Line Items] | |||||||
Credit facility fee rate basis points | 0.25% | ||||||
Eurodollar | Minimum | Revolving Credit Facility, due March 9, 2023 | |||||||
Debt Instrument [Line Items] | |||||||
Credit facility interest rate | 0.90% | ||||||
Eurodollar | Maximum | Revolving Credit Facility, due March 9, 2023 | |||||||
Debt Instrument [Line Items] | |||||||
Credit facility interest rate | 1.50% |
Leases - Cash Flow Information
Leases - Cash Flow Information (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2019USD ($) | |
Operating Leases | |
Operating Cash Flows | $ 74 |
Investing Cash Flows | 36 |
Finance Leases | |
Operating Cash Flows | 12 |
Financing Cash Flows | 42 |
ROU Assets Obtained in Exchange for Lease Liabilities | |
Operating Leases | 127 |
Finance Leases | $ 26 |
Long-Term Debt - Fair Value of
Long-Term Debt - Fair Value of Debt (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Carrying Amount | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term debt, net | $ 7,379 | $ 6,452 |
Fair Value | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term debt, net | $ 8,033 | $ 6,121 |
Leases - Lease Maturity (Detail
Leases - Lease Maturity (Details) $ in Millions | Dec. 31, 2019USD ($) |
Operating Leases | |
2020 | $ 100 |
2021 | 60 |
2022 | 41 |
2023 | 26 |
2024 | 15 |
2025 and Thereafter | 37 |
Total Lease Liabilities, Undiscounted | 279 |
Less: Imputed Interest | 27 |
Total Lease Liabilities | 252 |
Finance Leases | |
2020 | 52 |
2021 | 38 |
2022 | 27 |
2023 | 23 |
2024 | 21 |
2025 and Thereafter | 86 |
Total Lease Liabilities, Undiscounted | 247 |
Less: Imputed Interest | 42 |
Total Lease Liabilities | 205 |
Total | |
2020 | 152 |
2021 | 98 |
2022 | 68 |
2023 | 49 |
2024 | 36 |
2025 and Thereafter | 123 |
Total Lease Liabilities, Undiscounted | 526 |
Less: Imputed Interest | 69 |
Total Lease Liabilities | 457 |
Operating lease, liability, current | 88 |
Finance lease, liability, current | $ 42 |
Long-Term Debt - Debt Maturitie
Long-Term Debt - Debt Maturities (Details) $ in Millions | Dec. 31, 2019USD ($) |
Debt Instrument [Line Items] | |
2020 | $ 0 |
2021 | 500 |
2022 | 400 |
2023 | 695 |
2024 | 650 |
Thereafter | 5,134 |
Total | 7,379 |
Noble Energy | |
Debt Instrument [Line Items] | |
2020 | 0 |
2021 | 0 |
2022 | 0 |
2023 | 100 |
2024 | 650 |
Thereafter | 5,134 |
Total | 5,884 |
Noble Midstream | |
Debt Instrument [Line Items] | |
2020 | 0 |
2021 | 500 |
2022 | 400 |
2023 | 595 |
2024 | 0 |
Thereafter | 0 |
Total | $ 1,495 |
Leases - Lease Term and Discoun
Leases - Lease Term and Discount Rates (Details) | Dec. 31, 2019 |
Weighted-Average Remaining Lease Term | |
Operating Leases | 4 years 10 months 24 days |
Finance Leases | 7 years 6 months |
Weighted-Average Discount Rate | |
Operating Leases | 4.05% |
Finance Leases | 4.96% |
Impairments (Details)
Impairments (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||
Asset impairments | $ 1,160 | $ 206 | $ 70 | ||
Fair value | $ 600 | 600 | |||
Undeveloped leasehold costs | 2,152 | $ 2,373 | 2,152 | 2,373 | 2,922 |
Goodwill impairment | 1,300 | $ 0 | 1,281 | 0 | |
Gulf of Mexico | |||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||
Asset impairments | $ 168 | ||||
Certain midstream assets | |||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||
Asset impairments | $ 38 | ||||
Impairment charge | $ 37 | ||||
Troubadour | |||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||
Asset impairments | $ 70 |
Exit Cost - Transportation Co_3
Exit Cost - Transportation Commitments - Narrative (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | |
Jan. 31, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | |
Long-term Purchase Commitment [Line Items] | |||
Commitment amount | $ 1,000 | ||
Reduction and offset of financial obligations | 38 | $ 8 | |
Commitment reduction | $ 350 | ||
Marcellus Shale Firm Transportation Obligations | |||
Long-term Purchase Commitment [Line Items] | |||
Marcellus exit cost accrual | $ 92 | $ 88 | $ 0 |
Minimum | |||
Long-term Purchase Commitment [Line Items] | |||
Term | 3 years | ||
Maximum | |||
Long-term Purchase Commitment [Line Items] | |||
Term | 14 years |
Exit Cost - Transportation Co_4
Exit Cost - Transportation Commitments - Rollforward of Accrued Transportation Commitment (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | |
Jan. 31, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | |
Rollforward Of Contractual Obligations [Roll Forward] | |||
Long-term Portion Included in Other Noncurrent Liabilities | $ 129 | $ 67 | |
Marcellus Shale Firm Transportation Obligations | |||
Rollforward Of Contractual Obligations [Roll Forward] | |||
Balance at Beginning of Period | $ 80 | 80 | 90 |
Exit Cost Accrual | 92 | 88 | 0 |
Payments, Net of Accretion | (5) | (10) | |
Balance at End of Period | 163 | 80 | |
Less Current Portion Included in Other Current Liabilities | 34 | 13 | |
Long-term Portion Included in Other Noncurrent Liabilities | $ 129 | $ 67 | |
Long term purchase offset gain | $ 4 |
Exit Cost - Transportation Co_5
Exit Cost - Transportation Commitments - Income Statement Disclosures (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Long-term Purchase Commitment [Line Items] | |||
Cost of Purchased Oil and Gas | $ 431 | $ 296 | $ 0 |
Sales of Purchased Oil and Gas | |||
Long-term Purchase Commitment [Line Items] | |||
Sales of Purchased Oil and Gas | 90 | 113 | 0 |
Cost of Purchased Oil and Gas | 85 | 108 | 0 |
Utilized Firm Transportation Expense | |||
Long-term Purchase Commitment [Line Items] | |||
Cost of Purchased Oil and Gas | 57 | 29 | 0 |
Unutilized Firm Transportation Expense | |||
Long-term Purchase Commitment [Line Items] | |||
Cost of Purchased Oil and Gas | 1 | 3 | 0 |
Cost of Purchased Gas, Total | |||
Long-term Purchase Commitment [Line Items] | |||
Cost of Purchased Oil and Gas | $ 143 | $ 140 | $ 0 |
Commitments and Contingencies -
Commitments and Contingencies - Narrative (Details) - USD ($) $ in Thousands | 1 Months Ended | 12 Months Ended | ||||
Oct. 31, 2019 | Mar. 31, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2015 | |
Other Commitments [Line Items] | ||||||
Total financial commitment | $ 1,000,000 | |||||
Proceeds from issuance of mezzanine equity, net of offering costs | $ 97,000 | $ 0 | $ 0 | |||
Noble Midstream | ||||||
Other Commitments [Line Items] | ||||||
Redeemable convertible preferred stock | $ 200,000 | |||||
Proceeds from issuance of mezzanine equity, net of offering costs | 100,000 | |||||
Redeemable convertible preferred stock, remaining over next year | $ 100,000 | |||||
Minimum | ||||||
Other Commitments [Line Items] | ||||||
Term | 3 years | |||||
Maximum | ||||||
Other Commitments [Line Items] | ||||||
Term | 14 years | |||||
Colorado Water Quality Control Division Matter | ||||||
Other Commitments [Line Items] | ||||||
Environmental remediation expense | $ 57 | |||||
State-Managed Supplemental Environmental Project | ||||||
Other Commitments [Line Items] | ||||||
Environmental remediation expense | $ 126 | |||||
Consent Decree | ||||||
Other Commitments [Line Items] | ||||||
Corrective actions | $ 5,000 | |||||
Mitigation projects | 4,000 | |||||
Supplemental environmental projects | $ 4,000 | |||||
US Onshore And Eastern Mediterranean Agreements | ||||||
Other Commitments [Line Items] | ||||||
Total financial commitment | $ 921,000 | |||||
US Onshore And Eastern Mediterranean Agreements | Minimum | ||||||
Other Commitments [Line Items] | ||||||
Term | 1 year | |||||
US Onshore And Eastern Mediterranean Agreements | Maximum | ||||||
Other Commitments [Line Items] | ||||||
Term | 12 years |
Income Taxes - Income Tax Provi
Income Taxes - Income Tax Provision, Effective Income Tax Reconciliation, and Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |||
Domestic | $ (2,222) | $ (953) | $ (2,831) |
Foreign | 446 | 1,093 | 640 |
(Loss) Income Before Income Taxes | (1,776) | 140 | (2,191) |
Current Taxes | |||
Federal | 1 | 22 | (11) |
State | 3 | 2 | 1 |
Foreign | 81 | 172 | 96 |
Total Current | 85 | 196 | 86 |
Deferred Taxes | |||
Federal | (413) | (123) | (1,258) |
State | (25) | (7) | (8) |
Foreign | 10 | 60 | 39 |
Total Deferred | (428) | (70) | (1,227) |
Total Income Tax (Benefit) Provision Attributable to Noble Energy | $ (343) | $ 126 | $ (1,141) |
Effective Tax Rate | 19.30% | 90.00% | 52.10% |
Federal statutory tax rate reconciliation [Abstract] | |||
Federal Statutory Rate (in hundredths) | 21.00% | 21.00% | 35.00% |
Effect of | |||
Goodwill Impairment | 0.00% | 192.50% | 0.00% |
Change in Valuation Allowance | (0.60%) | (170.20%) | (17.40%) |
US and Foreign Statutory Rate Change | 0.00% | 80.70% | 23.50% |
Accumulated Undistributed Foreign Earnings | 0.00% | 0.00% | 11.00% |
Transition Tax | 0.00% | 0.00% | (4.80%) |
Difference Between US and Foreign Rates | (0.60%) | 17.90% | 1.80% |
Earnings of Equity Method Investments | 0.70% | (20.10%) | 1.90% |
Noncontrolling Interests | 0.90% | (12.10%) | 1.10% |
State Taxes | 1.10% | 0.90% | 0.30% |
Foreign Exploration Loss | 0.00% | (35.60%) | 0.00% |
Global Intangible Low-Taxed Income (GILTI) | (0.80%) | 24.20% | 0.00% |
Return to Provision | 0.00% | (17.10%) | (0.10%) |
Audit Settlement | 0.00% | 5.10% | 0.10% |
Oil Profits Tax - Israel | (0.10%) | 3.30% | (0.10%) |
Other, Net | (2.30%) | (0.50%) | (0.20%) |
Effective Rate | 19.30% | 90.00% | 52.10% |
Deferred Tax Assets | |||
Loss Carryforwards | $ 656 | $ 589 | |
Employee Compensation and Benefits | 92 | 92 | |
Mark to Market of Commodity Derivative Instruments | 11 | ||
Mark to Market of Commodity Derivative Instruments | (27) | ||
Foreign Tax Credits | 133 | 138 | |
Other | 126 | 157 | |
Total Deferred Tax Assets | 1,018 | 949 | |
Valuation Allowance - Foreign Loss Carryforwards and Foreign Tax Credits | (327) | (320) | |
Net Deferred Tax Assets | 691 | 629 | |
Deferred Tax Liabilities | |||
Property, Plant and Equipment, Principally Due to Differences in Depreciation, Amortization, Lease Impairment and Abandonments | (1,338) | (1,669) | |
Total Deferred Tax Liability | (1,338) | (1,669) | |
Net Deferred Tax Liability | (647) | (1,040) | |
Deferred Income Tax Asset - Noncurrent | 15 | 21 | |
Deferred Income Tax Liability - Noncurrent | (662) | $ (1,061) | |
Domestic Tax Authority | |||
Deferred Tax Assets | |||
Loss Carryforwards | 459 | ||
Foreign Tax Authority | |||
Deferred Tax Assets | |||
Loss Carryforwards | $ 197 |
Commitments and Contingencies_2
Commitments and Contingencies - Minimum Commitments Due (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2019USD ($) | |
Other Commitments [Line Items] | |
Commitment amount | $ 1,000 |
Operating Lease Obligations | |
2020 | 100 |
2021 | 60 |
2022 | 41 |
2023 | 26 |
2024 | 15 |
2025 and Thereafter | 37 |
Total Lease Liabilities, Undiscounted | 279 |
Finance Lease Obligations | |
2020 | 52 |
2021 | 38 |
2022 | 27 |
2023 | 23 |
2024 | 21 |
2025 and Thereafter | 86 |
Total Lease Liabilities, Undiscounted | 247 |
Total | |
2020 | 604 |
2021 | 404 |
2022 | 323 |
2023 | 315 |
2024 | 279 |
2025 and Thereafter | 1,204 |
Total | 3,129 |
Purchase and Service Obligations | |
Other Commitments [Line Items] | |
2020 | 135 |
2021 | 28 |
2022 | 14 |
2023 | 30 |
2024 | 2 |
2025 and Thereafter | 72 |
Total | 281 |
Marcellus Shale Firm Transportation Obligations | |
Other Commitments [Line Items] | |
2020 | 143 |
2021 | 102 |
2022 | 85 |
2023 | 83 |
2024 | 92 |
2025 and Thereafter | 675 |
Total | 1,180 |
Gathering, Transportation & Processing Obligations | |
Other Commitments [Line Items] | |
2020 | 174 |
2021 | 176 |
2022 | 156 |
2023 | 153 |
2024 | 149 |
2025 and Thereafter | 334 |
Total | 1,142 |
Noble Midstream Partners LP | |
Other Commitments [Line Items] | |
Commitment amount | $ 221 |
Income Taxes - Narrative (Detai
Income Taxes - Narrative (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||
Dec. 31, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Apr. 30, 2017 | Apr. 24, 2017 | |
Tax Credit Carryforward [Line Items] | |||||||
Deferred tax expense related to GILTI | $ 34 | ||||||
Deferred tax benefit associated with a write-off of foreign exploration losses | 50 | ||||||
Operating loss carryforwards | $ 2,700 | ||||||
Foreign loss carryforward | $ 320 | 327 | 320 | ||||
Toll tax accrued | 21 | 21 | $ 268 | ||||
Transition tax for accumulated foreign earnings | 261 | ||||||
Income tax expense (benefit) | $ (343) | $ 126 | $ (1,141) | ||||
Effective Rate | 19.30% | 90.00% | 52.10% | ||||
Clayton Williams Energy | |||||||
Tax Credit Carryforward [Line Items] | |||||||
Deferred tax liabilities | $ 307 | ||||||
Deferred tax assets | $ 450 | ||||||
One-time Deemed Repatriation | |||||||
Tax Credit Carryforward [Line Items] | |||||||
Change in enacted tax rate, amount | $ 107 | ||||||
Foreign tax credits | $ 240 | $ 252 | |||||
Income tax expense (benefit) | $ (145) | ||||||
Global Intangible Low-Taxed Income | |||||||
Tax Credit Carryforward [Line Items] | |||||||
Change in enacted tax rate, amount | $ 14 | 34 | |||||
Foreign Loss Carryforward | |||||||
Tax Credit Carryforward [Line Items] | |||||||
Foreign loss carryforward | 187 | 192 | 187 | ||||
Foreign Tax Credit | |||||||
Tax Credit Carryforward [Line Items] | |||||||
Foreign loss carryforward | $ 132 | 133 | $ 132 | ||||
Domestic Tax Authority | |||||||
Tax Credit Carryforward [Line Items] | |||||||
Operating loss carryforwards | 2,000 | ||||||
Foreign Tax Authority | |||||||
Tax Credit Carryforward [Line Items] | |||||||
Operating loss carryforwards | $ 691 | ||||||
Tamar and Dalit Fields | Disposal Group, Disposed of by Sale, Not Discontinued Operations | |||||||
Tax Credit Carryforward [Line Items] | |||||||
Ownership interest sold | 7.50% | ||||||
Israel Tax Authority | |||||||
Tax Credit Carryforward [Line Items] | |||||||
Effective Rate | 46.80% |
Derivative Instruments and He_3
Derivative Instruments and Hedging Activities - Derivative Instruments Summary (Details) | Dec. 31, 2019$ / MMBTUbbl / d$ / bblMMBTU / d |
Crude Oil | 2020 Sold Calls NYMEX WTI | |
Derivative [Line Items] | |
Volume Per Day (in units per day) | bbl / d | 8,000 |
Crude Oil | 2020 Swaps NYMEX WTI | |
Derivative [Line Items] | |
Volume Per Day (in units per day) | bbl / d | 35,000 |
Crude Oil | 2020 Three-Way Collars NYMEX WTI | |
Derivative [Line Items] | |
Volume Per Day (in units per day) | bbl / d | 30,000 |
Crude Oil | 2020 Swaps NYMEX WTI | |
Derivative [Line Items] | |
Volume Per Day (in units per day) | bbl / d | 24,000 |
Crude Oil | 2020 Call Swaption | |
Derivative [Line Items] | |
Volume Per Day (in units per day) | bbl / d | 11,000 |
Crude Oil | 2020 Basis Swaps | |
Derivative [Line Items] | |
Volume Per Day (in units per day) | bbl / d | 15,000 |
Natural Gas | Ethane Swaps | |
Derivative [Line Items] | |
Volume Per Day (in units per day) | bbl / d | 2,000 |
Natural Gas | Propane Swaps | |
Derivative [Line Items] | |
Volume Per Day (in units per day) | bbl / d | 5,000 |
Natural Gas | Isobutane Swaps | |
Derivative [Line Items] | |
Volume Per Day (in units per day) | bbl / d | 1,000 |
Natural Gas | Butane Swaps | |
Derivative [Line Items] | |
Volume Per Day (in units per day) | bbl / d | 1,500 |
Natural Gas | 2020 Swaps NYMEX HH | |
Derivative [Line Items] | |
Volume Per Day (in units per day) | MMBTU / d | 90,000 |
Natural Gas | 2020 Three-Way Collars NYMEX HH | |
Derivative [Line Items] | |
Volume Per Day (in units per day) | MMBTU / d | 40,000 |
Natural Gas | 2020 Sold Puts NYMEX HH | |
Derivative [Line Items] | |
Volume Per Day (in units per day) | MMBTU / d | 90,000 |
Natural Gas | 2020 Basis Swaps CIG | |
Derivative [Line Items] | |
Volume Per Day (in units per day) | MMBTU / d | 139,000 |
Natural Gas | 2020 Basis Swaps Waha | |
Derivative [Line Items] | |
Volume Per Day (in units per day) | MMBTU / d | 49,500 |
Natural Gas | 2021 Basis Swaps CIG | |
Derivative [Line Items] | |
Volume Per Day (in units per day) | MMBTU / d | 60,000 |
Weighted Average Differential (in usd per unit) | $ / MMBTU | (0.52) |
Natural Gas | 2021 Basis Swaps Waha | |
Derivative [Line Items] | |
Volume Per Day (in units per day) | MMBTU / d | 14,000 |
Swaps | Crude Oil | 2020 Sold Calls NYMEX WTI | |
Derivative [Line Items] | |
Weighted Average Fixed Price (in usd per unit) | 65.59 |
Swaps | Crude Oil | 2020 Swaps NYMEX WTI | |
Derivative [Line Items] | |
Weighted Average Fixed Price (in usd per unit) | 58.12 |
Swaps | Crude Oil | 2020 Swaps NYMEX WTI | |
Derivative [Line Items] | |
Weighted Average Fixed Price (in usd per unit) | 59.54 |
Swaps | Crude Oil | 2020 Call Swaption | |
Derivative [Line Items] | |
Weighted Average Fixed Price (in usd per unit) | 58.95 |
Swaps | Crude Oil | 2020 Basis Swaps | |
Derivative [Line Items] | |
Weighted Average Differential (in usd per unit) | (5.01) |
Swaps | Natural Gas | Ethane Swaps | |
Derivative [Line Items] | |
Weighted Average Fixed Price (in usd per unit) | 7.77 |
Swaps | Natural Gas | Propane Swaps | |
Derivative [Line Items] | |
Weighted Average Fixed Price (in usd per unit) | 21.04 |
Swaps | Natural Gas | Isobutane Swaps | |
Derivative [Line Items] | |
Weighted Average Fixed Price (in usd per unit) | 25.36 |
Swaps | Natural Gas | Butane Swaps | |
Derivative [Line Items] | |
Weighted Average Fixed Price (in usd per unit) | 24.31 |
Swaps | Natural Gas | 2020 Swaps NYMEX HH | |
Derivative [Line Items] | |
Weighted Average Fixed Price (in usd per unit) | $ / MMBTU | 2.60 |
Swaps | Natural Gas | 2020 Basis Swaps CIG | |
Derivative [Line Items] | |
Weighted Average Differential (in usd per unit) | $ / MMBTU | (0.56) |
Swaps | Natural Gas | 2020 Basis Swaps Waha | |
Derivative [Line Items] | |
Weighted Average Differential (in usd per unit) | $ / MMBTU | (1.05) |
Swaps | Natural Gas | 2021 Basis Swaps Waha | |
Derivative [Line Items] | |
Weighted Average Differential (in usd per unit) | $ / MMBTU | (0.60) |
Collars | Crude Oil | 2020 Three-Way Collars NYMEX WTI | |
Derivative [Line Items] | |
Weighted Average Short Put Price (in usd per unit) | 48.33 |
Weighted Average Floor Price (in usd per unit) | 57.87 |
Weighted Average Ceiling Price (in usd per unit) | 64.27 |
Collars | Natural Gas | 2020 Three-Way Collars NYMEX HH | |
Derivative [Line Items] | |
Weighted Average Short Put Price (in usd per unit) | $ / MMBTU | 2.25 |
Weighted Average Floor Price (in usd per unit) | $ / MMBTU | 2.70 |
Weighted Average Ceiling Price (in usd per unit) | $ / MMBTU | 2.85 |
Collars | Natural Gas | 2020 Sold Puts NYMEX HH | |
Derivative [Line Items] | |
Weighted Average Short Put Price (in usd per unit) | $ / MMBTU | 2.15 |
Derivative Instruments and He_4
Derivative Instruments and Hedging Activities - Fair Value and Effect on Statement of Operations (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Derivatives, Fair Value [Line Items] | |||
Asset Derivative Instruments | $ 15 | $ 180 | |
Liability Derivative Instruments | 37 | 27 | |
Cash (Received) Paid in Settlement of Commodity Derivative Instruments | (32) | 161 | $ (13) |
Total Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments | 175 | (224) | (50) |
Total Loss (Gain) on Commodity Derivative Instruments | 143 | (63) | (63) |
Crude Oil | |||
Derivatives, Fair Value [Line Items] | |||
Cash (Received) Paid in Settlement of Commodity Derivative Instruments | (10) | 162 | (14) |
Total Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments | 184 | (225) | 18 |
Total Loss (Gain) on Commodity Derivative Instruments | 174 | (63) | 4 |
Natural Gas | |||
Derivatives, Fair Value [Line Items] | |||
Cash (Received) Paid in Settlement of Commodity Derivative Instruments | (22) | (1) | 1 |
Total Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments | (6) | 1 | (68) |
Total Loss (Gain) on Commodity Derivative Instruments | (28) | 0 | (67) |
NGLs | |||
Derivatives, Fair Value [Line Items] | |||
Total Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments | (3) | 0 | 0 |
Total Loss (Gain) on Commodity Derivative Instruments | (3) | 0 | $ 0 |
Other Current Assets | |||
Derivatives, Fair Value [Line Items] | |||
Asset Derivative Instruments | 14 | 180 | |
Other Current Liabilities | |||
Derivatives, Fair Value [Line Items] | |||
Liability Derivative Instruments | 36 | 1 | |
Other Noncurrent Assets | |||
Derivatives, Fair Value [Line Items] | |||
Asset Derivative Instruments | 1 | 0 | |
Other Noncurrent Liabilities | |||
Derivatives, Fair Value [Line Items] | |||
Liability Derivative Instruments | $ 1 | $ 26 |
Additional Shareholders' Equi_3
Additional Shareholders' Equity Information - Common Stock and Treasury Stock (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Feb. 15, 2018 | |
Additional Information | |||
Incremental Shares From Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust | 0 | 0 | |
Number of Antidilutive Stock Options, Shares of Restricted Stock and Shares of Common Stock in Rabbi Trust excluded from Dilutive Earnings (Loss) per Share (2) | 13,892,742 | 15,004,591 | |
Share repurchase program authorized amount | $ 750,000,000 | ||
Repurchase price (in usd per share) | $ 29.49 | ||
Common Stock | |||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||
Shares, beginning balance | 521,055,001 | 528,743,381 | |
Exercise of Common Stock Options | 0 | 576,617 | |
Restricted Stock Awarded, Net of Forfeitures | 2,768,731 | 2,488,363 | |
Purchase and Retirement of Common Stock | 0 | (10,008,128) | |
Adjustment to Shares Exchanged in Clayton Williams Energy Acquisition | 0 | (745,232) | |
Shares, ending balance | 523,823,732 | 521,055,001 | |
Treasury Stock | |||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||
Shares, beginning balance | 38,851,988 | 38,786,969 | |
Shares Received in Payment of Withholding Taxes Due on Vesting of Shares of Restricted Stock | 240,865 | 267,258 | |
Rabbi Trust Shares Distributed and/or Sold | (203,063) | (202,239) | |
Shares, ending balance | 38,889,790 | 38,851,988 |
Additional Shareholders' Equi_4
Additional Shareholders' Equity Information - Accumulated Other Comprehensive Loss (AOCL) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Accumulated Other Comprehensive Loss (AOCL) | |||
Beginning Balance | $ 10,484 | $ 10,619 | $ 9,600 |
Realized Amounts Reclassified Into Earnings | 1 | (2) | 5 |
Unrealized Change in Fair Value | (4) | ||
Ending Balance | 9,055 | 10,484 | 10,619 |
Interest Rate Cash Flow Hedge | |||
Accumulated Other Comprehensive Loss (AOCL) | |||
Beginning Balance | (20) | (21) | |
Realized Amounts Reclassified Into Earnings | (3) | 1 | |
Unrealized Change in Fair Value | 0 | ||
Ending Balance | (20) | ||
Interest Rate Cash Flow Hedge | |||
Accumulated Other Comprehensive Loss (AOCL) | |||
Beginning Balance | (23) | ||
Realized Amounts Reclassified Into Earnings | 1 | ||
Ending Balance | (22) | (23) | |
Other Postretirement Benefit Plans | |||
Accumulated Other Comprehensive Loss (AOCL) | |||
Beginning Balance | (9) | (10) | (10) |
Realized Amounts Reclassified Into Earnings | 0 | 1 | 4 |
Unrealized Change in Fair Value | (4) | ||
Ending Balance | (9) | (9) | (10) |
Total | |||
Accumulated Other Comprehensive Loss (AOCL) | |||
Beginning Balance | (32) | (30) | (31) |
Ending Balance | $ (31) | $ (32) | $ (30) |
Additional Shareholders' Equi_5
Additional Shareholders' Equity Information - Narrative (Details) - USD ($) $ in Millions | 3 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2017 | Dec. 31, 2016 | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Reclassification to retained earnings | $ 6 | |||
Deferred losses | (10,484) | $ (9,055) | $ (10,619) | $ (9,600) |
Interest Rate Cash Flow Hedge | ||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Deferred losses | $ 23 | 22 | ||
Interest Rate Cash Flow Hedge | Interest Rate Contract | ||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Deferred losses | $ 22 |
Stock-Based and Other Compens_3
Stock-Based and Other Compensation Plans - Stock-Based Compensation Expense (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | |||
Total Stock-Based Compensation Expense | $ 68 | $ 62 | $ 104 |
Tax Benefit Recognized | (14) | (13) | (36) |
Amount capitalized to property, plant and equipment | 8 | ||
General and Administrative Expense | |||
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | |||
Total Stock-Based Compensation Expense | 59 | 54 | 56 |
Exploration Expense and Other | |||
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | |||
Total Stock-Based Compensation Expense | $ 9 | $ 8 | $ 48 |
Stock-Based and Other Compens_4
Stock-Based and Other Compensation Plans - Narrative (Details) $ / shares in Units, $ in Millions | Feb. 19, 2019shares | Feb. 01, 2016shares | Dec. 31, 2019USD ($)simulation$ / sharesshares | Dec. 31, 2018USD ($)simulation$ / sharesshares | Dec. 31, 2017USD ($)simulation$ / sharesshares |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Employer matching contribution, percent of employees' gross pay | 6.00% | ||||
401K plan employer cash contributions | $ 32 | $ 31 | $ 31 | ||
Deferred compensation plan assets | 27 | 38 | |||
Deferred compensation liabilities | $ 29 | $ 43 | |||
Deferred compensation arrangement most shares held by individual | shares | 64,729 | 267,792 | |||
Deferred compensation arrangement plan, distribution amount | shares | 200,000 | 200,000 | 200,000 | ||
Deferred compensation arrangements trust plan, distribution amount | $ 23 | $ 18 | $ 21 | ||
Deferred compensation expense | 9 | 2 | 9 | ||
Deferred compensation liabilities | $ 99 | 104 | |||
Stock Option | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Total intrinsic value of options exercised | $ 5 | $ 4 | |||
Minimum term to maturity on US Treasuries used to determine the risk free rate assumption in valuing stock options | 5 years | ||||
Maximum term to maturity on US Treasuries used to determine the risk free rate assumption in valuing stock options | 7 years | ||||
The period ended, prior to the date of grant, over which an average of daily stock prices is computed in determining the dividend yield | 3 years | ||||
Duration of dividends | 1 year | ||||
Unrecognized compensation cost related to nonvested awards | $ 5 | ||||
The weighted-average period over which unrecognized compensation cost is to be recognized (in years) | 1 year 2 months 12 days | ||||
Expected volatility | 33.80% | 33.40% | 33.20% | ||
Risk-free rate | 2.70% | 2.60% | 2.20% | ||
Restricted Stock | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Total fair value of vested restricted stock | $ 20 | $ 29 | $ 34 | ||
Weighted average award date fair value, shares awarded (in dollars per share) | $ / shares | $ 19.54 | $ 27.96 | $ 35.45 | ||
Unrecognized compensation cost related to nonvested awards | $ 74 | ||||
The weighted-average period over which unrecognized compensation cost is to be recognized (in years) | 1 year 4 months 24 days | ||||
Number of simulations | simulation | 10,000,000 | 10,000,000 | 500,000 | ||
Expected volatility | 37.50% | 35.00% | 35.00% | ||
Risk-free rate | 2.50% | 2.30% | 1.50% | ||
Phantom Units | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Total fair value of vested restricted stock | $ 10 | ||||
Unrecognized compensation cost related to nonvested awards | $ 11 | ||||
The weighted-average period over which unrecognized compensation cost is to be recognized (in years) | 2 years 1 month 6 days | ||||
Accrued liability related to phantom units | $ 5 | ||||
2017 Long-Term Incentive Plan | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Maximum number of shares of common stock authorized for issuance After April 26, 2011 (in shares) | shares | 44,000,000 | ||||
Number of shares of common stock reserved for issuance (in shares) | shares | 39,693,735 | ||||
Shares of common stock available for future grants and awards (in shares) | shares | 28,407,839 | ||||
Expiration period (in years) | 10 years | ||||
2017 Long-Term Incentive Plan | Stock Option | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Vesting period | 3 years | ||||
2017 Long-Term Incentive Plan | Restricted Stock | Minimum | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Vesting period | 2 years | ||||
2017 Long-Term Incentive Plan | Restricted Stock | Maximum | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Vesting period | 3 years | ||||
2017 Long-Term Incentive Plan | Performance Shares | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Vesting period | 3 years | ||||
2017 Long-Term Incentive Plan | Phantom Units | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Vesting period | 3 years | ||||
Number of phantom units issued (in shares) | shares | 803,606 | ||||
2015 Stock Plan for Non-Employee Directors | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Maximum number of shares of common stock authorized for issuance After April 26, 2011 (in shares) | shares | 708,996 | ||||
Number of shares of common stock reserved for issuance (in shares) | shares | 485,062 | ||||
Shares of common stock available for future grants and awards (in shares) | shares | 306,243 | ||||
Stock Option And Restricted Stock Plan 1992 | Phantom Units | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Number of phantom units issued (in shares) | shares | 1,000,000 | ||||
Vested (in dollars per share) | $ / shares | $ 31.65 | ||||
Number of simulations | simulation | 500,000 | ||||
Expected volatility | 38.00% | ||||
Risk-free rate | 0.90% | ||||
Vesting percentage | 0.00% | ||||
Subject to Time Vesting | Restricted Stock | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Weighted average award date fair value, shares awarded (in dollars per share) | $ / shares | $ 22.33 | ||||
Weighted average grant date fair value (in dollars per share) | $ / shares | 27.02 | $ 32.72 | |||
Vested (in dollars per share) | $ / shares | 34.11 | ||||
Subject to Time Vesting | Phantom Units | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Weighted average award date fair value, shares awarded (in dollars per share) | $ / shares | 22.39 | ||||
Weighted average grant date fair value (in dollars per share) | $ / shares | 22.39 | $ 31.65 | |||
Vested (in dollars per share) | $ / shares | $ 31.65 |
Stock-Based and Other Compens_5
Stock-Based and Other Compensation Plans - Assumptions and Award Activity (Details) - Stock Option - $ / shares | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Expected Term (in Years) | 6 years 10 months 24 days | 6 years 8 months 12 days | 6 years 4 months 24 days |
Expected Volatility | 33.80% | 33.40% | 33.20% |
Risk-Free Rate | 2.70% | 2.60% | 2.20% |
Expected Dividend Yield | 1.40% | 1.20% | 0.90% |
Weighted Average Grant-Date Fair Value | $ 7.57 | $ 10.47 | $ 13.26 |
Stock-Based and Other Compens_6
Stock-Based and Other Compensation Plans - Stock Option Activity (Details) $ / shares in Units, $ in Millions | 12 Months Ended |
Dec. 31, 2019USD ($)$ / sharesshares | |
Options | |
Outstanding, beginning balance (in shares) | shares | 13,852,020 |
Granted (in shares) | shares | 461,311 |
Forfeited (in shares) | shares | (51,100) |
Expired (in shares) | shares | (1,686,478) |
Outstanding, ending balance (in shares) | shares | 12,575,753 |
Exercisable (in shares) | shares | 11,373,846 |
Weighted Average Exercise Price | |
Outstanding, beginning balance (in dollars per share) | $ / shares | $ 44.04 |
Granted (in dollars per share) | $ / shares | 22.15 |
Forfeited (in dollars per share) | $ / shares | 34.72 |
Expired (in dollars per share) | $ / shares | 35.26 |
Outstanding, ending balance (in dollars per share) | $ / shares | 44.62 |
Exercisable (in dollars per share) | $ / shares | $ 46.11 |
Weighted Average Remaining Contractual Term and Aggregate Intrinsic Value | |
Weighted Average Remaining Contractual Term, Outstanding | 4 years 2 months 12 days |
Weighted Average Remaining Contractual Term, Exercisable | 3 years 8 months 12 days |
Aggregate Intrinsic Value, Outstanding | $ | $ 1 |
Aggregate Intrinsic Value, Exercisable | $ | $ 0 |
Stock-Based and Other Compens_7
Stock-Based and Other Compensation Plans - Assumptions Used For Restricted Stock (Details) - Restricted Stock - simulation | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Number of Simulations | 10,000,000 | 10,000,000 | 500,000 |
Expected Volatility | 37.50% | 35.00% | 35.00% |
Risk-Free Rate | 2.50% | 2.30% | 1.50% |
Stock-Based and Other Compens_8
Stock-Based and Other Compensation Plans - Restricted Stock and Phantom Unit Activity (Details) - $ / shares | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Restricted Stock | |||
Weighted Average Award Date Fair Value | |||
Awarded (in dollars per share) | $ 19.54 | $ 27.96 | $ 35.45 |
Restricted Stock | Subject to Time Vesting | |||
Number of Shares | |||
Outstanding, beginning balance (in shares) | 3,172,891 | ||
Awarded (in shares) | 2,464,682 | ||
Vested (in shares) | (906,485) | ||
Forfeited (in shares) | (486,733) | ||
Outstanding, ending balance (in shares) | 4,244,355 | 3,172,891 | |
Weighted Average Award Date Fair Value | |||
Outstanding, beginning of period (in dollars per share) | $ 32.72 | ||
Awarded (in dollars per share) | 22.33 | ||
Vested (in dollars per share) | 34.11 | ||
Forfeited (in dollars per share) | 27.97 | ||
Outstanding, end of period (in dollars per share) | $ 27.02 | $ 32.72 | |
Restricted Stock | Subject to Market Conditions | |||
Number of Shares | |||
Outstanding, beginning balance (in shares) | 1,385,634 | ||
Awarded (in shares) | 1,138,730 | ||
Vested (in shares) | 0 | ||
Forfeited (in shares) | (347,948) | ||
Outstanding, ending balance (in shares) | 2,176,416 | 1,385,634 | |
Weighted Average Award Date Fair Value | |||
Outstanding, beginning of period (in dollars per share) | $ 21.74 | ||
Awarded (in dollars per share) | 13.50 | ||
Vested (in dollars per share) | 0 | ||
Forfeited (in dollars per share) | 21.20 | ||
Outstanding, end of period (in dollars per share) | $ 17.52 | $ 21.74 | |
Phantom Units | Subject to Time Vesting | |||
Number of Shares | |||
Outstanding, beginning balance (in shares) | 467,365 | ||
Awarded (in shares) | 803,606 | ||
Vested (in shares) | (462,823) | ||
Forfeited (in shares) | (92,762) | ||
Outstanding, ending balance (in shares) | 715,386 | 467,365 | |
Weighted Average Award Date Fair Value | |||
Outstanding, beginning of period (in dollars per share) | $ 31.65 | ||
Awarded (in dollars per share) | 22.39 | ||
Vested (in dollars per share) | 31.65 | ||
Forfeited (in dollars per share) | 22.55 | ||
Outstanding, end of period (in dollars per share) | $ 22.39 | $ 31.65 | |
Phantom Units | Subject to Market Conditions | |||
Number of Shares | |||
Outstanding, beginning balance (in shares) | 150,296 | ||
Forfeited (in shares) | (150,296) | ||
Outstanding, ending balance (in shares) | 0 | 150,296 | |
Weighted Average Award Date Fair Value | |||
Outstanding, beginning of period (in dollars per share) | $ 6.82 | ||
Forfeited (in dollars per share) | 6.82 | ||
Outstanding, end of period (in dollars per share) | $ 0 | $ 6.82 |