Document And Entity Information
Document And Entity Information | 6 Months Ended |
Jun. 30, 2018shares | |
Document And Entity Information [Abstract] | |
Entity Registrant Name | NOBLE ENERGY INC |
Entity Central Index Key | 72,207 |
Current Fiscal Year End Date | --12-31 |
Entity Filer Category | Large Accelerated Filer |
Entity Common Stock, Shares Outstanding | 483,118,790 |
Document Fiscal Year Focus | 2,018 |
Document Fiscal Period Focus | Q2 |
Document Type | 10-Q |
Amendment Flag | false |
Document Period End Date | Jun. 30, 2018 |
Consolidated Statements of Oper
Consolidated Statements of Operations and Comprehensive Income - USD ($) shares in Millions, $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Revenues | ||||
Oil, NGL and Gas Sales | $ 1,100 | $ 1,017 | $ 2,273 | $ 2,011 |
Income from Equity Method Investees and Other | 130 | 42 | 243 | 84 |
Total | 1,230 | 1,059 | 2,516 | 2,095 |
Costs and Expenses | ||||
Production Expense | 292 | 283 | 613 | 586 |
Exploration Expense | 29 | 30 | 64 | 72 |
Depreciation, Depletion and Amortization | 465 | 503 | 933 | 1,031 |
Loss on Marcellus Shale Upstream Divestiture | 0 | 2,322 | 0 | 2,322 |
Gain on Divestitures, Net | (78) | 0 | (666) | 0 |
Asset Impairments | 0 | 0 | 168 | 0 |
General and Administrative | 105 | 103 | 209 | 202 |
Other Operating Expense, Net | 74 | 118 | 144 | 147 |
Total | 887 | 3,359 | 1,465 | 4,360 |
Operating Income (Loss) | 343 | (2,300) | 1,051 | (2,265) |
Other (Income) Expense | ||||
Loss (Gain) on Commodity Derivative Instruments | 249 | (57) | 328 | (167) |
Interest, Net of Amount Capitalized | 73 | 96 | 146 | 183 |
Other Non-Operating Expense (Income), Net | 11 | (5) | 24 | (6) |
Total | 333 | 34 | 498 | 10 |
Income (Loss) Before Income Taxes | 10 | (2,334) | 553 | (2,275) |
Income Tax Expense (Benefit) | 16 | (836) | (15) | (824) |
Net (Loss) Income and Comprehensive (Loss) Income Including Noncontrolling Interests | (6) | (1,498) | 568 | (1,451) |
Less: Net Income and Comprehensive Income Attributable to Noncontrolling Interests | 17 | 14 | 37 | 25 |
Net (Loss) Income and Comprehensive Income (Loss) Attributable to Noble Energy | $ (23) | $ (1,512) | $ 531 | $ (1,476) |
Net (Loss) Income Attributable to Noble Energy per Common Share | ||||
Basic ($ per share) | $ (0.05) | $ (3.20) | $ 1.09 | $ (3.27) |
Diluted ($ per share) | $ (0.05) | $ (3.20) | $ 1.09 | $ (3.27) |
Weighted Average Number of Common Shares Outstanding | ||||
Basic (in shares) | 484 | 472 | 485 | 452 |
Diluted (in shares) | 484 | 472 | 487 | 452 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Jun. 30, 2018 | Dec. 31, 2017 |
Current Assets | ||
Cash and Cash Equivalents | $ 621 | $ 675 |
Accounts Receivable, Net | 743 | 748 |
Other Current Assets | 187 | 780 |
Total Current Assets | 1,551 | 2,203 |
Property, Plant and Equipment | ||
Oil and Gas Properties (Successful Efforts Method of Accounting) | 28,334 | 29,678 |
Property, Plant and Equipment, Other | 896 | 879 |
Total Property, Plant and Equipment, Gross | 29,230 | 30,557 |
Accumulated Depreciation, Depletion and Amortization | (11,313) | (13,055) |
Total Property, Plant and Equipment, Net | 17,917 | 17,502 |
Other Noncurrent Assets | 984 | 461 |
Goodwill | 1,402 | 1,310 |
Total Assets | 21,854 | 21,476 |
Current Liabilities | ||
Accounts Payable – Trade | 1,308 | 1,161 |
Other Current Liabilities | 745 | 578 |
Total Current Liabilities | 2,053 | 1,739 |
Long-Term Debt | 6,555 | 6,746 |
Deferred Income Taxes | 970 | 1,127 |
Other Noncurrent Liabilities | 995 | 1,245 |
Total Liabilities | 10,573 | 10,857 |
Commitments and Contingencies | ||
Shareholders’ Equity | ||
Preferred Stock - Par Value $1.00 per share; 4 Million Shares Authorized; None Issued | 0 | 0 |
Common Stock - Par Value $0.01 per share; 1 Billion Shares Authorized; 526 Million and 529 Million Shares Issued, respectively | 5 | 5 |
Additional Paid in Capital | 8,329 | 8,438 |
Accumulated Other Comprehensive Loss | (28) | (30) |
Treasury Stock, at Cost; 39 Million Shares | (731) | (725) |
Retained Earnings | 2,677 | 2,248 |
Noble Energy Share of Equity | 10,252 | 9,936 |
Noncontrolling Interests | 1,029 | 683 |
Total Equity | 11,281 | 10,619 |
Total Liabilities and Equity | $ 21,854 | $ 21,476 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Jun. 30, 2018 | Dec. 31, 2017 |
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) | 526,000,000 | 529,000,000 |
Treasury stock, shares (in shares) | 39,000,000 | 39,000,000 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Millions | 6 Months Ended | |
Jun. 30, 2018 | Jun. 30, 2017 | |
Cash Flows From Operating Activities | ||
Net Income (Loss) Including Noncontrolling Interests | $ 568 | $ (1,451) |
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities | ||
Depreciation, Depletion and Amortization | 933 | 1,031 |
Loss on Marcellus Shale Upstream Divestiture | 0 | 2,322 |
Gain on Divestitures, Net | (666) | 0 |
Asset Impairments | 168 | 0 |
Deferred Income Tax Benefit | (164) | (873) |
Loss (Gain) on Commodity Derivative Instruments | 328 | (167) |
Net Cash (Paid) Received in Settlement of Commodity Derivative Instruments | (93) | 14 |
Stock Based Compensation | 35 | 67 |
Other Adjustments for Noncash Items Included in Income (Loss) | 22 | 33 |
Changes in Operating Assets and Liabilities | ||
Decrease (Increase) in Accounts Receivable | 76 | (123) |
(Decrease) Increase in Accounts Payable | (24) | 120 |
Decrease in Current Income Taxes Payable | 3 | (42) |
Other Current Assets and Liabilities, Net | (58) | (42) |
Other Operating Assets and Liabilities, Net | (49) | (12) |
Net Cash Provided by Operating Activities | 1,079 | 877 |
Cash Flows From Investing Activities | ||
Additions to Property, Plant and Equipment | (1,782) | (1,215) |
Proceeds from Sale of 7.5% Interest in Tamar Field | 484 | 0 |
Proceeds from Sale of CONE Gathering LLC and CNX Midstream Partners Common Units | 443 | 0 |
Clayton Williams Energy Acquisition | 0 | (616) |
Acquisitions, Net of Cash Acquired | (650) | (351) |
Proceeds from Other Divestitures | 72 | 101 |
Additions to Equity Method Investments | 0 | (68) |
Other | 0 | 0 |
Net Cash Used in Investing Activities | (1,050) | (1,121) |
Cash Flows From Financing Activities | ||
Dividends Paid, Common Stock | (102) | (92) |
Purchase and Retirement of Common Stock | (130) | 0 |
Proceeds from Noble Midstream Services Revolving Credit Facility | 610 | 195 |
Repayment of Noble Midstream Services Revolving Credit Facility | (165) | (5) |
Contributions from Noncontrolling Interest Owners | 331 | 0 |
Issuance of Noble Midstream Partners Common Units, Net of Offering Costs | 0 | 138 |
Proceeds from Revolving Credit Facility | 905 | 1,310 |
Repayment of Revolving Credit Facility | (1,135) | (1,310) |
Repayment of Clayton Williams Energy Long-term Debt | 0 | (595) |
Repayment of Senior Notes | (384) | 0 |
Other | (51) | (67) |
Net Cash Used in Financing Activities | (121) | (426) |
Decrease in Cash, Cash Equivalents, and Restricted Cash | (92) | (670) |
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | 713 | 1,210 |
Cash, Cash Equivalents, and Restricted Cash at End of Period | 621 | 540 |
Gulf of Mexico | ||
Cash Flows From Investing Activities | ||
Proceeds from Divestitures | 383 | 0 |
Marcellus Shale | ||
Cash Flows From Investing Activities | ||
Proceeds from Divestitures | $ 0 | $ 1,028 |
Consolidated Statements of Equi
Consolidated Statements of Equity - USD ($) $ in Millions | Total | Common Stock | Additional Paid in Capital | Accumulated Other Comprehensive Loss | Treasury Stock at Cost | Retained Earnings | Non- controlling Interests |
Balance at Beginning of Period at Dec. 31, 2016 | $ 9,600 | $ 5 | $ 6,450 | $ (31) | $ (692) | $ 3,556 | $ 312 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Net Income | (1,451) | (1,476) | 25 | ||||
Clayton Williams Energy Acquisition | 1,851 | 1,876 | (25) | ||||
Stock-based Compensation | 65 | 65 | |||||
Dividends | (92) | (92) | |||||
Issuance of Noble Midstream Partners Common Units, Net of Offering Costs | 138 | 138 | |||||
Distributions to Noncontrolling Interest Owners | (12) | (12) | |||||
Other | (1) | 8 | 1 | (10) | |||
Balance at End of Period at Jun. 30, 2017 | 10,098 | 5 | 8,399 | (30) | (727) | 1,988 | 463 |
Balance at Beginning of Period at Dec. 31, 2017 | 10,619 | 5 | 8,438 | (30) | (725) | 2,248 | 683 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Net Income | 568 | 531 | 37 | ||||
Stock-based Compensation | 46 | 46 | |||||
Dividends | (102) | (102) | |||||
Purchase and Retirement of Common Stock | (130) | (130) | |||||
Clayton Williams Energy Acquisition | (25) | (25) | |||||
Contributions from Noncontrolling Interest Owners | 331 | 331 | |||||
Distributions to Noncontrolling Interest Owners | (22) | (22) | |||||
Other | (4) | 2 | (6) | ||||
Balance at End of Period at Jun. 30, 2018 | $ 11,281 | $ 5 | $ 8,329 | $ (28) | $ (731) | $ 2,677 | $ 1,029 |
Consolidated Statements of Equ7
Consolidated Statements of Equity (Parenthetical) - $ / shares | 6 Months Ended | |
Jun. 30, 2018 | Jun. 30, 2017 | |
Statement of Stockholders' Equity [Abstract] | ||
Cash Dividends per share (in dollars per share) | $ 0.21 | $ 0.1 |
Organization and Nature of Oper
Organization and Nature of Operations | 6 Months Ended |
Jun. 30, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization and Nature of Operations | Note 1. Organization and Nature of Operations |
Basis of Presentation
Basis of Presentation | 6 Months Ended |
Jun. 30, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Basis of Presentation | Note 2. Basis of Presentation Presentation The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the US (US GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and notes required by US GAAP for complete financial statements. The accompanying consolidated financial statements at June 30, 2018 and December 31, 2017 and for the three and six months ended June 30, 2018 and 2017 contain all normally recurring adjustments considered necessary for a fair presentation of our financial position, results of operations, cash flows and equity for such periods. For the periods presented, activity within other comprehensive income or loss was de minimis; therefore, net income is materially consistent with comprehensive income or loss. Operating results for the three and six months ended June 30, 2018 are not necessarily indicative of the results that may be expected for the year ending December 31, 2018 . These consolidated financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in our Annual Report on Form 10-K for the year ended December 31, 2017 . Consolidation Our consolidated financial statements include our accounts, the accounts of subsidiaries which Noble Energy wholly owns, and the accounts of Noble Midstream Partners, which is considered a variable interest entity (VIE) for which Noble Energy is the primary beneficiary. In addition, we use the equity method of accounting for investments in entities that we do not control, but over which we exert significant influence. All significant intercompany balances and transactions have been eliminated upon consolidation. Estimates The preparation of consolidated financial statements in conformity with US GAAP requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ significantly from those estimates. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. Investment in Shares of Tamar Petroleum We account for our investment in shares of Tamar Petroleum Ltd. at fair value and record changes in fair value in other non-operating expense (income), net in our consolidated statements of operations. See Note 3. Acquisitions and Divestitures and Note 6. Fair Value Measurements and Disclosures . Intangible Assets Intangible assets consist of customer contracts and relationships acquired by Noble Midstream Partners in its acquisition of Saddle Butte Rockies Midstream, LLC and affiliates (collectively, Saddle Butte). We recorded the intangible assets 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 asset, which is currently over periods of seven to 13 years. As of June 30, 2018, the gross book value of the intangible asset was $340 million . Amortization expense of $9 million and $14 million for the three and six months ended June 30, 2018 , respectively, is included in depreciation, depletion and amortization expense in our consolidated statements of operations. Intangible assets with finite useful lives are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. See Note 3. Acquisitions and Divestitures . Stock Repurchase Program On February 15, 2018 , we announced that the Company's Board of Directors authorized a $ 750 million share repurchase program which expires December 31, 2020 . All purchases will be made from time to time in the open market or private transactions, depending on market conditions, and may be discontinued at any time. During second quarter and the first six months of 2018 , we repurchased and retired 1.8 million shares and 4.0 million shares of common stock at an average purchase price of $35.15 per share and $32.41 per share, respectively. ASC 606, Revenue from Contracts with Customers Our revenue is derived from the sale of crude oil, NGL and natural gas production primarily to crude oil refining companies, midstream marketing companies, marketers, industrial companies, electric utility companies, independent power producers and cogeneration facilities, among others. We account for revenue in accordance with ASC 606, Revenue from Contracts with Customers (ASC 606), which we adopted on January 1, 2018 using the modified retrospective method. Under ASC 606, performance obligations are the unit of account and generally represent distinct goods or services that are promised to customers. For sales of crude oil, NGLs and natural gas, each unit sold is generally considered a distinct good and the related performance obligation is generally satisfied at a point in time. We recognize our sales revenues at a point in time and upon delivery to a customer at the contractually stated price and for the quantity of product delivered. In Israel, because our contracts are long-term arrangements, we recognize revenues from the sale of natural gas over the life of the contract based on the quantity of natural gas delivered. ASC 606 provides additional clarification related to principal versus agent considerations. Under this guidance, we record revenue on a gross basis if we control a promised good or service before transferring it to a customer. For example, gathering, processing, transportation and fractionation costs incurred before transfer of control to the customer at the tailgate of a plant are accounted for as fulfillment costs and are presented as a component of gathering, transportation and processing expense in our consolidated statements of operations. On the other hand, we record revenue on a net basis if our role is to arrange for another entity to provide the goods or services. For example, costs incurred after control over the product has transferred to the customer, such as at the wellhead or inlet of a plant, are recorded as a reduction of the transaction price received within revenue. Certain of our contracts for the sale of commodities contain embedded derivatives. We have elected the normal purchases and normal sales scope exception as provided by ASC 815, Derivatives and Hedging , and will account for such contracts in accordance with ASC 606. In the US, we enter into marketing agreements with our non-operating partners to market and sell their share of production to third parties. We have determined that we act as an agent in such arrangements and account for such arrangements on a net basis. ASC 606 adoption did not have an impact on the opening balance of retained earnings. The adoption resulted in de minimis increases of $2 million and $7 million to both revenues and expenses for second quarter and the first six months of 2018 , respectively, but did not affect operating or net income or operating cash flows. The comparative information for the prior period has not been recast and continues to be reported under the accounting standards in effect for the period. Adoption of the new standard did not impact our financial position, and we do not expect that it will do so going forward. Changes to the presentation of commodity sales revenue and production expense resulted from our assessment of certain contractual arrangements under principal versus agent guidance and assessment of control under ASC 606. In particular, we have determined that the processor is our customer with regard to the sale of natural gas at the wellhead or the sale of NGLs at the tailgate. This is a change from previous conclusions reached under principal versus agent guidance per ASC 605, Revenue Recognition , where we previously retained control over our production until the sale to the end customer in the downstream markets. As such, effective January 1, 2018, revenues and expenses are presented on a net basis within revenues in our consolidated statements of operations at the time control over production is transferred to the processor under these arrangements. Following the control model in ASC 606, we determined that we remain the principal in arrangements with the end customers, such as when we take product in-kind at the tailgate and when we are directly responsible for the transportation and marketing of our production in the downstream markets. In such arrangements, we record NGL and natural gas sales and production expense on a gross basis. Our commodity sale contracts in the US are index-based and, thus, include variable consideration. In accordance with ASC 606, we allocate variable consideration (market price) to the distinct commodities transferred in the period, but not to the future obligations to deliver production. Such allocation represents the amount of consideration to which we are entitled for deliveries of our commodities to-date and represents the value of product delivered to the customer. Therefore, our revenue is recognized at the time of delivery and is the product of the volume delivered and the index-based price for the period. The following is a summary of our types of revenue arrangements by commodity and geographic location. EXPLORATION AND PRODUCTION (E&P) REVENUE ARRANGEMENTS Crude Oil Sale Arrangements – US We sell the majority of our US crude oil production under short-term contracts at market-based prices, adjusted for location, quality and transportation charges. Market-based pricing is based on the price index applicable for the location of the sale. We sell our crude oil production either at the lease location or in downstream markets. Crude oil production at the lease location is sold through netback arrangements, under which we sell crude oil net of transportation costs incurred by the purchaser. We record revenue, net, at the lease location when the customer receives delivery of the product. When we move our crude oil production from the lease location to the downstream markets in the US, we incur gathering and transportation costs, which we consider contract fulfillment activities. Such costs are reported as expense within gathering, transportation and processing expense in the consolidated statements of operations. Revenue from the sale of crude oil in downstream markets is recognized upon delivery, as specified in the contract, when control of the product has transferred to the customer. In second quarter 2018, we entered into a long-term contract to sell firm quantities of crude oil under index-based prices adjusted by applicable fees, including transportation, insurance, and marketing. Crude Oil Buy/Sell Transactions – US We enter into buy/sell arrangements that effect a change in location and/or grade with required repurchase of crude oil at a delivery point. The sale and repurchase of crude oil is settled at the same contractually fixed price (before application of transportation and grade deductions) on a net basis. We account for these transactions on a net basis, in accordance with ASC 845, Nonmonetary Transactions . We record the residual transportation fee as transportation expense within gathering, transportation and processing expense in the consolidated statements of operations. Crude Oil Sale Arrangements – West Africa Our share of crude oil and condensate from the Aseng, Alen and Alba fields is sold at market-based prices to Glencore Energy UK Ltd (Glencore Energy). Crude oil is priced at a Dated Brent FOB net realized price achieved by Glencore Energy and is adjusted by applicable fees, including transportation, insurance, and marketing. We recognize revenue on the sale of crude oil to Glencore Energy at the time crude oil cargo is loaded onto the tanker and control transfers to Glencore Energy. We record revenue at the realized price received from Glencore Energy, net of applicable fees. Natural Gas and NGLs Sale Arrangements – US Certain of our commodity contracts in the US are for the sale of natural gas to processors at prevailing market prices. We evaluate the contract terms of these arrangements to determine whether the processor is a service provider or a customer on a contract by contract basis. In arrangements where we determine that we sold our product to the processor, we record revenue when the processor takes physical possession of 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 natural gas processing arrangements, we receive natural gas and NGL products "in-kind" after processing at the tailgate of the plant. In these arrangements, we are responsible for the transportation, fractionation and marketing costs of our production. In such cases, we record the sale of natural gas and NGLs and applicable gathering, processing, transportation and fractionation fees on a gross basis at the time the product is delivered to the end customer. Natural Gas Purchase and Sale Arrangements – US We enter into purchase transactions and separate sale transactions with third parties at prevailing market prices to mitigate unutilized pipeline transportation commitments, primarily related to retained Marcellus Shale firm transportation agreements. Revenues and expenses from the sales and purchases are recorded on a gross basis, as we act as a principal in these transactions by assuming control of the purchased commodity before it is transferred to the customer. Natural Gas Sale Arrangements – West Africa We sell our share of natural gas production from the Alba field under 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 – Israel Our natural gas sales in Israel are primarily based on long-term contracts with fixed volume commitments over the life of the arrangements. Our performance obligations for the sale of natural gas are satisfied over time using production output to measure progress. The nature of these contracts gives rise to several types of variable consideration, including index-based annual price escalations, commodity-based index pricing, tiered pricing and sales price discounts in periods of volume deficiencies. Additionally, the majority of our sales contracts contain take-or-pay provisions where the customers are required to purchase a contractual minimum over varying time periods. Where the variable consideration is related to market-based pricing or index-based escalations of a fixed base price, we have elected the variable consideration allocation exception pursuant to ASC 606. We record revenue related to the volumes delivered at the contract price at the time of delivery. To date, there have been no impacts of variability in consideration due to tiered pricing, take-or-pay provisions and/or volume deficiency discounts. We believe that any variability due to future sales price adjustments associated with potential volume deficiencies will not have a significant impact on our financial position or results of operations. Transaction Price Allocated to Remaining Performance Obligations – Israel Remaining performance obligations represent the transaction price of firm sales arrangements for which volumes have not been delivered. Pursuant to ASC 606, short and long-term interruptible contracts, and long-term dedicated production agreements, are excluded from the disclosure due to uncertainty associated with estimating future production volumes and future market prices. However, certain of our natural gas sales contracts in Israel have fixed annual sales volumes and fixed base pricing with annual index escalations. The following table includes estimated revenues based upon those certain agreements with fixed minimum take-or-pay sales volumes. Our actual future sales volumes under these agreements may exceed future minimum volume commitments. (millions) July - Dec 2018 2019 2020 Total Natural Gas Revenues (1) $ 107 $ 137 $ 169 $ 413 (1) The remaining performance obligations are estimated utilizing the contractual base or floor price provision in effect. Our future revenues from the sale of natural gas under these associated contracts will vary from the amounts presented above due to components of variable consideration above the contractual base or floor provision, such as index-based escalations and market price changes. MIDSTREAM REVENUE ARRANGEMENTS Our Midstream segment revenues are derived from fixed fee contract arrangements for gathering, transportation and storage services. We have determined that our performance obligations for the provision of such services are satisfied over time using volumes delivered as the measure of progress. ASC 606 adoption did not have an impact on the recognition, measurement and presentation of our midstream revenues and expenses. Crude Oil Purchase and Sale Arrangements – US As part of the Saddle Butte acquisition in first quarter 2018, we acquired a pipeline and associated third party contracts which include transactions for the purchase and sale of crude oil with varying counterparties. Revenues and expenses from the sales and purchases are recorded on a gross basis as we act as a principal in these transactions by assuming control of the purchased commodity before it is transferred to the customer. The purchases and sales of crude oil are at the prevailing market prices. Recently Issued Accounting Standards Leases In February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2016-02 (ASU 2016-02): Leases. The standard requires lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by leases with terms of more than 12 months. ASU 2016-02 also requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB issued Accounting Standards Update No. 2018-01 (ASU 2018-01): Land Easement Practical Expedient for Transition to Topic 842 , to provide an optional practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under Topic 840. In July 2018, the FASB issued Accounting Standards Update No. 2018-10 (ASU 2018-10): Codification Improvements to Topic 842, Leases , to clarify application of certain aspects of the standard and to remove inconsistencies within the guidance. Furthermore, in July 2018, the FASB issued Accounting Standards Update No. 2018-11 (ASU 2018-11): Leases (Topic 842): Targeted Improvements , which provides for another transition method, in addition to the existing transition method, by allowing entities to initially apply the new leases standard at the adoption date (such as January 1, 2019) and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption (i.e. comparative periods presented in the financial statements will continue to be in accordance with current GAAP (Topic 840, Leases)). The standard will be effective for annual and interim periods beginning after December 15, 2018, with earlier application permitted. In the normal course of business, we enter into capital and operating lease agreements to support our exploration and development operations and lease assets such as drilling rigs, platforms, storage facilities, field services and well equipment, pipeline capacity, office space and other assets. We will adopt the new standard on the effective date of January 1, 2019. Although we continue to assess the impact of the standard on our consolidated financial statements, we believe adoption and implementation will result in an increase in assets and liabilities as well as additional disclosures. We do not expect a material impact on our consolidated statement of operations. We have developed and are executing a project plan, which includes contract review and assessment, as well as evaluation of our systems, processes and internal controls. In addition, we plan to implement new lease accounting software. Accumulated Other Comprehensive Income In February 2018, the FASB issued Accounting Standards Update No. 2018-02 (ASU 2018-02): Income Statement – Reporting Comprehensive Income, to allow reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act. ASU 2018-02 will be effective for annual and interim periods beginning after December 15, 2018, with earlier application permitted. As of June 30, 2018, we have a disproportionate tax effect of approximately $7 million stranded in accumulated other comprehensive income. We are currently evaluating the provisions of this standard. Intangibles – Goodwill and Other: Simplifying the Test for Goodwill Impairment In January 2017, the FASB issued Accounting Standards Update No. 2017-04 (ASU 2017-04): Intangibles – Goodwill and Other – Simplifying the Test for Goodwill Impairment, to simplify how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. Under the new standard, we will perform our goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount, with an impairment charge being recognized for the amount by which the carrying amount exceeds the reporting unit’s fair value. ASU 2017-04 will be effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019, with early adoption permitted. We are currently evaluating the provisions of ASU 2017-04. Financial Instruments: Credit Losses In June 2016, the FASB issued Accounting Standards Update No. 2016-13 (ASU 2016-13): Financial Instruments – Credit Losses , which replaces the incurred loss impairment methodology with a methodology that reflects expected credit losses. The update is intended to provide financial statement users with more useful information about expected credit losses. The amended standard is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. From evaluation of our current credit portfolio, which includes receivables for commodity sales, joint interest billings due from partners and other receivables, historical credit losses have been de minimis and we believe that our expected future credit losses would not be significant. As such, we do not believe adoption of the standard will have a material impact on our financial statements. Derivatives and Hedging – Targeted Improvements to Accounting for Hedging Activities In August 2017, the FASB issued Accounting Standards Update No. 2017-12 (ASU 2017-12): Derivatives and Hedging – Targeted Improvements to Accounting for Hedging Activities. The update is intended to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition to that main objective, ASU 2017-12 makes certain targeted improvements to simplify the application of the hedge accounting guidance in current US GAAP. The amended standard is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. We are currently evaluating the provisions of ASU 2017-12. Statements of Operations Information Other statements of operations information is as follows: Three Months Ended June 30, Six Months Ended June 30, (millions) 2018 2017 2018 2017 Income From Equity Method Investees and Other Income from Equity Method Investees $ 49 $ 38 $ 96 $ 80 Sales of Purchased Oil and Gas (1) 66 — 119 — Midstream Services Revenues – Third Party 15 4 28 4 Total $ 130 $ 42 $ 243 $ 84 Production Expense Lease Operating Expense $ 132 $ 124 $ 287 $ 263 Production and Ad Valorem Taxes 50 32 104 73 Gathering, Transportation and Processing Expense 100 121 195 240 Other Royalty Expense 10 6 27 10 Total $ 292 $ 283 $ 613 $ 586 Exploration Expense Leasehold Impairment and Amortization $ — $ — $ — $ 18 Seismic, Geological and Geophysical 2 8 13 13 Staff Expense 13 16 27 29 Other 14 6 24 12 Total $ 29 $ 30 $ 64 $ 72 Other Operating Expense, Net Marketing Expense (2) $ 7 $ 14 $ 12 $ 33 Purchased Oil and Gas (1) 71 — 128 — Clayton Williams Energy Acquisition Expenses — 90 — 94 Other, Net (4 ) 14 4 20 Total $ 74 $ 118 $ 144 $ 147 Other Non-Operating Expense (Income), Net Loss on Investment in Shares of Tamar Petroleum Ltd., Net (3) $ 11 $ — $ 26 $ — Other — (5 ) (2 ) (6 ) Total $ 11 $ (5 ) $ 24 $ (6 ) (1) As part of the Saddle Butte acquisition in first quarter 2018, we acquired certain contracts which include the purchase and sale of crude oil with third parties. In addition, we have entered into certain transactions beginning in first quarter 2018 for the purchase of third party natural gas and the subsequent sale of natural gas to other third parties. The natural gas is transported through firm transportation capacity we retained following the Marcellus Shale upstream divestiture in second quarter 2017 and is part of our mitigation efforts to utilize capacity and reduce our financial commitment. The cost to purchase natural gas includes transportation expense incurred of $6 million and $11 million for second quarter and the first six months of 2018 , respectively. See Note 11. Segment Information and Note 12. Commitments and Contingencies . (2) Expense relates to unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments. (3) Amounts for second quarter and the first six months of 2018 include losses of $11 million and $40 million , respectively, related to the change in fair value. The loss for the six months ended June 30, 2018 is partially offset by dividend income of $14 million . There was no dividend income for second quarter 2018. Balance Sheet Information Other balance sheet information is as follows: (millions) June 30, December 31, Accounts Receivable, Net Commodity Sales $ 460 $ 455 Joint Interest Billings 210 207 Other 89 103 Allowance for Doubtful Accounts (16 ) (17 ) Total $ 743 $ 748 Other Current Assets Inventories, Materials and Supplies $ 46 $ 66 Inventories, Crude Oil 27 16 Commodity Derivative Assets 29 2 Assets Held for Sale (1) 40 629 Restricted Cash (2) — 38 Prepaid Expenses and Other Current Assets 45 29 Total $ 187 $ 780 Other Noncurrent Assets Equity Method Investments (3) $ 357 $ 305 Customer-Related Intangible Assets (4) 326 — Investment in Shares of Tamar Petroleum Ltd. (5) 150 — Mutual Fund Investments 57 57 Net Deferred Income Tax Asset 25 25 Other Assets, Noncurrent 69 74 Total $ 984 $ 461 Other Current Liabilities Production and Ad Valorem Taxes $ 111 $ 84 Commodity Derivative Liabilities 250 58 Income Taxes Payable 5 18 Asset Retirement Obligations 92 51 Interest Payable 64 67 Current Portion of Capital Lease Obligations 47 61 Liabilities Associated with Assets Held for Sale (1) — 55 Compensation and Benefits Payable 66 98 Other Liabilities, Current 110 86 Total $ 745 $ 578 Other Noncurrent Liabilities Deferred Compensation Liabilities $ 180 $ 197 Asset Retirement Obligations 543 824 Marcellus Shale Firm Transportation Commitment (6) 71 76 Production and Ad Valorem Taxes 39 69 Commodity Derivative Liabilities 85 15 Other Liabilities, Noncurrent 77 64 Total $ 995 $ 1,245 (1) Assets held for sale at June 30, 2018 include assets in the Greeley Crescent area of the DJ Basin. Assets held for sale at December 31, 2017 include assets in the Greeley Crescent area of the DJ Basin, a 7.5% interest in the Tamar field, offshore Israel, our interest in Southwest Royalties, Inc. acquired in the Clayton Williams Energy Acquisition, and the CONE investments. Liabilities associated with assets held for sale primarily represent asset retirement obligations and other liabilities to be assumed by the purchaser. See Note 3. Acquisitions and Divestitures . (2) Balance at December 31, 2017 represents amount held in escrow pending closing of the Saddle Butte acquisition. See Note 3. Acquisitions and Divestitures . (3) Includes $49 million for our investment in shares of CNX Midstream Partners LP. At December 31, 2017 , this investment was included in assets held for sale. See Note 3. Acquisitions and Divestitures and Note 6. Fair Value Measurements and Disclosures . (4) Amount relates to intangible assets acquired in the Saddle Butte acquisition and is net of $14 million of accumulated amortization. See Note 3. Acquisitions and Divestitures . (5) Amount relates to our investment in shares of Tamar Petroleum Ltd. See Note 3. Acquisitions and Divestitures and Note 6. Fair Value Measurements and Disclosures . (6) Amounts relate to the long-term portion of retained firm transportation agreements. At June 30, 2018 and December 31, 2017 , we recorded $12 million and $14 million , respectively, associated with the current portion of the Marcellus Shale firm transportation commitment. See Note 12. Commitments and Contingencies . Reconciliation of Total Cash We define total cash as cash, cash equivalents and restricted cash. The following table provides a reconciliation of total cash: Six Months Ended June 30, (millions) 2018 2017 Cash and Cash Equivalents at Beginning of Period $ 675 $ 1,180 Restricted Cash at Beginning of Period 38 30 Cash, Cash Equivalents, and Restricted Cash at Beginning of Period $ 713 $ 1,210 Cash and Cash Equivalents at End of Period $ 621 $ 540 Restricted Cash at End of Period — — Cash, Cash Equivalents, and Restricted Cash at End of Period $ 621 $ 540 |
Acquisitions and Divestitures
Acquisitions and Divestitures | 6 Months Ended |
Jun. 30, 2018 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Acquisitions and Divestitures | Note 3. Acquisitions and Divestitures 2018 Asset Transactions Divestiture of Gulf of Mexico Assets On February 15, 2018, we announced that we had signed a definitive agreement to sell our Gulf of Mexico assets, including all of our interests in producing properties and undeveloped acreage, for cash consideration of $ 480 million, along with the assumption, by the purchaser, of all abandonment obligations associated with the properties. As a result, we recorded impairment expense of $ 168 million during first quarter 2018. In second quarter 2018, we closed the transaction with an effective date of January 1, 2018. After consideration of customary closing adjustments, we received net proceeds of $ 383 million and recorded an additional loss of $ 19 million. In addition, a cumulative contingent payment of up to $ 100 million is payable to us in the period after the closing of the transaction, beginning third quarter 2018, through the end of 2022, determined quarterly, at a rate of $ 2 per barrel produced by these assets when the average purchase price for Light Louisiana Sweet (LLS) crude oil exceeds $ 63 per barrel, and if produced crude oil volumes exceed certain minimum thresholds. As of June 30, 2018, no amounts have been accrued related to the contingent payment. Proved reserves associated with these properties totaled approximately 23 MMBoe as of December 31, 2017. Divestiture of 7.5% Interest in Tamar Field On March 14, 2018, we closed the sale of a 7.5% working interest in the Tamar field to Tamar Petroleum Ltd. (Tamar Petroleum), a publicly traded entity on the Tel Aviv Stock Exchange (TASE: TMRP). Total consideration included cash and 38.5 million shares of Tamar Petroleum that had a publicly traded value of $224 million . The transaction had an effective date of January 1, 2018 and after consideration of closing adjustments and before consideration of taxes, we received $484 million of cash. Our shares of Tamar Petroleum are currently subject to certain temporary lock-up provisions and have no voting rights. Upon subsequent sale of the shares to a third party, the voting rights will be restored and granted to the third party. Due to the lock-up provisions associated with the Tamar Petroleum shares, we initially attributed $190 million of fair value to the shares, or 15% lower than the publicly traded value on the TASE. These shares are currently being accounted for at fair value. See Note 6. Fair Value Measurements and Disclosures . Total consideration received was applied to the field's basis and resulted in the recognition of a pre-tax gain of $376 million . In connection with the transaction, we incurred tax expense of $86 million . The sale is in accordance with the terms of the Israel Natural Gas Framework (Framework) that requires us to reduce our ownership interest in the Tamar field from 32.5% to 25% by year-end 2021. We expect to sell the Tamar Petroleum shares before year-end 2021. Proved reserves related to the 7.5% interest totaled approximately 84 MMBoe as of December 31, 2017. Divestiture of Southwest Royalties In January 2018, we closed the sale of our interest in Southwest Royalties, Inc. (Southwest Royalties), a subsidiary of Clayton Williams Energy, Inc. (Clayton Williams Energy), which we acquired in the acquisition of Clayton Williams Energy (Clayton Williams Energy Acquisition) in 2017. We received proceeds of $60 million , resulting in no gain or loss recognition on the sale of these assets. Divestiture of Marcellus Shale CONE Gathering In January 2018, we closed the sale of our 50% interest in CONE Gathering LLC (CONE Gathering) to CNX Resources Corporation. CONE Gathering owns the general partner of CNX Midstream Partners LP (CNX Midstream Partners, NYSE: CNXM). We received proceeds of $308 million in cash and recognized a pre-tax gain of $196 million . After the sale, we continued to hold 21.7 million common units, representing a 34.1% limited partner interest, in CNX Midstream Partners. During second quarter 2018, we sold 7.5 million of the common units, receiving net proceeds of approximately $135 million , net of underwriting fees, and recognized a gain of $109 million . As of June 30, 2018, we continue to hold 14.2 million common units, representing a 22.3% limited partner interest, in CNX Midstream Partners and account for the investment under equity method accounting. Noble Midstream Partners Saddle Butte Acquisition On January 31, 2018, Black Diamond Gathering LLC (Black Diamond), an entity formed by Black Diamond Gathering Holdings LLC, a wholly-owned subsidiary of Noble Midstream Partners, and Greenfield Midstream, LLC (Greenfield), completed the acquisition of Saddle Butte Rockies Midstream, LLC and affiliates (collectively, Saddle Butte) from Saddle Butte Pipeline II, LLC. Saddle Butte owned a large-scale integrated gathering system, located in the DJ Basin, which we subsequently renamed the Black Diamond gathering system. Consideration totaled $681 million , which included $663 million of cash and assumption of $18 million of liabilities. Greenfield funded approximately $343 million of the purchase price, which is reflected as a contribution from noncontrolling interest within our consolidated statement of equity, and Noble Midstream Partners funded the remainder. We consolidate Black Diamond and reflect the third-party ownership within noncontrolling interest within our consolidated statement of equity. We accounted for the transaction as a business combination using the acquisition method. The total purchase price was allocated to assets acquired and liabilities assumed based on the fair value at the acquisition date. We have recognized goodwill for the amount of the purchase price exceeding the fair value of the assets acquired. Allocated fair value included: $206 million to property, plant and equipment; $340 million to customer-related intangible assets (acquired customer contracts); and $111 million to implied goodwill. The purchase price allocation is preliminary as certain data necessary to complete the purchase price allocation is not yet available, such as analysis of the final appraisals of assets acquired and liabilities assumed. We expect to complete the purchase price allocation during the 12-month period following the acquisition date, during which time the value of the assets and liabilities, including any goodwill, may be revised as appropriate. Other Divestitures During the first six months of 2018 , we also closed the sale of certain other smaller US onshore properties and received total cash consideration of $12 million , recording a gain of $ 4 million. 2017 Asset Transactions Delaware Basin Acquisition During the first six months of 2017 , we closed a bolt-on acquisition in the Delaware Basin for $301 million , approximately $246 million of which was allocated to undeveloped leasehold costs. The acquisition included interests in seven producing wells, four of which are operated by us. Clayton Williams Energy Acquisition On April 24, 2017 , we completed the Clayton Williams Energy Acquisition. The acquisition was effected through the issuance of 56 million shares of Noble Energy common stock, with a fair value of $ 1.9 billion, and cash consideration of $ 637 million, for total consideration of $2.5 billion , in exchange for all of the outstanding Clayton Williams Energy shares, including stock options, restricted stock awards and warrants. The transaction was accounted for as a business combination using the acquisition method. The following table represents the final allocation of the total purchase price of Clayton Williams Energy to the assets acquired and liabilities assumed, based on the fair value at the acquisition date, with any excess of the purchase price over the estimated fair value of the identifiable ne t assets acquired recorded as goodwill. (millions) Fair Value of Common Stock Issued $ 1,851 Plus: Cash Consideration Paid to Clayton Williams Energy Stockholders 637 Total Purchase Price $ 2,488 Plus Liabilities Assumed by Noble Energy: Accounts Payable 99 Other Current Liabilities 38 Long-Term Deferred Tax Liability 515 Long-Term Debt 595 Asset Retirement Obligations 63 Total Purchase Price Plus Liabilities Assumed $ 3,798 The fair value of Clayton Williams Energy's identifiable assets was as follows: (millions) Cash and Cash Equivalents $ 21 Other Current Assets 70 Oil and Gas Properties: Proved Reserves 722 Undeveloped Leasehold Costs 1,571 Gathering and Processing Assets 48 Asset Retirement Costs 63 Other Noncurrent Assets 12 Implied Goodwill 1,291 Total Asset Value $ 3,798 In connection with the acquisition, we assumed, and then subsequently retired in second quarter 2017, all of Clayton Williams Energy's long-term debt at a cost of $ 595 million. The fair value measurements of long-term debt were estimated based on the early redemption prices and represent Level 1 inputs. The fair value measurements of crude oil and natural gas properties and asset retirement obligations were based on inputs that are not observable in the market and, therefore, represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert expected future cash flows to a single discounted amount. Significant inputs to the valuation of crude oil and natural gas properties included estimates of: (i) proved, possible and probable reserves; (ii) production rates and related development timing; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average cost of capital rate. These inputs required significant judgments and estimates by management at the time of the valuation and were the most sensitive. Based upon the final purchase price allocation, we recognized $1.3 billion of goodwill, all of which is assigned to the Texas reporting unit. The following pro forma condensed combined financial information was derived from the historical financial statements of Noble Energy and Clayton Williams Energy and gives effect to the acquisition as if it had occurred on January 1, 2017 . The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including: (i) Noble Energy's common stock and equity awards issued to convert Clayton Williams Energy's outstanding shares of common stock and equity awards and conversion of warrants as of the closing date of the acquisition, (ii) depletion of Clayton Williams Energy's fair-valued proved crude oil and natural gas properties, and (iii) the estimated tax impacts of the pro forma adjustments. The pro forma results of operations do not include any cost savings or other synergies that we expect to realize from the Clayton Williams Energy Acquisition or any estimated costs that have been or will be incurred by us to integrate the Clayton Williams Energy assets. The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Clayton Williams Energy Acquisitio n taken place on January 1, 2017 ; furthermore, the financial information is not intended to be a projection of future results. Three Months Ended June 30, Six Months Ended June 30, (millions, except per share amounts) 2018 (1) 2017 2018 (1) 2017 Revenues $ 1,230 $ 1,070 $ 2,516 $ 2,141 Net (Loss) Income and Comprehensive (Loss) Income Attributable to Noble Energy (23 ) (1,354 ) 531 (1,324 ) Net (Loss) Income Attributable to Noble Energy per Common Share Basic $ (0.05 ) $ (2.77 ) $ 1.09 $ (2.71 ) Diluted $ (0.05 ) $ (2.77 ) $ 1.09 $ (2.71 ) (1) No pro forma adjustments were made for the period as Clayton Williams Energy operations are included in our historical results. Marcellus Shale Upstream Divestiture On June 28, 2017, we closed the sale of all of our Marcellus Shale upstream assets, which were primarily natural gas properties. The purchase price totaled $1.2 billion , and we received $1.0 billion of net cash proceeds, after consideration of customary adjustments, at closing. The purchase price includes additional contingent consideration of up to $100 million structured as three separate payments of $33.3 million each. The contingent payments are in effect should the average annual price of the Appalachia Dominion, South Point index exceed $3.30 per MMBtu in the individual annual periods from 2018 through 2020. No amounts have been accrued related to the contingent consideration. Proceeds from the transaction were used to repay borrowings resulting from the Clayton Williams Energy Acquisition. See Note 5. Debt . In second quarter 2017, we recognized a total loss of $2.3 billion , or $1.5 billion after-tax, on this transaction. The aggregate net book value of the properties prior to the sale was approximately $3.4 billion , which included approximately $883 million of undeveloped leasehold cost. As part of the total loss, we recorded a charge of $41 million , discounted, relating to a retained transportation contract. See Note 12. Commitments and Contingencies . During second quarter 2017, production from the Marcellus Shale upstream assets totaled 393 MMcfe/d. With the closing of the sale, we recorded a decrease in net proved reserves of approximately 241 MMBoe, of which approximately 190 MMBoe were proved developed reserves and 51 MMBoe were proved undeveloped reserves. Noble Midstream Partners Asset Contribution On June 26, 2017, Noble Midstream Partners acquired an additional 15% limited partner interest in Blanco River DevCo LP (Blanco River DevCo), increasing its ownership to 40% of the Blanco River DevCo LP, and acquired the remaining 20% limited partner interest in Colorado River DevCo LP (Colorado River DevCo) from Noble Energy for $270 million . Blanco River DevCo holds Noble Midstream Partners’ Delaware Basin in-field gathering dedications for crude oil and produced water gathering services on approximately 111,000 net acres, with substantially all of the acreage also dedicated for natural gas gathering. Colorado River DevCo consists of gathering systems across Noble Energy’s Wells Ranch and East Pony development areas in the DJ Basin. The $270 million consideration consisted of $245 million in cash and 562,430 common units representing limited partner interests in Noble Midstream Partners. Noble Midstream Partners funded the cash consideration with approximately $138 million of net proceeds from a concurrent private placement of common units and $90 million of borrowings under the Noble Midstream Services Revolving Credit Facility (defined below) and the remainder from cash on hand. Noble Midstream Partners Advantage Acquisition On April 3, 2017, Noble Midstream Partners and Plains Pipeline, L.P., a wholly owned subsidiary of Plains All American Pipeline, L.P., acquired Advantage Pipeline, L.L.C. (Advantage Pipeline) for $133 million through a newly formed 50 /50 joint venture (Advantage Joint Venture). Noble Midstream Partners contributed $66.5 million |
Derivative Instruments and Hedg
Derivative Instruments and Hedging Activities | 6 Months Ended |
Jun. 30, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Instruments and Hedging Activities | Note 4. Derivative Instruments and Hedging Activities Objective and Strategies for Using Derivative Instruments We are exposed to fluctuations in crude oil, natural gas and NGL pricing. In order to mitigate the effect of commodity price volatility and enhance the predictability of cash flows relating to the marketing of our global crude oil and domestic natural gas, we enter into crude oil and natural gas price hedging arrangements. While these instruments mitigate the cash flow risk of future decreases in commodity prices, they may also curtail benefits from future increases in commodity prices. See Note 6. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of our derivative instruments. Unsettled Commodity Derivative Instruments As of June 30, 2018 , the following crude oil derivative contracts were outstanding: Swaps Collars Settlement Period Type of Contract Index Bbls Per Day Weighted Average Differential Weighted Average Fixed Price Weighted Average Short Put Price Weighted Average Floor Price Weighted Average Ceiling Price 2018 Swaps NYMEX WTI 66,000 $ — $ 60.30 $ — $ — $ — 2018 Collars NYMEX WTI 18,000 — — — 50.42 58.82 2018 Three-Way Collars NYMEX WTI 10,000 — — 45.50 52.50 69.09 2018 Three-Way Collars Dated Brent 3,000 — — 40.00 50.00 70.41 2018 Swaps ICE Brent 2,000 — 59.00 — — — 2018 Collars ICE Brent 2,000 — — — 50.00 55.25 2018 Three-Way Collars ICE Brent 5,000 — — 43.00 50.00 59.50 2018 Basis Swaps (1) 20,000 (2.30 ) — — — — 2019 Swaps NYMEX WTI 44,000 — 58.37 — — — 2019 Three-Way Collars NYMEX WTI 6,000 — — 50.00 60.00 72.75 2019 Swaps ICE Brent 5,000 — 57.00 — — — 2019 Three-Way Collars ICE Brent 3,000 — — 43.00 50.00 64.07 2019 Basis Swaps (1) 27,000 (3.23 ) — — — — 2020 Swaption (2) NYMEX WTI 5,000 — 61.79 — — — 2020 Basis Swaps (1) 15,000 (5.01 ) — — — — (1) We have entered into crude oil basis swap contracts in order to establish a fixed amount for the differential between pricing in Midland, Texas, and Cushing, Oklahoma. The weighted average differential represents the amount of reduction to Cushing, Oklahoma prices for the notional volumes covered by the basis swap contracts. (2) We have entered into certain derivative contracts (swaptions), which give counterparties the right, but not the obligation, to enter into swap agreements with us on the option expiration dates. As of June 30, 2018 , the following natural gas derivative contracts were outstanding: Swaps Collars Settlement Period Type of Contract Index MMBtu Per Day Weighted Average Fixed Price Weighted Average Short Put Price Weighted Average Floor Price Weighted Average Ceiling Price 2018 Three-Way Collars NYMEX HH 120,000 $ — $ 2.50 $ 2.88 $ 3.65 Fair Value Amounts and Loss (Gain) on Commodity Derivative Instruments The fair values of commodity derivative instruments in our consolidated balance sheets were as follows: Fair Value of Derivative Instruments Asset Derivative Instruments Liability Derivative Instruments June 30, December 31, June 30, December 31, (millions) Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Commodity Derivative Instruments Current Assets $ 29 Current Assets $ 2 Current Liabilities $ 250 Current Liabilities $ 58 Noncurrent Assets — Noncurrent Assets — Noncurrent Liabilities 85 Noncurrent Liabilities 15 Total $ 29 $ 2 $ 335 $ 73 The effect of commodity derivative instruments on our consolidated statements of operations was as follows: Three Months Ended June 30, Six Months Ended June 30, (millions) 2018 2017 2018 2017 Cash Paid (Received) in Settlement of Commodity Derivative Instruments Crude Oil $ 66 $ (11 ) $ 96 $ (16 ) Natural Gas (1 ) — (3 ) 2 Total Cash Paid (Received) in Settlement of Commodity Derivative Instruments 65 (11 ) 93 (14 ) Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments Crude Oil 181 (28 ) 231 (91 ) Natural Gas 3 (18 ) 4 (62 ) Total Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments 184 (46 ) 235 (153 ) Loss (Gain) on Commodity Derivative Instruments Crude Oil 247 (39 ) 327 (107 ) Natural Gas 2 (18 ) 1 (60 ) Total Loss (Gain) on Commodity Derivative Instruments $ 249 $ (57 ) $ 328 $ (167 ) |
Debt
Debt | 6 Months Ended |
Jun. 30, 2018 | |
Debt Disclosure [Abstract] | |
Debt | Note 5. Debt Debt consists of the following: June 30, December 31, (millions, except percentages) Debt Interest Rate Debt Interest Rate Revolving Credit Facility, due March 9, 2023 $ — — % $ 230 2.27 % Noble Midstream Services Revolving Credit Facility, due March 9, 2023 530 3.25 % 85 2.75 % Leviathan Term Loan Facility, due February 23, 2025 — — % — — % Senior Notes, due May 1, 2021 (1) — — % 379 5.63 % Senior Notes, due December 15, 2021 1,000 4.15 % 1,000 4.15 % Senior Notes, due October 15, 2023 100 7.25 % 100 7.25 % Senior Notes, due November 15, 2024 650 3.90 % 650 3.90 % Senior Notes, due April 1, 2027 250 8.00 % 250 8.00 % Senior Notes, due January 15, 2028 600 3.85 % 600 3.85 % Senior Notes, due March 1, 2041 850 6.00 % 850 6.00 % Senior Notes, due November 15, 2043 1,000 5.25 % 1,000 5.25 % Senior Notes, due November 15, 2044 850 5.05 % 850 5.05 % Senior Notes, due August 15, 2047 500 4.95 % 500 4.95 % Other Senior Notes and Debentures (2) 92 7.13 % 92 7.13 % Capital Lease Obligations 241 — % 273 — % Total 6,663 6,859 Unamortized Discount (23 ) (24 ) Unamortized Premium (1) — 12 Unamortized Debt Issuance Costs (38 ) (40 ) Total Debt, Net of Unamortized Discount, Premium and Debt Issuance Costs 6,602 6,807 Less Amounts Due Within One Year Capital Lease Obligations (47 ) (61 ) Long-Term Debt Due After One Year $ 6,555 $ 6,746 (1) In second quarter 2018, we redeemed all of the Senior Notes due May 1, 2021, writing off the associated premium. See Redemption of Senior Notes, below. (2) Includes $8 million of Senior Notes due June 1, 2024 and $84 million of Senior Debentures due August 1, 2097. The weighted average interest rate for these instruments is 7.13% . Revolving Credit Facility Our Credit Agreement, as amended, provides for a $ 4 billion unsecured revolving credit facility (Revolving Credit Facility), which is available for general corporate purposes. The Revolving Credit Facility (i) provides for facility fee rates that range from 10 basis points to 25 basis points per year depending upon our credit rating, (ii) provides for interest rates that are based upon the Eurodollar rate plus a margin that ranges from 90 basis points to 150 basis points depending upon our credit rating 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. In first quarter 2018, we extended the maturity date of the Revolving Credit Facility from August 2020 to March 2023. As of June 30, 2018 , no borrowings were outstanding under the Revolving Credit Facility. Noble Midstream Services Revolving Credit Facility Noble Midstream Services, LLC, 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 first quarter 2018, the facility capacity was increased from $350 million to $800 million and the maturity date was extended from September 2021 to March 2023. Borrowings by Noble Midstream Partners under the Noble Midstream Services Revolving Credit Facility bear interest at a rate equal to an applicable margin plus, at Noble Midstream Partners' option, either (a) in the case of base rate borrowings, a rate equal to the highest of (1) the prime rate, (2) the greater of the federal funds rate or the overnight bank funding rate, plus 0.5% and (3) the LIBOR for an interest period of one month plus 1.00% ; or (b) in the case of LIBOR borrowings, the offered rate per annum for deposits of dollars for the applicable interest period. As of June 30, 2018 , $ 530 million was outstanding under the Noble Midstream Services Revolving Credit Facility. The increase from December 31, 2017 was primarily used to fund the Saddle Butte acquisition, as well as construction activities. See Note 3. Acquisitions and Divestitures . Leviathan Term Loan Agreement On February 24, 2017, Noble Energy Mediterranean Ltd. (NEML), a wholly owned subsidiary of Noble Energy, entered into a facility agreement (Leviathan Term Loan Facility) which provides for a limited recourse secured term loan facility with an aggregate principal borrowing amount of up to $1.0 billion , $625 million of which is initially committed. Any amounts borrowed under the Leviathan Term Loan Facility will be available to fund a portion of our share of costs for the initial phase of development of the Leviathan field offshore Israel. Any amounts borrowed will be subject to repayment on a quarterly basis following production startup for the first phase of development, which is targeted for the end of 2019. Repayment will be in accordance with an amortization schedule set forth in the facility agreement, with a final balloon payment of no more than 35% of the loans outstanding. The Leviathan Term Loan Facility matures on February 23, 2025, and we can prepay borrowings at any time, in whole or in part, without penalty. The Leviathan Term Loan Facility contains customary representations and warranties, affirmative and negative covenants, events of default and also includes a prepayment mechanism that reduces the final balloon amount if cash flows exceed certain defined coverage ratios. Any amounts borrowed will accrue interest at LIBOR, plus a margin of 3.50% per annum prior to production startup, 3.25% during the period following production startup until the last two years of maturity, and 3.75% during the last two years until the maturity date. We are also required to pay a commitment fee equal to 1.00% per annum on the unused and available commitments under the Leviathan Term Loan Facility until the beginning of the repayment period. The Leviathan Term Loan Facility is secured by a first priority security interest in substantially all of NEML's interests in the Leviathan field and its marketing subsidiary, and in assets related to the initial phase of the project. All of NEML’s revenues from the first phase of Leviathan development will be deposited in collateral accounts and we will be required to maintain a debt service reserve account for the benefit of the lenders under the Leviathan Term Loan Facility. Once servicing accounts are replenished and debt service made, all remaining cash will be available to us and our subsidiaries. As of June 30, 2018 , there were no borrowings under the Leviathan Term Loan Facility. See Note 6. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of debt. Redemption of Senior Notes In May 2018, we redeemed $ 379 million of Senior Notes due May 1, 2021 that we assumed in the merger (Rosetta Merger) with Rosetta Resources, Inc. in 2015 for $ 395 million , including $11 million of accrued interest and $5 million of call premium. We fully amortized $10 million of remaining premium and recognized a gain of $5 million , which is reflected in other non-operating (income) expense in our consolidated statements of operations. Annual Debt Maturities Our nearest annual maturity of outstanding debt, excluding capital lease payments and outstanding balances under the revolving credit facilities, is $1.0 billion of senior notes which mature in 2021. The Revolving Credit Facility and Noble Midstream Services Revolving Credit Facility both mature in March 2023. No other balances are due within the next five years. Subsequent Event - Noble Midstream Services Term Credit Agreement On July 31, 2018, Noble Midstream Services, LLC entered into a three year senior unsecured term loan credit facility (Noble Midstream Services Term Credit Agreement) that permits aggregate borrowings of up to $500 million . Proceeds from the Noble Midstream Services Term Credit Agreement will be used to repay a portion of the outstanding borrowings under the Noble Midstream Services Revolving Credit Facility, pay fees and expenses in connection with the Noble Midstream Services Term Credit Agreement transactions and for working capital, capital expenditures, acquisitions and other purposes as necessary of Noble Midstream Partners and its subsidiaries. Borrowings under the Noble Midstream Services Term Credit Agreement will bear interest at a rate equal to, at Noble Midstream Partners' option, either (1) a base rate plus an applicable margin between 0.00% and 0.50% per annum or (2) a Eurodollar rate plus an applicable margin between 1.00% and 1.50% per annum. The Noble Midstream Services Term Credit Agreement contains customary representations and warranties, affirmative and negative covenants, and events of default that are substantially the same as those contained in the Noble Midstream Services Revolving Credit Facility. Upon the occurrence and during the continuation of an event of default under the Noble Midstream |
Fair Value Measurements and Dis
Fair Value Measurements and Disclosures | 6 Months Ended |
Jun. 30, 2018 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements and Disclosures | Note 6. Fair Value Measurements and Disclosures Assets and Liabilities Measured at Fair Value on a Recurring Basis Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheets. The following methods and assumptions were used to estimate the fair values: Cash, Cash Equivalents, Accounts Receivable and Accounts Payable The carrying amounts approximate fair value due to the short-term nature or maturity of the instruments. Mutual Fund Investments Our mutual fund investments consist of various publicly-traded mutual funds that include investments ranging from equities to money market instruments. The fair values are based on quoted market prices for identical assets. Commodity Derivative Instruments Our commodity derivative instruments may include variable to fixed price commodity swaps, two-way collars, three-way collars, swaptions, enhanced swaps and basis swaps. We estimate the fair values of these instruments using published forward commodity price curves as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates. In addition, for collars, we estimate the option values of the put options sold and the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract terms. See Note 4. Derivative Instruments and Hedging Activities . Investment in Tamar Petroleum Ltd Our investment in shares of Tamar Petroleum was acquired on March 14, 2018. The fair value of these shares is determined at the end of each quarter based on the trading price of Tamar Petroleum shares on the Tel Aviv Stock Exchange and is reduced by a 15% discount. The discount rate is based on analysis of historical discounts realized in private placements of public common stock, which we believe represents a reasonable estimate of the impact of the temporary lock-up provisions applicable to the shares we own. See Note 2. Basis of Presentation and Note 3. Acquisitions and Divestitures . Deferred Compensation Liability The value is dependent upon the fair values of mutual fund investments and shares of our common stock held in a rabbi trust. See Mutual Fund Investments above . Stock-Based Compensation Liability A portion of the value of the liability associated with our phantom unit plan is dependent upon the fair value of Noble Energy common stock as of the end of each reporting period. Measurement information for assets and liabilities that are measured at fair value on a recurring basis was as follows: Fair Value Measurements Using (millions) Quoted Prices in Active Markets (Level 1) (1) Significant Other Observable Inputs (Level 2) (2) Significant Unobservable Inputs (Level 3) (3) Adjustment (4) Fair Value Measurement June 30, 2018 Financial Assets: Mutual Fund Investments $ 57 $ — $ — $ — $ 57 Commodity Derivative Instruments — 72 — (43 ) 29 Investment in Tamar Petroleum Ltd. (38,495,575 Shares) (5) — 150 — — 150 Financial Liabilities: Commodity Derivative Instruments — (378 ) — 43 (335 ) Portion of Deferred Compensation Liability Measured at Fair Value (73 ) — — — (73 ) Stock Based Compensation Liability Measured at Fair Value (12 ) — — — (12 ) December 31, 2017 Financial Assets: Mutual Fund Investments $ 57 $ — $ — $ — $ 57 Commodity Derivative Instruments — 7 — (5 ) 2 Financial Liabilities: Commodity Derivative Instruments — (78 ) — 5 (73 ) Portion of Deferred Compensation Liability Measured at Fair Value (71 ) — — — (71 ) Stock Based Compensation Liability Measured at Fair Value (10 ) — — — (10 ) (1) Level 1 measurements are fair value measurements which use quoted market prices (unadjusted) in active markets for identical assets or liabilities. We use Level 1 inputs when available as Level 1 inputs generally provide the most reliable evidence of fair value. (2) Level 2 measurements are fair value measurements which use inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly. (3) Level 3 measurements are fair value measurements which use unobservable inputs. (4) Amount represents the impact of netting provisions within our master agreements that allow us to net cash settle asset and liability positions with the same counterparty. (5) As of June 30, 2018, the closing price on the TASE of publicly traded and unrestricted shares of Tamar Petroleum Ltd. was $4.60 per share. Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Certain assets and liabilities such, as oil and gas properties, goodwill and other intangible assets, are not required to be measured at fair value on a recurring basis. However, these assets are assessed for impairment, and a resulting asset impairment would require the asset be recorded at fair value. Asset Impairments During first quarter 2018, upon classification of the Gulf of Mexico properties as assets held for sale, we recognized an impairment of $168 million . See Note 3. Acquisitions and Divestitures . For second quarter 2018 and the first six months of 2017, we had no adjustments in fair value related to oil and gas properties. Additional Fair Value Disclosures Investment in CNX Midstream Partners Our investment in CNX Midstream Partners, which is included in our Midstream reportable segment, is accounted for using the equity method. The fair value of the investment is based on the published market price of the common units for the date indicated below. June 30, 2018 December 31, 2017 (millions) Carrying Amount Fair Value Carrying Amount Fair Value Investment in CNX Midstream Partners (14,217,198 Common Units and 21,692,198 Common Units, respectively) (1) $ 49 $ 276 $ 70 $ 364 (1) During second quarter 2018, we sold 7.5 million common units, reducing our ownership in CNX Midstream Partners. See Note 3. Acquisitions and Divestitures . Debt The fair value of fixed-rate, public debt is estimated based on the published market prices for the same or similar issues. As such, we consider the fair value of our public, fixed-rate debt to be a Level 1 measurement on the fair value hierarchy. Our Revolving Credit Facility, the Noble Midstream Services Revolving Credit Facility and the Leviathan Term Loan Facility are variable-rate, non-public debt. The fair value is estimated based on significant other observable inputs. As such, we consider the fair value of these facilities to be a Level 2 measurement on the fair value hierarchy. See Note 5. Debt . Fair value information regarding our debt is as follows: June 30, 2018 December 31, 2017 (millions) Carrying Amount Fair Value Carrying Amount Fair Value Long-Term Debt (1) $ 6,422 $ 6,591 $ 6,586 $ 7,142 (1) |
Capitalized Exploratory Well Co
Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs | 6 Months Ended |
Jun. 30, 2018 | |
Extractive Industries [Abstract] | |
Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs | Note 7. 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. On a quarterly basis, we review the status of suspended exploratory well costs and assess the development of these projects. If a well is deemed to be noncommercial, the well costs are charged to exploration expense as dry hole cost. Changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and subsequently expensed in the same period: (millions) Six Months Ended June 30, 2018 Capitalized Exploratory Well Costs, Beginning of Period $ 520 Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves 4 Divestitures (1) (167 ) Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves (1 ) Capitalized Exploratory Well Costs Charged to Expense — Capitalized Exploratory Well Costs, End of Period $ 356 (1) Represents costs primarily related to Gulf of Mexico assets. The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced: (millions) June 30, December 31, Exploratory Well Costs Capitalized for a Period of One Year or Less $ 8 $ 10 Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling 348 510 Balance at End of Period $ 356 $ 520 Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling 7 8 Undeveloped Leasehold Costs We reclassify undeveloped leasehold costs to proved property costs when, as a result of exploration and development activities, probable and possible resources are reclassified to proved reserves, including proved undeveloped reserves. On the other hand, if, based upon a change in exploration plans, timing and extent of development activities, availability of capital and suitable rig and drilling equipment, resource potential, comparative economics, changing regulations and/or other factors, an impairment is indicated, we record impairment expense related to the respective leases or licenses. As of June 30, 2018 , we had remaining undeveloped leasehold costs, to which proved reserves had not been attributed, of $2.6 billion , including $1.6 billion related to Delaware Basin assets acquired in the Clayton Williams Energy Acquisition in 2017, and $859 million and $129 million attributable to Delaware Basin and Eagle Ford Shale assets, respectively, acquired in the Rosetta Merger in 2015. Undeveloped leasehold costs were derived from allocated fair values as a result of business combinations or other purchases of unproved properties and are subject to impairment testing. The remaining balance of undeveloped leasehold costs as of June 30, 2018 included $53 million related to international unproved properties. These costs pertain to acquired leases or licenses that are subject to expiration over the next several years unless production is established on units containing the acreage. These costs are evaluated as part of our periodic impairment review. During the first half of 2018, we transferred $247 million and $20 million of undeveloped leasehold costs associated with Delaware Basin and Eagle Ford Shale assets, respectively, to proved properties. These transfers resulted from additions of proved reserves through development activities. In addition, $43 million of capitalized costs associated with Gulf of Mexico leases and licenses was removed from undeveloped leasehold costs due to divestiture of the associated assets in second quarter 2018. See Note 3. Acquisitions and Divestitures |
Asset Retirement Obligations
Asset Retirement Obligations | 6 Months Ended |
Jun. 30, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | Note 8. Asset Retirement Obligations Asset retirement obligations (ARO) consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. Changes in ARO are as follows: Six Months Ended June 30, (millions) 2018 2017 Asset Retirement Obligations, Beginning Balance $ 875 $ 935 Liabilities Incurred 14 82 Liabilities Settled (261 ) (32 ) Revisions of Estimates (10 ) (15 ) Accretion Expense (1) 17 23 Asset Retirement Obligations, Ending Balance $ 635 $ 993 (1) Accretion expense is included in depreciation, depletion and amortization (DD&A) expense in the consolidated statements of operations. For the Six Months Ended June 30, 2018 Liabilities settled include $ 216 million of liabilities assumed by the purchaser of the Gulf of Mexico properties and $44 million related to abandonment of US onshore properties, primarily in the DJ Basin. Revisions of estimates primarily relate to decreases in cost and timing estimates of $11 million associated with the North Sea abandonment project and $6 million for Eastern Mediterranean, partially offset by an increase of $7 million for US onshore. For the Six Months Ended June 30, 2017 Liabilities incurred include $59 million related to the Clayton Williams Energy Acquisition and $23 million primarily for other US onshore wells and facilities placed into service. Liabilities settled primarily related to US onshore property abandonments, as well as $12 million related to properties sold in the Marcellus Shale upstream divestiture. Revisions of estimates related to decreases in cost and timing estimates of $30 million for US onshore and Gulf of Mexico, partially offset by an increase of $15 million |
Income Per Share Attributable t
Income Per Share Attributable to Noble Energy | 6 Months Ended |
Jun. 30, 2018 | |
Earnings Per Share [Abstract] | |
Income (Loss) Per Share Attributable to Noble Energy | Note 10. Income Per Share Attributable to Noble Energy Noble Energy's basic income (loss) per share of common stock is computed by dividing net income (loss) attributable to Noble Energy by the weighted average number of shares of Noble Energy common stock outstanding during each period. The following table summarizes the calculation of basic and diluted income (loss) per share: Three Months Ended June 30, Six Months Ended June 30, (millions, except per share amounts) 2018 2017 2018 2017 Net (Loss) Income and Comprehensive (Loss) Income Attributable to Noble Energy $ (23 ) $ (1,512 ) $ 531 $ (1,476 ) Weighted Average Number of Shares Outstanding, Basic 484 472 485 452 Incremental Shares from Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust — — 2 — Weighted Average Number of Shares Outstanding, Diluted 484 472 487 452 (Loss) Income Per Share, Basic $ (0.05 ) $ (3.20 ) $ 1.09 $ (3.27 ) (Loss) Income Per Share, Diluted (0.05 ) (3.20 ) 1.09 (3.27 ) Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above 14 16 14 15 |
Income Taxes
Income Taxes | 6 Months Ended |
Jun. 30, 2018 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Note 9. Income Taxes The income tax (benefit) expense consists of the following: Three Months Ended June 30, Six Months Ended June 30, (millions, except percentages) 2018 2017 2018 2017 Current $ 23 $ 37 $ 149 $ 49 Deferred (7 ) (873 ) (164 ) (873 ) Total Income Tax Expense (Benefit) $ 16 $ (836 ) $ (15 ) $ (824 ) Effective Tax Rate 160.0 % 35.8 % (2.7 )% 36.2 % Changes in US Tax Law On December 22, 2017, the US Congress enacted the Tax Cuts and Jobs Act (Tax Reform Legislation), which made significant changes to US federal income tax law, including a reduction in the federal corporate tax rate to 21%, effective January 1, 2018. In accordance with US GAAP, we recognized the effect of the rate change on deferred tax assets and liabilities as of December 31, 2017. On April 2, 2018, the US Department of the Treasury and the Internal Revenue Service released Notice 2018-26, signaling intent to issue regulations related to the transition tax (toll tax) on a one-time “deemed repatriation” of accumulated foreign earnings for the year ended December 31, 2017. Notice 2018-26 clarifies that an Internal Revenue Code Section 965(n) election is available with respect to both current year operating losses and net operating losses from a prior year. As a result, during first quarter 2018, we released the valuation allowance recorded against foreign tax credits that will be utilized against the $268 million toll tax liability we had recorded as of December 31, 2017, resulting in a $252 million tax benefit, and reduced our estimated toll tax liability to $16 million to be paid in installments over eight years. We also recorded a corresponding expense of $107 million for the tax rate change adjustment on the previously utilized net operating losses. The impact on first quarter 2018 total tax expense, related to this additional guidance, was a net $145 million discrete tax benefit. During second quarter 2018, we made no changes to the provisional amounts recognized in 2017. The ultimate impact of the Tax Reform Legislation may differ from our estimates due to changes in interpretations and assumptions made by us, as well as additional regulatory guidance that may be issued. In particular, our estimate of the impact of the toll tax is a provisional amount, based on current legal interpretations. This amount may be adjusted further in future periods, as an adjustment to income tax expense or benefit, in the period in which the final amounts are determined. Effective Tax Rate (ETR) At the end of each interim period, we apply a forecasted annualized effective tax rate (ETR) to current period earnings or loss before tax, which can result in significant interim ETR fluctuations. Our ETR for the six months ended June 30, 2018 varied as compared with the six months ended June 30, 2017 primarily due to a deferred tax benefit of $145 million recorded discretely in the current year, as discussed above, and a significant deferred tax benefit recorded at the higher prior year US tax rate of 35% on the Marcellus Shale upstream divestiture in second quarter 2017. In addition, the increase in the current income tax expense for the six months ended June 30, 2018 is primarily due to foreign taxes on a gain associated with the first quarter 2018 divestiture of a 7.5% interest in the Tamar field, offshore Israel. In our major tax jurisdictions, the earliest years remaining open to examination are as follows: US – 2014 , Israel – 2015 (2013 with respect to Israel Oil Profits Tax) and Equatorial Guinea – 2013 |
Segment Information
Segment Information | 6 Months Ended |
Jun. 30, 2018 | |
Segment Reporting [Abstract] | |
Segment Information | Note 11. Segment Information We have the following reportable segments: United States (US onshore and Gulf of Mexico (until April 2018)); Eastern Mediterranean (Israel and Cyprus); West Africa (Equatorial Guinea, Cameroon and Gabon); Other International (Falkland Islands, Suriname, Canada, and New Ventures); and Midstream. The Midstream segment includes the consolidated accounts of Noble Midstream Partners, US onshore equity method investments and other US onshore midstream assets. The geographical reportable segments are in the business of crude oil and natural gas acquisition and exploration, development, and production (Oil and Gas Exploration and Production). The Midstream reportable segment owns, acquires, operates, and develops domestic midstream infrastructure assets, with current focus areas being the DJ and Delaware Basins. Expenses related to debt, headquarters depreciation and corporate general and administrative expenses are recorded at the corporate level. Oil and Gas Exploration and Production Midstream (millions) Consolidated United Eastern West Other Int'l United States Intersegment Eliminations and Other (1) Corporate Three Months Ended June 30, 2018 Crude Oil Sales $ 749 $ 635 $ 2 $ 112 $ — $ — $ — $ — NGL Sales 137 137 — — — — — — Natural Gas Sales 214 98 111 5 — — — — Total Crude Oil, NGL and Natural Gas Sales 1,100 870 113 117 — — — — Income from Equity Method Investees and Other 64 — — 36 — 28 — — Sales of Purchased Oil and Gas 66 24 — — — 42 — — Intersegment Revenues — — — — — 85 (85 ) — Total Revenues 1,230 894 113 153 — 155 (85 ) — Lease Operating Expense 132 114 5 19 — — (6 ) — Production and Ad Valorem Taxes 50 48 — — — 2 — — Gathering, Transportation and Processing Expense 100 133 — — — 22 (55 ) — Other Royalty Expense 10 10 — — — — — — Total Production Expense 292 305 5 19 — 24 (61 ) — DD&A 465 394 15 26 — 22 (4 ) 12 Loss (Gain) on Divestitures (78 ) 21 10 — — (109 ) — — Purchased Oil and Gas 71 31 — — — 40 — — Loss on Commodity Derivative Instruments 249 196 — 53 — — — — (Loss) Income Before Income Taxes 10 (90 ) 62 48 (13 ) 175 (18 ) (154 ) Three Months Ended June 30, 2017 Crude Oil Sales $ 557 $ 458 $ 1 $ 98 $ — $ — $ — $ — NGL Sales 108 108 — — — — — — Natural Gas Sales 352 214 132 6 — — — — Total Crude Oil, NGL and Natural Gas Sales 1,017 780 133 104 — — — — Income from Equity Method Investees and Other 42 — — 25 — 17 — — Intersegment Revenues — — — — — 69 (69 ) — Total Revenues 1,059 780 133 129 — 86 (69 ) — Lease Operating Expense 124 105 6 18 — — (5 ) — Production and Ad Valorem Taxes 32 32 — — — — — — Gathering, Transportation and Processing Expense 121 142 — — — 17 (38 ) — Other Royalty Expense 6 6 — — — — — — Total Production Expense 283 285 6 18 — 17 (43 ) — DD&A 503 427 19 39 1 5 — 12 Loss on Marcellus Shale Upstream Divestiture 2,322 2,322 — — — — — — Loss on Commodity Derivative Instruments (57 ) (51 ) — (6 ) — — — — (Loss) Income Before Income Taxes (2,334 ) (2,319 ) 106 72 (4 ) 58 (13 ) (234 ) Six Months Ended June 30, 2018 Crude Oil Sales $ 1,522 $ 1,317 $ 4 $ 201 $ — $ — $ — $ — NGL Sales 283 283 — — — — — — Natural Gas Sales 468 218 240 10 — — — — Total Crude Oil, NGL and Natural Gas Sales 2,273 1,818 244 211 — — — — Income from Equity Method Investees and Other 124 — — 71 — 53 — — Sales of Purchased Oil and Gas 119 55 — — — 64 — — Intersegment Revenues — — — — — 166 (166 ) — Total Revenues 2,516 1,873 244 282 — 283 (166 ) — Lease Operating Expense 287 240 12 41 — — (6 ) — Production and Ad Valorem Taxes 104 101 — — — 3 — — Gathering, Transportation and Processing Expense 195 260 — — — 43 (108 ) — Other Royalty Expense 27 27 — — — — — — Total Production Expense 613 628 12 41 — 46 (114 ) — DD&A 933 800 28 52 — 38 (8 ) 23 Gain on Divestitures (666 ) 15 (376 ) — — (305 ) — — Asset Impairments 168 168 — — — — — — Purchased Oil and Gas 128 67 — — — 61 — — Loss on Commodity Derivative Instruments 328 260 — 68 — — — — Income (Loss) Before Income Taxes 553 (127 ) 535 112 (27 ) 428 (40 ) (328 ) Six Months Ended June 30, 2017 Crude Oil Sales $ 1,084 $ 897 $ 2 $ 185 $ — $ — $ — $ — NGL Sales 213 213 — — — — — — Natural Gas Sales 714 440 263 11 — — — — Total Crude Oil, NGL and Natural Gas Sales 2,011 1,550 265 196 — — — — Income from Equity Method Investees and Other 84 — — 52 — 32 — — Intersegment Revenues — — — — — 127 (127 ) — Total Revenues 2,095 1,550 265 248 — 159 (127 ) — Lease Operating Expense 263 211 14 40 — — (2 ) — Production and Ad Valorem Taxes 73 72 — — — 1 — — Gathering, Transportation and Processing Expense 240 280 — — — 32 (72 ) — Other Royalty Expense 10 10 — — — — — — Total Production Expense 586 573 14 40 — 33 (74 ) — DD&A 1,031 886 37 74 2 10 — 22 Loss on Marcellus Shale Upstream Divestiture 2,322 2,322 — — — — — — Gain on Commodity Derivative Instruments (167 ) (154 ) — (13 ) — — — — Income (Loss) Before Income Taxes (2,275 ) (2,251 ) 207 138 (11 ) 107 (35 ) (430 ) June 30, 2018 Goodwill (2) $ 1,402 $ 1,291 $ — $ — $ — $ 111 $ — $ — Total Assets 21,854 15,138 2,996 1,275 62 2,280 (140 ) 243 December 31, 2017 Goodwill (2) 1,310 1,310 — — — — — — Total Assets 21,476 15,767 2,846 1,308 114 1,357 (163 ) 247 (1) The intersegment eliminations related to income (loss) before income taxes are the result of midstream expenditures. These costs are presented as property, plant and equipment within the E&P business on an unconsolidated basis, in accordance with the successful efforts method of accounting, and are eliminated upon consolidation. (2) |
Commitments and Contingencies
Commitments and Contingencies | 6 Months Ended |
Jun. 30, 2018 | |
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. Marcellus Shale Firm Transportation Contracts In connection with the 2017 Marcellus Shale upstream divestiture, we retained certain firm transportation obligations to flow Marcellus Shale natural gas production to various markets inside and outside of the Marcellus Basin. Our financial commitment for these agreements, which have remaining terms of approximately four to 15 years, is approximately $1.4 billion , undiscounted. The agreements for firm transportation primarily relate to services on certain pipelines which were placed into service in late 2017 and early 2018 or for services on new pipeline projects to be constructed by, and connecting to, existing and new interstate pipeline systems, with estimated in-service dates in late 2018. We are currently engaged in actions to commercialize these commitments which provide for the transportation of 450,000 MMBtu/d of natural gas. Actions include the permanent assignment of capacity, negotiation of capacity release, utilization of capacity through purchase of third party natural gas, and other potential arrangements. We continue to expect these actions, some of which may require pipeline and/or FERC approval, to ultimately reduce our financial commitment associated with these contracts. At the date each pipeline is placed in service and our commitment begins, we will evaluate our position. If we determine that we will not utilize a portion, or all, of the contracted pipeline capacity, we will accrue a liability at fair value for the net amount of the estimated remaining financial commitment. We cannot guarantee our commercialization efforts will be successful and we may recognize substantial future liabilities, at fair value, for the net amount of the estimated remaining commitments under these contracts. As of June 30, 2018 , our exit cost accrual, relating to certain transportation arrangements, totals $83 million , discounted. For the first six months of 2018 , we incurred expense of $3 million related to unutilized transportation related to these contracts. Colorado Air Matter In April 2015, we entered into a joint consent decree (Consent Decree) with the US Environmental Protection Agency, US Department of Justice, and State of Colorado to improve emission control systems at a number of our condensate storage tanks that are part of our upstream crude oil and natural gas operations within the Non-Attainment Area of the DJ Basin. The Consent Decree was entered by the US District Court for the District of Colorado on June 2, 2015. The Consent Decree, which alleges violations of the Colorado Air Pollution Prevention and Control Act and Colorado’s federal approved State Implementation Plan, specifically Colorado Air Quality Control Commission Regulation Number 7, requires us to perform certain corrective actions, to complete mitigation projects, to complete supplemental environmental projects (SEP), and to pay a civil penalty. Costs associated with the settlement consist of $5 million in civil penalties which were paid in 2015. Mitigation costs of $5 million and SEP costs of $4 million are being expended in accordance with schedules established in the Consent Decree. Costs associated with the injunctive relief are also being expended in accordance with schedules established in the Consent Decree. Since 2015, we have incurred approximately $83 million to undertake corrective actions at certain tank systems following the outcome of adequacy of design evaluations and certain operation and maintenance activities to handle potential peak instantaneous vapor flow rates. Future costs associated with injunctive relief are not yet precisely quantifiable as we are continually evaluating various approaches to meet the ongoing obligations of the Consent Decree. Overall compliance with the Consent Decree has resulted in the temporary shut-in and permanent plugging and abandonment of certain wells and associated tank batteries. Consent Decree compliance could result in additional temporary shut-ins and permanent plugging and abandonment of certain wells and associated tank batteries. The Consent Decree sets forth a detailed compliance schedule with deadlines for achievement of milestones through early 2019 that may be extended depending on certain situations. The Consent Decree contains additional obligations for ongoing inspection and monitoring beyond that which is required under existing Colorado regulations. We have concluded that the penalties, injunctive relief, and mitigation expenditures that resulted from this settlement did not have, and based on currently available information will not have, a material adverse effect on our financial position, results of operations or cash flows. Colorado Water Quality Control Division Matter In January 2017, we received a Notice of Violation/Cease and Desist Order (NOV/CDO) advising us of alleged violations of the Colorado Water Quality Control Act (Act) and its implementing regulations as it relates to our Colorado Discharge Permit System General Permit for construction activities associated with oil and gas exploration and /or production within our Wells Ranch Drilling and Production field located in Weld County, Colorado (Permit). The NOV/CDO further orders us to cease and desist from all violations of the Act, the regulations and the Permit and to undertake certain corrective actions. Given the uncertainty associated with administrative actions of this nature, we are unable to predict the ultimate outcome of this action at this time but believe that the resolution of this action will not have a material adverse effect on our financial position, results of operations or cash flows. Colorado Oil and Gas Conservation Commission Administrative Order on Consent In November 2017, we received a proposed Administrative Order on Consent (AOC) from the Colorado Oil and Gas Conservation Commission (COGCC) to resolve allegations of noncompliance associated with site preparation and stabilization at an oil and gas location in Weld County, Colorado. The AOC, which provides for an opportunity to further discuss the offer of settlement, has not yet been executed. Given the uncertainty associated with administrative actions of this nature, we are unable to predict the ultimate outcome of this action at this time, but believe that the resolution of this action will not have a material adverse effect on our financial position, results of operations or cash flows. Colorado Mechanical Integrity Testing Matter |
Basis of Presentation (Policies
Basis of Presentation (Policies) | 6 Months Ended |
Jun. 30, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Presentation | Presentation The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the US (US GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and notes required by US GAAP for complete financial statements. The accompanying consolidated financial statements at June 30, 2018 and December 31, 2017 and for the three and six months ended June 30, 2018 and 2017 contain all normally recurring adjustments considered necessary for a fair presentation of our financial position, results of operations, cash flows and equity for such periods. For the periods presented, activity within other comprehensive income or loss was de minimis; therefore, net income is materially consistent with comprehensive income or loss. Operating results for the three and six months ended June 30, 2018 are not necessarily indicative of the results that may be expected for the year ending December 31, 2018 . These consolidated financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in our Annual Report on Form 10-K for the year ended December 31, 2017 |
Consolidation | Consolidation Our consolidated financial statements include our accounts, the accounts of subsidiaries which Noble Energy wholly owns, and the accounts of Noble Midstream Partners, which is considered a variable interest entity (VIE) for which Noble Energy is the primary beneficiary. In addition, we use the equity method of accounting for investments in entities that we do not control, but over which we exert significant influence. All significant intercompany balances and transactions have been eliminated upon consolidation. |
Estimates | Estimates |
Investment in Shares of Tamar Petroleum | Investment in Shares of Tamar Petroleum We account for our investment in shares of Tamar Petroleum Ltd. at fair value and record changes in fair value in other non-operating expense (income), net in our consolidated statements of operations. |
Intangible Assets | Intangible Assets Intangible assets consist of customer contracts and relationships acquired by Noble Midstream Partners in its acquisition of Saddle Butte Rockies Midstream, LLC and affiliates (collectively, Saddle Butte). We recorded the intangible assets 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 asset, which is currently over periods of seven to 13 years. As of June 30, 2018, the gross book value of the intangible asset was $340 million . Amortization expense of $9 million and $14 million for the three and six months ended June 30, 2018 , respectively, is included in depreciation, depletion and amortization expense in our consolidated statements of operations. Intangible assets with finite useful lives are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. See Note 3. Acquisitions and Divestitures . |
Stock Repurchase Program | Stock Repurchase Program On February 15, 2018 , we announced that the Company's Board of Directors authorized a $ 750 million share repurchase program which expires December 31, 2020 |
Recently Issued Accounting Standards | Recently Issued Accounting Standards Leases In February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2016-02 (ASU 2016-02): Leases. The standard requires lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by leases with terms of more than 12 months. ASU 2016-02 also requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB issued Accounting Standards Update No. 2018-01 (ASU 2018-01): Land Easement Practical Expedient for Transition to Topic 842 , to provide an optional practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under Topic 840. In July 2018, the FASB issued Accounting Standards Update No. 2018-10 (ASU 2018-10): Codification Improvements to Topic 842, Leases , to clarify application of certain aspects of the standard and to remove inconsistencies within the guidance. Furthermore, in July 2018, the FASB issued Accounting Standards Update No. 2018-11 (ASU 2018-11): Leases (Topic 842): Targeted Improvements , which provides for another transition method, in addition to the existing transition method, by allowing entities to initially apply the new leases standard at the adoption date (such as January 1, 2019) and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption (i.e. comparative periods presented in the financial statements will continue to be in accordance with current GAAP (Topic 840, Leases)). The standard will be effective for annual and interim periods beginning after December 15, 2018, with earlier application permitted. In the normal course of business, we enter into capital and operating lease agreements to support our exploration and development operations and lease assets such as drilling rigs, platforms, storage facilities, field services and well equipment, pipeline capacity, office space and other assets. We will adopt the new standard on the effective date of January 1, 2019. Although we continue to assess the impact of the standard on our consolidated financial statements, we believe adoption and implementation will result in an increase in assets and liabilities as well as additional disclosures. We do not expect a material impact on our consolidated statement of operations. We have developed and are executing a project plan, which includes contract review and assessment, as well as evaluation of our systems, processes and internal controls. In addition, we plan to implement new lease accounting software. Accumulated Other Comprehensive Income In February 2018, the FASB issued Accounting Standards Update No. 2018-02 (ASU 2018-02): Income Statement – Reporting Comprehensive Income, to allow reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act. ASU 2018-02 will be effective for annual and interim periods beginning after December 15, 2018, with earlier application permitted. As of June 30, 2018, we have a disproportionate tax effect of approximately $7 million stranded in accumulated other comprehensive income. We are currently evaluating the provisions of this standard. Intangibles – Goodwill and Other: Simplifying the Test for Goodwill Impairment In January 2017, the FASB issued Accounting Standards Update No. 2017-04 (ASU 2017-04): Intangibles – Goodwill and Other – Simplifying the Test for Goodwill Impairment, to simplify how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. Under the new standard, we will perform our goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount, with an impairment charge being recognized for the amount by which the carrying amount exceeds the reporting unit’s fair value. ASU 2017-04 will be effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019, with early adoption permitted. We are currently evaluating the provisions of ASU 2017-04. Financial Instruments: Credit Losses In June 2016, the FASB issued Accounting Standards Update No. 2016-13 (ASU 2016-13): Financial Instruments – Credit Losses |
Revenue from Contract with Customer [Policy Text Block] | MIDSTREAM REVENUE ARRANGEMENTS Our Midstream segment revenues are derived from fixed fee contract arrangements for gathering, transportation and storage services. We have determined that our performance obligations for the provision of such services are satisfied over time using volumes delivered as the measure of progress. ASC 606 adoption did not have an impact on the recognition, measurement and presentation of our midstream revenues and expenses. Crude Oil Purchase and Sale Arrangements – US Our revenue is derived from the sale of crude oil, NGL and natural gas production primarily to crude oil refining companies, midstream marketing companies, marketers, industrial companies, electric utility companies, independent power producers and cogeneration facilities, among others. We account for revenue in accordance with ASC 606, Revenue from Contracts with Customers (ASC 606), which we adopted on January 1, 2018 using the modified retrospective method. Under ASC 606, performance obligations are the unit of account and generally represent distinct goods or services that are promised to customers. For sales of crude oil, NGLs and natural gas, each unit sold is generally considered a distinct good and the related performance obligation is generally satisfied at a point in time. We recognize our sales revenues at a point in time and upon delivery to a customer at the contractually stated price and for the quantity of product delivered. In Israel, because our contracts are long-term arrangements, we recognize revenues from the sale of natural gas over the life of the contract based on the quantity of natural gas delivered. ASC 606 provides additional clarification related to principal versus agent considerations. Under this guidance, we record revenue on a gross basis if we control a promised good or service before transferring it to a customer. For example, gathering, processing, transportation and fractionation costs incurred before transfer of control to the customer at the tailgate of a plant are accounted for as fulfillment costs and are presented as a component of gathering, transportation and processing expense in our consolidated statements of operations. On the other hand, we record revenue on a net basis if our role is to arrange for another entity to provide the goods or services. For example, costs incurred after control over the product has transferred to the customer, such as at the wellhead or inlet of a plant, are recorded as a reduction of the transaction price received within revenue. Certain of our contracts for the sale of commodities contain embedded derivatives. We have elected the normal purchases and normal sales scope exception as provided by ASC 815, Derivatives and Hedging , and will account for such contracts in accordance with ASC 606. In the US, we enter into marketing agreements with our non-operating partners to market and sell their share of production to third parties. We have determined that we act as an agent in such arrangements and account for such arrangements on a net basis. ASC 606 adoption did not have an impact on the opening balance of retained earnings. The adoption resulted in de minimis increases of $2 million and $7 million to both revenues and expenses for second quarter and the first six months of 2018 , respectively, but did not affect operating or net income or operating cash flows. The comparative information for the prior period has not been recast and continues to be reported under the accounting standards in effect for the period. Adoption of the new standard did not impact our financial position, and we do not expect that it will do so going forward. Changes to the presentation of commodity sales revenue and production expense resulted from our assessment of certain contractual arrangements under principal versus agent guidance and assessment of control under ASC 606. In particular, we have determined that the processor is our customer with regard to the sale of natural gas at the wellhead or the sale of NGLs at the tailgate. This is a change from previous conclusions reached under principal versus agent guidance per ASC 605, Revenue Recognition , where we previously retained control over our production until the sale to the end customer in the downstream markets. As such, effective January 1, 2018, revenues and expenses are presented on a net basis within revenues in our consolidated statements of operations at the time control over production is transferred to the processor under these arrangements. Following the control model in ASC 606, we determined that we remain the principal in arrangements with the end customers, such as when we take product in-kind at the tailgate and when we are directly responsible for the transportation and marketing of our production in the downstream markets. In such arrangements, we record NGL and natural gas sales and production expense on a gross basis. Our commodity sale contracts in the US are index-based and, thus, include variable consideration. In accordance with ASC 606, we allocate variable consideration (market price) to the distinct commodities transferred in the period, but not to the future obligations to deliver production. Such allocation represents the amount of consideration to which we are entitled for deliveries of our commodities to-date and represents the value of product delivered to the customer. Therefore, our revenue is recognized at the time of delivery and is the product of the volume delivered and the index-based price for the period. The following is a summary of our types of revenue arrangements by commodity and geographic location. EXPLORATION AND PRODUCTION (E&P) REVENUE ARRANGEMENTS Crude Oil Sale Arrangements – US We sell the majority of our US crude oil production under short-term contracts at market-based prices, adjusted for location, quality and transportation charges. Market-based pricing is based on the price index applicable for the location of the sale. We sell our crude oil production either at the lease location or in downstream markets. Crude oil production at the lease location is sold through netback arrangements, under which we sell crude oil net of transportation costs incurred by the purchaser. We record revenue, net, at the lease location when the customer receives delivery of the product. When we move our crude oil production from the lease location to the downstream markets in the US, we incur gathering and transportation costs, which we consider contract fulfillment activities. Such costs are reported as expense within gathering, transportation and processing expense in the consolidated statements of operations. Revenue from the sale of crude oil in downstream markets is recognized upon delivery, as specified in the contract, when control of the product has transferred to the customer. In second quarter 2018, we entered into a long-term contract to sell firm quantities of crude oil under index-based prices adjusted by applicable fees, including transportation, insurance, and marketing. Crude Oil Buy/Sell Transactions – US We enter into buy/sell arrangements that effect a change in location and/or grade with required repurchase of crude oil at a delivery point. The sale and repurchase of crude oil is settled at the same contractually fixed price (before application of transportation and grade deductions) on a net basis. We account for these transactions on a net basis, in accordance with ASC 845, Nonmonetary Transactions . We record the residual transportation fee as transportation expense within gathering, transportation and processing expense in the consolidated statements of operations. Crude Oil Sale Arrangements – West Africa Our share of crude oil and condensate from the Aseng, Alen and Alba fields is sold at market-based prices to Glencore Energy UK Ltd (Glencore Energy). Crude oil is priced at a Dated Brent FOB net realized price achieved by Glencore Energy and is adjusted by applicable fees, including transportation, insurance, and marketing. We recognize revenue on the sale of crude oil to Glencore Energy at the time crude oil cargo is loaded onto the tanker and control transfers to Glencore Energy. We record revenue at the realized price received from Glencore Energy, net of applicable fees. Natural Gas and NGLs Sale Arrangements – US Certain of our commodity contracts in the US are for the sale of natural gas to processors at prevailing market prices. We evaluate the contract terms of these arrangements to determine whether the processor is a service provider or a customer on a contract by contract basis. In arrangements where we determine that we sold our product to the processor, we record revenue when the processor takes physical possession of 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 natural gas processing arrangements, we receive natural gas and NGL products "in-kind" after processing at the tailgate of the plant. In these arrangements, we are responsible for the transportation, fractionation and marketing costs of our production. In such cases, we record the sale of natural gas and NGLs and applicable gathering, processing, transportation and fractionation fees on a gross basis at the time the product is delivered to the end customer. Natural Gas Purchase and Sale Arrangements – US We enter into purchase transactions and separate sale transactions with third parties at prevailing market prices to mitigate unutilized pipeline transportation commitments, primarily related to retained Marcellus Shale firm transportation agreements. Revenues and expenses from the sales and purchases are recorded on a gross basis, as we act as a principal in these transactions by assuming control of the purchased commodity before it is transferred to the customer. Natural Gas Sale Arrangements – West Africa We sell our share of natural gas production from the Alba field under 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 – Israel Our natural gas sales in Israel are primarily based on long-term contracts with fixed volume commitments over the life of the arrangements. Our performance obligations for the sale of natural gas are satisfied over time using production output to measure progress. The nature of these contracts gives rise to several types of variable consideration, including index-based annual price escalations, commodity-based index pricing, tiered pricing and sales price discounts in periods of volume deficiencies. Additionally, the majority of our sales contracts contain take-or-pay provisions where the customers are required to purchase a contractual minimum over varying time periods. Where the variable consideration is related to market-based pricing or index-based escalations of a fixed base price, we have elected the variable consideration allocation exception pursuant to ASC 606. We record revenue related to the volumes delivered at the contract price at the time of delivery. To date, there have been no impacts of variability in consideration due to tiered pricing, take-or-pay provisions and/or volume deficiency discounts. We believe that any variability due to future sales price adjustments associated with potential volume deficiencies will not have a significant impact on our financial position or results of operations. Transaction Price Allocated to Remaining Performance Obligations – Israel |
Basis of Presentation (Tables)
Basis of Presentation (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Statement of Operations Information | Other statements of operations information is as follows: Three Months Ended June 30, Six Months Ended June 30, (millions) 2018 2017 2018 2017 Income From Equity Method Investees and Other Income from Equity Method Investees $ 49 $ 38 $ 96 $ 80 Sales of Purchased Oil and Gas (1) 66 — 119 — Midstream Services Revenues – Third Party 15 4 28 4 Total $ 130 $ 42 $ 243 $ 84 Production Expense Lease Operating Expense $ 132 $ 124 $ 287 $ 263 Production and Ad Valorem Taxes 50 32 104 73 Gathering, Transportation and Processing Expense 100 121 195 240 Other Royalty Expense 10 6 27 10 Total $ 292 $ 283 $ 613 $ 586 Exploration Expense Leasehold Impairment and Amortization $ — $ — $ — $ 18 Seismic, Geological and Geophysical 2 8 13 13 Staff Expense 13 16 27 29 Other 14 6 24 12 Total $ 29 $ 30 $ 64 $ 72 Other Operating Expense, Net Marketing Expense (2) $ 7 $ 14 $ 12 $ 33 Purchased Oil and Gas (1) 71 — 128 — Clayton Williams Energy Acquisition Expenses — 90 — 94 Other, Net (4 ) 14 4 20 Total $ 74 $ 118 $ 144 $ 147 Other Non-Operating Expense (Income), Net Loss on Investment in Shares of Tamar Petroleum Ltd., Net (3) $ 11 $ — $ 26 $ — Other — (5 ) (2 ) (6 ) Total $ 11 $ (5 ) $ 24 $ (6 ) (1) As part of the Saddle Butte acquisition in first quarter 2018, we acquired certain contracts which include the purchase and sale of crude oil with third parties. In addition, we have entered into certain transactions beginning in first quarter 2018 for the purchase of third party natural gas and the subsequent sale of natural gas to other third parties. The natural gas is transported through firm transportation capacity we retained following the Marcellus Shale upstream divestiture in second quarter 2017 and is part of our mitigation efforts to utilize capacity and reduce our financial commitment. The cost to purchase natural gas includes transportation expense incurred of $6 million and $11 million for second quarter and the first six months of 2018 , respectively. See Note 11. Segment Information and Note 12. Commitments and Contingencies . (2) Expense relates to unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments. (3) Amounts for second quarter and the first six months of 2018 include losses of $11 million and $40 million , respectively, related to the change in fair value. The loss for the six months ended June 30, 2018 is partially offset by dividend income of $14 million |
Balance Sheet Information Table | Other balance sheet information is as follows: (millions) June 30, December 31, Accounts Receivable, Net Commodity Sales $ 460 $ 455 Joint Interest Billings 210 207 Other 89 103 Allowance for Doubtful Accounts (16 ) (17 ) Total $ 743 $ 748 Other Current Assets Inventories, Materials and Supplies $ 46 $ 66 Inventories, Crude Oil 27 16 Commodity Derivative Assets 29 2 Assets Held for Sale (1) 40 629 Restricted Cash (2) — 38 Prepaid Expenses and Other Current Assets 45 29 Total $ 187 $ 780 Other Noncurrent Assets Equity Method Investments (3) $ 357 $ 305 Customer-Related Intangible Assets (4) 326 — Investment in Shares of Tamar Petroleum Ltd. (5) 150 — Mutual Fund Investments 57 57 Net Deferred Income Tax Asset 25 25 Other Assets, Noncurrent 69 74 Total $ 984 $ 461 Other Current Liabilities Production and Ad Valorem Taxes $ 111 $ 84 Commodity Derivative Liabilities 250 58 Income Taxes Payable 5 18 Asset Retirement Obligations 92 51 Interest Payable 64 67 Current Portion of Capital Lease Obligations 47 61 Liabilities Associated with Assets Held for Sale (1) — 55 Compensation and Benefits Payable 66 98 Other Liabilities, Current 110 86 Total $ 745 $ 578 Other Noncurrent Liabilities Deferred Compensation Liabilities $ 180 $ 197 Asset Retirement Obligations 543 824 Marcellus Shale Firm Transportation Commitment (6) 71 76 Production and Ad Valorem Taxes 39 69 Commodity Derivative Liabilities 85 15 Other Liabilities, Noncurrent 77 64 Total $ 995 $ 1,245 (1) Assets held for sale at June 30, 2018 include assets in the Greeley Crescent area of the DJ Basin. Assets held for sale at December 31, 2017 include assets in the Greeley Crescent area of the DJ Basin, a 7.5% interest in the Tamar field, offshore Israel, our interest in Southwest Royalties, Inc. acquired in the Clayton Williams Energy Acquisition, and the CONE investments. Liabilities associated with assets held for sale primarily represent asset retirement obligations and other liabilities to be assumed by the purchaser. See Note 3. Acquisitions and Divestitures . (2) Balance at December 31, 2017 represents amount held in escrow pending closing of the Saddle Butte acquisition. See Note 3. Acquisitions and Divestitures . (3) Includes $49 million for our investment in shares of CNX Midstream Partners LP. At December 31, 2017 , this investment was included in assets held for sale. See Note 3. Acquisitions and Divestitures and Note 6. Fair Value Measurements and Disclosures . (4) Amount relates to intangible assets acquired in the Saddle Butte acquisition and is net of $14 million of accumulated amortization. See Note 3. Acquisitions and Divestitures . (5) Amount relates to our investment in shares of Tamar Petroleum Ltd. See Note 3. Acquisitions and Divestitures and Note 6. Fair Value Measurements and Disclosures . (6) Amounts relate to the long-term portion of retained firm transportation agreements. At June 30, 2018 and December 31, 2017 , we recorded $12 million and $14 million , respectively, associated with the current portion of the Marcellus Shale firm transportation commitment. See Note 12. Commitments and Contingencies |
Summary of Cash, Cash Equivalents and Restricted Cash | We define total cash as cash, cash equivalents and restricted cash. The following table provides a reconciliation of total cash: Six Months Ended June 30, (millions) 2018 2017 Cash and Cash Equivalents at Beginning of Period $ 675 $ 1,180 Restricted Cash at Beginning of Period 38 30 Cash, Cash Equivalents, and Restricted Cash at Beginning of Period $ 713 $ 1,210 Cash and Cash Equivalents at End of Period $ 621 $ 540 Restricted Cash at End of Period — — Cash, Cash Equivalents, and Restricted Cash at End of Period $ 621 $ 540 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | The following table includes estimated revenues based upon those certain agreements with fixed minimum take-or-pay sales volumes. Our actual future sales volumes under these agreements may exceed future minimum volume commitments. (millions) July - Dec 2018 2019 2020 Total Natural Gas Revenues (1) $ 107 $ 137 $ 169 $ 413 (1) |
Acquisitions and Divestitures A
Acquisitions and Divestitures Acquisitions and Divestitures (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Business Combinations [Abstract] | |
Schedule of Business Acquisitions, by Acquisition | The following table represents the final allocation of the total purchase price of Clayton Williams Energy to the assets acquired and liabilities assumed, based on the fair value at the acquisition date, with any excess of the purchase price over the estimated fair value of the identifiable ne t assets acquired recorded as goodwill. (millions) Fair Value of Common Stock Issued $ 1,851 Plus: Cash Consideration Paid to Clayton Williams Energy Stockholders 637 Total Purchase Price $ 2,488 Plus Liabilities Assumed by Noble Energy: Accounts Payable 99 Other Current Liabilities 38 Long-Term Deferred Tax Liability 515 Long-Term Debt 595 Asset Retirement Obligations 63 Total Purchase Price Plus Liabilities Assumed $ 3,798 The fair value of Clayton Williams Energy's identifiable assets was as follows: (millions) Cash and Cash Equivalents $ 21 Other Current Assets 70 Oil and Gas Properties: Proved Reserves 722 Undeveloped Leasehold Costs 1,571 Gathering and Processing Assets 48 Asset Retirement Costs 63 Other Noncurrent Assets 12 Implied Goodwill 1,291 Total Asset Value $ 3,798 |
Business Acquisition, Pro Forma Information | The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Clayton Williams Energy Acquisitio n taken place on January 1, 2017 ; furthermore, the financial information is not intended to be a projection of future results. Three Months Ended June 30, Six Months Ended June 30, (millions, except per share amounts) 2018 (1) 2017 2018 (1) 2017 Revenues $ 1,230 $ 1,070 $ 2,516 $ 2,141 Net (Loss) Income and Comprehensive (Loss) Income Attributable to Noble Energy (23 ) (1,354 ) 531 (1,324 ) Net (Loss) Income Attributable to Noble Energy per Common Share Basic $ (0.05 ) $ (2.77 ) $ 1.09 $ (2.71 ) Diluted $ (0.05 ) $ (2.77 ) $ 1.09 $ (2.71 ) (1) No pro forma adjustments were made for the period as Clayton Williams Energy operations are included in our historical results. |
Derivative Instruments and He23
Derivative Instruments and Hedging Activities (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Unsettled Derivative Instruments | As of June 30, 2018 , the following crude oil derivative contracts were outstanding: Swaps Collars Settlement Period Type of Contract Index Bbls Per Day Weighted Average Differential Weighted Average Fixed Price Weighted Average Short Put Price Weighted Average Floor Price Weighted Average Ceiling Price 2018 Swaps NYMEX WTI 66,000 $ — $ 60.30 $ — $ — $ — 2018 Collars NYMEX WTI 18,000 — — — 50.42 58.82 2018 Three-Way Collars NYMEX WTI 10,000 — — 45.50 52.50 69.09 2018 Three-Way Collars Dated Brent 3,000 — — 40.00 50.00 70.41 2018 Swaps ICE Brent 2,000 — 59.00 — — — 2018 Collars ICE Brent 2,000 — — — 50.00 55.25 2018 Three-Way Collars ICE Brent 5,000 — — 43.00 50.00 59.50 2018 Basis Swaps (1) 20,000 (2.30 ) — — — — 2019 Swaps NYMEX WTI 44,000 — 58.37 — — — 2019 Three-Way Collars NYMEX WTI 6,000 — — 50.00 60.00 72.75 2019 Swaps ICE Brent 5,000 — 57.00 — — — 2019 Three-Way Collars ICE Brent 3,000 — — 43.00 50.00 64.07 2019 Basis Swaps (1) 27,000 (3.23 ) — — — — 2020 Swaption (2) NYMEX WTI 5,000 — 61.79 — — — 2020 Basis Swaps (1) 15,000 (5.01 ) — — — — (1) We have entered into crude oil basis swap contracts in order to establish a fixed amount for the differential between pricing in Midland, Texas, and Cushing, Oklahoma. The weighted average differential represents the amount of reduction to Cushing, Oklahoma prices for the notional volumes covered by the basis swap contracts. (2) We have entered into certain derivative contracts (swaptions), which give counterparties the right, but not the obligation, to enter into swap agreements with us on the option expiration dates. As of June 30, 2018 , the following natural gas derivative contracts were outstanding: Swaps Collars Settlement Period Type of Contract Index MMBtu Per Day Weighted Average Fixed Price Weighted Average Short Put Price Weighted Average Floor Price Weighted Average Ceiling Price 2018 Three-Way Collars NYMEX HH 120,000 $ — $ 2.50 $ 2.88 $ 3.65 |
Fair Value of Derivative Instruments | The fair values of commodity derivative instruments in our consolidated balance sheets were as follows: Fair Value of Derivative Instruments Asset Derivative Instruments Liability Derivative Instruments June 30, December 31, June 30, December 31, (millions) Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Commodity Derivative Instruments Current Assets $ 29 Current Assets $ 2 Current Liabilities $ 250 Current Liabilities $ 58 Noncurrent Assets — Noncurrent Assets — Noncurrent Liabilities 85 Noncurrent Liabilities 15 Total $ 29 $ 2 $ 335 $ 73 |
Derivative Instruments, (Gain) Loss | The effect of commodity derivative instruments on our consolidated statements of operations was as follows: Three Months Ended June 30, Six Months Ended June 30, (millions) 2018 2017 2018 2017 Cash Paid (Received) in Settlement of Commodity Derivative Instruments Crude Oil $ 66 $ (11 ) $ 96 $ (16 ) Natural Gas (1 ) — (3 ) 2 Total Cash Paid (Received) in Settlement of Commodity Derivative Instruments 65 (11 ) 93 (14 ) Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments Crude Oil 181 (28 ) 231 (91 ) Natural Gas 3 (18 ) 4 (62 ) Total Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments 184 (46 ) 235 (153 ) Loss (Gain) on Commodity Derivative Instruments Crude Oil 247 (39 ) 327 (107 ) Natural Gas 2 (18 ) 1 (60 ) Total Loss (Gain) on Commodity Derivative Instruments $ 249 $ (57 ) $ 328 $ (167 ) |
Debt (Tables)
Debt (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Debt Disclosure [Abstract] | |
Schedule of debt | Debt consists of the following: June 30, December 31, (millions, except percentages) Debt Interest Rate Debt Interest Rate Revolving Credit Facility, due March 9, 2023 $ — — % $ 230 2.27 % Noble Midstream Services Revolving Credit Facility, due March 9, 2023 530 3.25 % 85 2.75 % Leviathan Term Loan Facility, due February 23, 2025 — — % — — % Senior Notes, due May 1, 2021 (1) — — % 379 5.63 % Senior Notes, due December 15, 2021 1,000 4.15 % 1,000 4.15 % Senior Notes, due October 15, 2023 100 7.25 % 100 7.25 % Senior Notes, due November 15, 2024 650 3.90 % 650 3.90 % Senior Notes, due April 1, 2027 250 8.00 % 250 8.00 % Senior Notes, due January 15, 2028 600 3.85 % 600 3.85 % Senior Notes, due March 1, 2041 850 6.00 % 850 6.00 % Senior Notes, due November 15, 2043 1,000 5.25 % 1,000 5.25 % Senior Notes, due November 15, 2044 850 5.05 % 850 5.05 % Senior Notes, due August 15, 2047 500 4.95 % 500 4.95 % Other Senior Notes and Debentures (2) 92 7.13 % 92 7.13 % Capital Lease Obligations 241 — % 273 — % Total 6,663 6,859 Unamortized Discount (23 ) (24 ) Unamortized Premium (1) — 12 Unamortized Debt Issuance Costs (38 ) (40 ) Total Debt, Net of Unamortized Discount, Premium and Debt Issuance Costs 6,602 6,807 Less Amounts Due Within One Year Capital Lease Obligations (47 ) (61 ) Long-Term Debt Due After One Year $ 6,555 $ 6,746 (1) In second quarter 2018, we redeemed all of the Senior Notes due May 1, 2021, writing off the associated premium. See Redemption of Senior Notes, below. (2) Includes $8 million of Senior Notes due June 1, 2024 and $84 million of Senior Debentures due August 1, 2097. The weighted average interest rate for these instruments is 7.13% . |
Fair Value Measurements and D25
Fair Value Measurements and Disclosures (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Fair Value Disclosures [Abstract] | |
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis | Measurement information for assets and liabilities that are measured at fair value on a recurring basis was as follows: Fair Value Measurements Using (millions) Quoted Prices in Active Markets (Level 1) (1) Significant Other Observable Inputs (Level 2) (2) Significant Unobservable Inputs (Level 3) (3) Adjustment (4) Fair Value Measurement June 30, 2018 Financial Assets: Mutual Fund Investments $ 57 $ — $ — $ — $ 57 Commodity Derivative Instruments — 72 — (43 ) 29 Investment in Tamar Petroleum Ltd. (38,495,575 Shares) (5) — 150 — — 150 Financial Liabilities: Commodity Derivative Instruments — (378 ) — 43 (335 ) Portion of Deferred Compensation Liability Measured at Fair Value (73 ) — — — (73 ) Stock Based Compensation Liability Measured at Fair Value (12 ) — — — (12 ) December 31, 2017 Financial Assets: Mutual Fund Investments $ 57 $ — $ — $ — $ 57 Commodity Derivative Instruments — 7 — (5 ) 2 Financial Liabilities: Commodity Derivative Instruments — (78 ) — 5 (73 ) Portion of Deferred Compensation Liability Measured at Fair Value (71 ) — — — (71 ) Stock Based Compensation Liability Measured at Fair Value (10 ) — — — (10 ) (1) Level 1 measurements are fair value measurements which use quoted market prices (unadjusted) in active markets for identical assets or liabilities. We use Level 1 inputs when available as Level 1 inputs generally provide the most reliable evidence of fair value. (2) Level 2 measurements are fair value measurements which use inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly. (3) Level 3 measurements are fair value measurements which use unobservable inputs. (4) Amount represents the impact of netting provisions within our master agreements that allow us to net cash settle asset and liability positions with the same counterparty. (5) As of June 30, 2018, the closing price on the TASE of publicly traded and unrestricted shares of Tamar Petroleum Ltd. was $4.60 |
Investment in CNX Midstream Partners | The fair value of the investment is based on the published market price of the common units for the date indicated below. June 30, 2018 December 31, 2017 (millions) Carrying Amount Fair Value Carrying Amount Fair Value Investment in CNX Midstream Partners (14,217,198 Common Units and 21,692,198 Common Units, respectively) (1) $ 49 $ 276 $ 70 $ 364 (1) During second quarter 2018, we sold 7.5 million common units, reducing our ownership in CNX Midstream Partners. See Note 3. Acquisitions and Divestitures |
Additional fair value disclosures | Fair value information regarding our debt is as follows: June 30, 2018 December 31, 2017 (millions) Carrying Amount Fair Value Carrying Amount Fair Value Long-Term Debt (1) $ 6,422 $ 6,591 $ 6,586 $ 7,142 (1) |
Capitalized Exploratory Well 26
Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Extractive Industries [Abstract] | |
Changes in Capitalized Exploratory Well Costs | Changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and subsequently expensed in the same period: (millions) Six Months Ended June 30, 2018 Capitalized Exploratory Well Costs, Beginning of Period $ 520 Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves 4 Divestitures (1) (167 ) Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves (1 ) Capitalized Exploratory Well Costs Charged to Expense — Capitalized Exploratory Well Costs, End of Period $ 356 (1) |
Aging of Capitalized Well Costs | The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced: (millions) June 30, December 31, Exploratory Well Costs Capitalized for a Period of One Year or Less $ 8 $ 10 Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling 348 510 Balance at End of Period $ 356 $ 520 Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling 7 8 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Changes in Asset Retirement Obligations | Changes in ARO are as follows: Six Months Ended June 30, (millions) 2018 2017 Asset Retirement Obligations, Beginning Balance $ 875 $ 935 Liabilities Incurred 14 82 Liabilities Settled (261 ) (32 ) Revisions of Estimates (10 ) (15 ) Accretion Expense (1) 17 23 Asset Retirement Obligations, Ending Balance $ 635 $ 993 (1) Accretion expense is included in depreciation, depletion and amortization (DD&A) expense in the consolidated statements of |
Income Per Share Attributable28
Income Per Share Attributable to Noble Energy (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Earnings Per Share [Abstract] | |
Schedule of earnings per share | The following table summarizes the calculation of basic and diluted income (loss) per share: Three Months Ended June 30, Six Months Ended June 30, (millions, except per share amounts) 2018 2017 2018 2017 Net (Loss) Income and Comprehensive (Loss) Income Attributable to Noble Energy $ (23 ) $ (1,512 ) $ 531 $ (1,476 ) Weighted Average Number of Shares Outstanding, Basic 484 472 485 452 Incremental Shares from Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust — — 2 — Weighted Average Number of Shares Outstanding, Diluted 484 472 487 452 (Loss) Income Per Share, Basic $ (0.05 ) $ (3.20 ) $ 1.09 $ (3.27 ) (Loss) Income Per Share, Diluted (0.05 ) (3.20 ) 1.09 (3.27 ) Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above 14 16 14 15 |
Income Taxes (Tables)
Income Taxes (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Income Tax Disclosure [Abstract] | |
Income Tax Provision (Benefit) | The income tax (benefit) expense consists of the following: Three Months Ended June 30, Six Months Ended June 30, (millions, except percentages) 2018 2017 2018 2017 Current $ 23 $ 37 $ 149 $ 49 Deferred (7 ) (873 ) (164 ) (873 ) Total Income Tax Expense (Benefit) $ 16 $ (836 ) $ (15 ) $ (824 ) Effective Tax Rate 160.0 % 35.8 % (2.7 )% 36.2 % |
Segment Information (Tables)
Segment Information (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Segment Reporting [Abstract] | |
Segment Information | Oil and Gas Exploration and Production Midstream (millions) Consolidated United Eastern West Other Int'l United States Intersegment Eliminations and Other (1) Corporate Three Months Ended June 30, 2018 Crude Oil Sales $ 749 $ 635 $ 2 $ 112 $ — $ — $ — $ — NGL Sales 137 137 — — — — — — Natural Gas Sales 214 98 111 5 — — — — Total Crude Oil, NGL and Natural Gas Sales 1,100 870 113 117 — — — — Income from Equity Method Investees and Other 64 — — 36 — 28 — — Sales of Purchased Oil and Gas 66 24 — — — 42 — — Intersegment Revenues — — — — — 85 (85 ) — Total Revenues 1,230 894 113 153 — 155 (85 ) — Lease Operating Expense 132 114 5 19 — — (6 ) — Production and Ad Valorem Taxes 50 48 — — — 2 — — Gathering, Transportation and Processing Expense 100 133 — — — 22 (55 ) — Other Royalty Expense 10 10 — — — — — — Total Production Expense 292 305 5 19 — 24 (61 ) — DD&A 465 394 15 26 — 22 (4 ) 12 Loss (Gain) on Divestitures (78 ) 21 10 — — (109 ) — — Purchased Oil and Gas 71 31 — — — 40 — — Loss on Commodity Derivative Instruments 249 196 — 53 — — — — (Loss) Income Before Income Taxes 10 (90 ) 62 48 (13 ) 175 (18 ) (154 ) Three Months Ended June 30, 2017 Crude Oil Sales $ 557 $ 458 $ 1 $ 98 $ — $ — $ — $ — NGL Sales 108 108 — — — — — — Natural Gas Sales 352 214 132 6 — — — — Total Crude Oil, NGL and Natural Gas Sales 1,017 780 133 104 — — — — Income from Equity Method Investees and Other 42 — — 25 — 17 — — Intersegment Revenues — — — — — 69 (69 ) — Total Revenues 1,059 780 133 129 — 86 (69 ) — Lease Operating Expense 124 105 6 18 — — (5 ) — Production and Ad Valorem Taxes 32 32 — — — — — — Gathering, Transportation and Processing Expense 121 142 — — — 17 (38 ) — Other Royalty Expense 6 6 — — — — — — Total Production Expense 283 285 6 18 — 17 (43 ) — DD&A 503 427 19 39 1 5 — 12 Loss on Marcellus Shale Upstream Divestiture 2,322 2,322 — — — — — — Loss on Commodity Derivative Instruments (57 ) (51 ) — (6 ) — — — — (Loss) Income Before Income Taxes (2,334 ) (2,319 ) 106 72 (4 ) 58 (13 ) (234 ) Six Months Ended June 30, 2018 Crude Oil Sales $ 1,522 $ 1,317 $ 4 $ 201 $ — $ — $ — $ — NGL Sales 283 283 — — — — — — Natural Gas Sales 468 218 240 10 — — — — Total Crude Oil, NGL and Natural Gas Sales 2,273 1,818 244 211 — — — — Income from Equity Method Investees and Other 124 — — 71 — 53 — — Sales of Purchased Oil and Gas 119 55 — — — 64 — — Intersegment Revenues — — — — — 166 (166 ) — Total Revenues 2,516 1,873 244 282 — 283 (166 ) — Lease Operating Expense 287 240 12 41 — — (6 ) — Production and Ad Valorem Taxes 104 101 — — — 3 — — Gathering, Transportation and Processing Expense 195 260 — — — 43 (108 ) — Other Royalty Expense 27 27 — — — — — — Total Production Expense 613 628 12 41 — 46 (114 ) — DD&A 933 800 28 52 — 38 (8 ) 23 Gain on Divestitures (666 ) 15 (376 ) — — (305 ) — — Asset Impairments 168 168 — — — — — — Purchased Oil and Gas 128 67 — — — 61 — — Loss on Commodity Derivative Instruments 328 260 — 68 — — — — Income (Loss) Before Income Taxes 553 (127 ) 535 112 (27 ) 428 (40 ) (328 ) Six Months Ended June 30, 2017 Crude Oil Sales $ 1,084 $ 897 $ 2 $ 185 $ — $ — $ — $ — NGL Sales 213 213 — — — — — — Natural Gas Sales 714 440 263 11 — — — — Total Crude Oil, NGL and Natural Gas Sales 2,011 1,550 265 196 — — — — Income from Equity Method Investees and Other 84 — — 52 — 32 — — Intersegment Revenues — — — — — 127 (127 ) — Total Revenues 2,095 1,550 265 248 — 159 (127 ) — Lease Operating Expense 263 211 14 40 — — (2 ) — Production and Ad Valorem Taxes 73 72 — — — 1 — — Gathering, Transportation and Processing Expense 240 280 — — — 32 (72 ) — Other Royalty Expense 10 10 — — — — — — Total Production Expense 586 573 14 40 — 33 (74 ) — DD&A 1,031 886 37 74 2 10 — 22 Loss on Marcellus Shale Upstream Divestiture 2,322 2,322 — — — — — — Gain on Commodity Derivative Instruments (167 ) (154 ) — (13 ) — — — — Income (Loss) Before Income Taxes (2,275 ) (2,251 ) 207 138 (11 ) 107 (35 ) (430 ) June 30, 2018 Goodwill (2) $ 1,402 $ 1,291 $ — $ — $ — $ 111 $ — $ — Total Assets 21,854 15,138 2,996 1,275 62 2,280 (140 ) 243 December 31, 2017 Goodwill (2) 1,310 1,310 — — — — — — Total Assets 21,476 15,767 2,846 1,308 114 1,357 (163 ) 247 (1) The intersegment eliminations related to income (loss) before income taxes are the result of midstream expenditures. These costs are presented as property, plant and equipment within the E&P business on an unconsolidated basis, in accordance with the successful efforts method of accounting, and are eliminated upon consolidation. (2) |
Basis of Presentation - Narrati
Basis of Presentation - Narrative (Details) $ / shares in Units, shares in Millions, $ in Millions | 3 Months Ended | 6 Months Ended | ||||
Jun. 30, 2018USD ($)$ / sharesshares | Jun. 30, 2017USD ($) | Jun. 30, 2018USD ($)$ / shares$ / MMBTUshares | Jun. 30, 2017USD ($) | Mar. 31, 2018USD ($) | Feb. 15, 2018USD ($) | |
Finite-Lived Intangible Assets [Line Items] | ||||||
Intangible assets, gross | $ 340 | $ 340 | ||||
Amortization expense | $ 9 | $ 14 | ||||
Share purchase plan, authorized amount | $ 750 | |||||
Shares repurchased and retired during period (in shares) | shares | 1.8 | 4 | ||||
Repurchase price (in usd per share) | $ / shares | $ 35.15 | $ 32.41 | ||||
Revenues | $ 1,230 | $ 1,059 | $ 2,516 | $ 2,095 | ||
Expenses | 887 | $ 3,359 | 1,465 | $ 4,360 | ||
Stranded tax assets | 7 | $ 7 | ||||
Minimum | ||||||
Finite-Lived Intangible Assets [Line Items] | ||||||
Intangible asset, useful life | 7 years | |||||
Maximum | ||||||
Finite-Lived Intangible Assets [Line Items] | ||||||
Intangible asset, useful life | 13 years | |||||
ASC 606 | ||||||
Finite-Lived Intangible Assets [Line Items] | ||||||
Revenues | 2 | |||||
Expenses | 7 | |||||
West Africa | ||||||
Finite-Lived Intangible Assets [Line Items] | ||||||
Contractual sales price (in usd per MMBtu) | $ / MMBTU | 0.25 | |||||
Retained Earnings | ASC 606 | ||||||
Finite-Lived Intangible Assets [Line Items] | ||||||
Cumulative effect of adoption | $ 2 | $ 2 | $ 7 |
Basis of Presentation - Stateme
Basis of Presentation - Statements of Operations Information (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Income From Equity Method Investees and Other | ||||
Income from Equity Method Investees | $ 49 | $ 38 | $ 96 | $ 80 |
Sales of Purchased Oil and Gas | 66 | 0 | 119 | 0 |
Midstream Services Revenues – Third Party | 15 | 4 | 28 | 4 |
Total | 130 | 42 | 243 | 84 |
Production Expense | ||||
Lease Operating Expense | 132 | 124 | 287 | 263 |
Production and Ad Valorem Taxes | 50 | 32 | 104 | 73 |
Gathering, Transportation and Processing Expense | 100 | 121 | 195 | 240 |
Total | 292 | 283 | 613 | 586 |
Exploration Expense | ||||
Leasehold Impairment and Amortization | 0 | 0 | 0 | 18 |
Seismic, Geological and Geophysical | 2 | 8 | 13 | 13 |
Staff Expense | 13 | 16 | 27 | 29 |
Other | 14 | 6 | 24 | 12 |
Total | 29 | 30 | 64 | 72 |
Other Operating Expense, Net | ||||
Marketing Expense | 7 | 14 | 12 | 33 |
Purchased Oil and Gas | 71 | 0 | 128 | 0 |
Clayton Williams Energy Acquisition Expenses | 0 | 90 | 0 | 94 |
Other, Net | (4) | 14 | 4 | 20 |
Total | 74 | 118 | 144 | 147 |
Other Non-Operating Expense (Income), Net | ||||
Loss on Investment in Tamar Petroleum Ltd., Net | 11 | 0 | 26 | 0 |
Other | 0 | (5) | (2) | (6) |
Total | 11 | (5) | 24 | (6) |
Loss from change in fair value | 11 | 40 | ||
Dividend income | 14 | |||
Saddle Butte | ||||
Other Operating Expense, Net | ||||
Purchased Oil and Gas | 6 | 11 | ||
Other Royalty Expense | ||||
Production Expense | ||||
Other Royalty Expense | $ 10 | $ 6 | $ 27 | $ 10 |
Basis of Presentation - Balance
Basis of Presentation - Balance Sheet Information (Details) - USD ($) $ in Millions | 6 Months Ended | |||
Jun. 30, 2018 | Jun. 30, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | |
Accounts Receivable, Net | ||||
Commodity Sales | $ 460 | $ 455 | ||
Joint Interest Billings | 210 | 207 | ||
Other | 89 | 103 | ||
Allowance for Doubtful Accounts | (16) | (17) | ||
Total | 743 | 748 | ||
Other Current Assets | ||||
Inventories, Materials and Supplies | 46 | 66 | ||
Inventories, Crude Oil | 27 | 16 | ||
Commodity Derivative Assets | 29 | 2 | ||
Assets Held for Sale | 40 | 629 | ||
Restricted Cash | 0 | $ 0 | 38 | $ 30 |
Prepaid Expenses and Other Current Assets | 45 | 29 | ||
Total | 187 | 780 | ||
Other Noncurrent Assets | ||||
Equity Method Investments | 357 | 305 | ||
Customer-Related Intangible Assets | 326 | 0 | ||
Investment in Tamar Petroleum Ltd | 150 | 0 | ||
Mutual Fund Investments | 57 | 57 | ||
Net Deferred Income Tax Asset | 25 | 25 | ||
Other Assets, Noncurrent | 69 | 74 | ||
Total | 984 | 461 | ||
Other Current Liabilities | ||||
Production and Ad Valorem Taxes | 111 | 84 | ||
Commodity Derivative Liabilities | 250 | 58 | ||
Income Taxes Payable | 5 | 18 | ||
Asset Retirement Obligations | 92 | 51 | ||
Interest Payable | 64 | 67 | ||
Current Portion of Capital Lease Obligations | 47 | 61 | ||
Liabilities Associated with Assets Held for Sale | 0 | 55 | ||
Compensation and Benefits Payable | 66 | 98 | ||
Other Liabilities, Current | 110 | 86 | ||
Total | 745 | 578 | ||
Other Noncurrent Liabilities | ||||
Deferred Compensation Liabilities | 180 | 197 | ||
Asset Retirement Obligations | 543 | 824 | ||
Marcellus Shale Firm Transportation Commitment | 71 | 76 | ||
Production and Ad Valorem Taxes | 39 | 69 | ||
Commodity Derivative Liabilities | 85 | 15 | ||
Other Liabilities, Noncurrent | 77 | 64 | ||
Total | 995 | $ 1,245 | ||
Tamar and Dalit Fields | ||||
Other Noncurrent Liabilities | ||||
Ownership interest, percent | 7.50% | |||
Other Current Liabilities | ||||
Other Noncurrent Liabilities | ||||
Firm transportation liability | 12 | $ 14 | ||
CNX Midstream Partners | ||||
Other Noncurrent Assets | ||||
Equity Method Investments | 49 | |||
Saddle Butte | ||||
Other Noncurrent Assets | ||||
Customer-Related Intangible Assets | 340 | |||
Other Noncurrent Liabilities | ||||
Accumulated amortization | $ 14 |
Basis of Presentation - Compone
Basis of Presentation - Components of Cash, Cash Equivalents and Restricted Cash (Details) - USD ($) $ in Millions | Jun. 30, 2018 | Dec. 31, 2017 | Jun. 30, 2017 | Dec. 31, 2016 |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||||
Cash and Cash Equivalents | $ 621 | $ 675 | $ 540 | $ 1,180 |
Restricted Cash | 0 | 38 | 0 | 30 |
Cash, Cash Equivalents, and Restricted Cash | $ 621 | $ 713 | $ 540 | $ 1,210 |
Basis of Presentation - Perform
Basis of Presentation - Performance Obligation, Expected Timing (Details) $ in Millions | Jun. 30, 2018USD ($) |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-12-31 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Expected timing | 6 months |
Natural Gas Revenues | $ 107 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-12-31 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Expected timing | 2 years |
Natural Gas Revenues | $ 137 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-12-31 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Expected timing | 3 years |
Natural Gas Revenues | $ 413 |
Acquisitions and Divestitures -
Acquisitions and Divestitures - Narrative (Details) $ in Millions | Mar. 14, 2018USD ($)shares | Feb. 15, 2018USD ($)$ / bbl | Jan. 31, 2018USD ($) | Jun. 28, 2017USD ($)$ / MMBTU | Jun. 26, 2017USD ($)ashares | Apr. 24, 2017USD ($)shares | Apr. 03, 2017USD ($) | Jan. 31, 2018USD ($) | Jun. 30, 2018USD ($)shares | Mar. 31, 2018USD ($) | Jun. 30, 2017USD ($)MMcf / dMMBoewell | Jun. 30, 2018USD ($)shares | Jun. 30, 2017USD ($)MMBoewell | Apr. 11, 2018MMBoe | Feb. 01, 2018shares | Jan. 29, 2018 | Jan. 28, 2018 | Dec. 31, 2017USD ($)MMBoeshares |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||||
Long-Term Debt | $ 595 | |||||||||||||||||
Gain (loss) on divestiture | $ 78 | $ 0 | $ 666 | $ 0 | ||||||||||||||
Asset Impairments | $ 0 | 0 | $ 168 | 0 | ||||||||||||||
Undeveloped Leasehold Costs | 1,571 | |||||||||||||||||
Equity owned (units) | shares | 14,217,198 | 14,217,198 | 21,692,198 | |||||||||||||||
Proceeds from divestiture | $ 72 | 101 | ||||||||||||||||
Consideration | 2,488 | |||||||||||||||||
Cash consideration | 637 | 0 | 616 | |||||||||||||||
Fair value of common stock issued | 1,851 | |||||||||||||||||
Proceeds from sale | 443 | 0 | ||||||||||||||||
Proceeds from Sale of 7.5% Interest in Tamar Field | (484) | 0 | ||||||||||||||||
Intangible assets | $ 326 | 326 | $ 0 | |||||||||||||||
Goodwill | 1,291 | 1,402 | 1,402 | $ 1,310 | ||||||||||||||
Gain (loss) on disposition | 0 | $ (2,322) | 0 | (2,322) | ||||||||||||||
Natural gas production per day | MMcf / d | 393 | |||||||||||||||||
Proceeds from Noble Midstream Services Revolving Credit Facility | $ 610 | 195 | ||||||||||||||||
CONE Gathering LLC | ||||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||||
Gain (loss) on divestiture | $ 196 | $ 109 | ||||||||||||||||
Ownership | 50.00% | 50.00% | 22.30% | 22.30% | 34.10% | |||||||||||||
Shares sold (in shares) | shares | 7,500,000 | |||||||||||||||||
Proceeds from divestiture | $ 308 | $ 135 | ||||||||||||||||
Marcellus Shale | ||||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||||
Total transaction value | $ 1,200 | |||||||||||||||||
Assets | 3,400 | |||||||||||||||||
Proceeds from Sale of Oil and Gas Property and Equipment | 1,000 | $ 0 | $ 1,028 | |||||||||||||||
Adjustment to consideration | 100 | |||||||||||||||||
Adjustment to consideration, individual payment amounts | $ 33.3 | |||||||||||||||||
Minimum index price for contingent payments to be required (in usd per unit) | $ / MMBTU | 3.30 | |||||||||||||||||
Gain (loss) on disposition | $ 2,300 | |||||||||||||||||
Gain (loss) on sale | 1,500 | |||||||||||||||||
Exit costs | $ 41 | |||||||||||||||||
Period increase (decrease) | MMBoe | 241 | |||||||||||||||||
Proved developed reserves | MMBoe | 190 | 190 | ||||||||||||||||
Proved undeveloped reserves | MMBoe | 51 | 51 | ||||||||||||||||
Saddle Butte | ||||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||||
Consideration | $ 681 | |||||||||||||||||
Cash consideration | 663 | |||||||||||||||||
Liabilities assumed | 18 | 18 | ||||||||||||||||
Property, plant and equipment | 206 | 206 | ||||||||||||||||
Intangible assets | 340 | 340 | ||||||||||||||||
Goodwill | $ 111 | $ 111 | ||||||||||||||||
Clayton Williams Energy | ||||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||||
Long-Term Debt | $ 595 | $ 595 | ||||||||||||||||
Consideration | 2,500 | |||||||||||||||||
Cash consideration | $ 637 | |||||||||||||||||
Shares exchange in acquisition (shares) | shares | 56,000,000 | |||||||||||||||||
Fair value of common stock issued | $ 1,900 | |||||||||||||||||
Goodwill | $ 1,300 | |||||||||||||||||
Bolt-on acquisition in the Delaware Basin | ||||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||||
Productive oil wells | well | 7 | 7 | ||||||||||||||||
Payments to acquire oil and gas properties | $ 301 | |||||||||||||||||
Undeveloped Leasehold Costs | $ 246 | $ 246 | ||||||||||||||||
Number of productive wells | well | 4 | 4 | ||||||||||||||||
Noble Midstream Partners LP | Blanco River DevCo | ||||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||||
Percentage acquired | 15.00% | |||||||||||||||||
Step acquisition, percentage acquired | 40.00% | |||||||||||||||||
Noble Midstream Partners LP | Colorado River DevCo | ||||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||||
Consideration | $ 270 | |||||||||||||||||
Percentage acquired | 20.00% | |||||||||||||||||
Tamar and Dalit Fields | ||||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||||
Ownership interest | 25.00% | 32.50% | ||||||||||||||||
CNX Midstream Partners | ||||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||||
Equity owned (units) | shares | 14,200,000 | 14,200,000 | 21,700,000 | |||||||||||||||
Advantage Joint Venture | ||||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||||
Payments to acquire interest | $ 66.5 | |||||||||||||||||
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] | ||||||||||||||||||
Discount percent | 15.00% | |||||||||||||||||
Tax effect | $ 86 | |||||||||||||||||
Gain (loss) on divestiture | 376 | |||||||||||||||||
Gain attributable to change in fair value | $ 190 | |||||||||||||||||
Percentage of divestiture farmed out | 7.50% | |||||||||||||||||
Estimated capacity | MMBoe | 84 | |||||||||||||||||
Shares received in divestiture (in shares) | shares | 38,500,000 | |||||||||||||||||
Value of shares issued | $ 224 | |||||||||||||||||
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] | ||||||||||||||||||
Proceeds from sale | $ 60 | |||||||||||||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Other Divestitures | ||||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||||
Total transaction value | $ 12 | $ 12 | ||||||||||||||||
Gain (loss) on divestiture | 4 | |||||||||||||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Gulf of Mexico Assets | ||||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||||
Total transaction value | $ 480 | |||||||||||||||||
Gain (loss) on divestiture | (19) | |||||||||||||||||
Asset Impairments | $ 168 | $ 168 | ||||||||||||||||
Proceeds from divestiture | $ 383 | |||||||||||||||||
Estimated capacity | MMBoe | 23 | |||||||||||||||||
Assets | $ 100 | |||||||||||||||||
Asset basis, price per barrel (in usd per barrel) | $ / bbl | 2 | |||||||||||||||||
Price benchmark (in usd per barrel) | $ / bbl | 63 | |||||||||||||||||
Greenfield Midstream | Saddle Butte | ||||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||||
Cash consideration | $ 343 | |||||||||||||||||
Leaseholds and Leasehold Improvements | Marcellus Shale | ||||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||||
Assets | $ 883 | |||||||||||||||||
Corporate Joint Venture | Advantage Pipeline | ||||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||||
Ownership | 5000.00% | |||||||||||||||||
Consideration | $ 133 | |||||||||||||||||
Subsidiaries | Blanco River And Colorado River DevCos | ||||||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||||||
Consideration | $ 270 | |||||||||||||||||
Cash consideration | $ 245 | |||||||||||||||||
Shares exchange in acquisition (shares) | shares | 562,430 | |||||||||||||||||
Gas and oil area developed | a | 111,000 | |||||||||||||||||
Proceeds from issuance | $ 138 | |||||||||||||||||
Proceeds from Noble Midstream Services Revolving Credit Facility | $ 90 |
Acquisitions and Divestitures37
Acquisitions and Divestitures - Pro Forma Information (Details) - Clayton Williams Energy - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Business Acquisition [Line Items] | ||||
Revenues | $ 1,230 | $ 1,070 | $ 2,516 | $ 2,141 |
Net Income (Loss) and Comprehensive Income (Loss) Attributable to Noble Energy | $ 23 | $ 1,354 | $ (531) | $ 1,324 |
Net Income (Loss) Attributable to Noble Energy per Common Share | ||||
Basic (in usd per share) | $ (0.05) | $ (2.77) | $ 1.09 | $ (2.71) |
Diluted (in usd per share) | $ (0.05) | $ (2.77) | $ 1.09 | $ (2.71) |
Acquisitions and Divestitures38
Acquisitions and Divestitures - Consideration Transferred and Purchase Price Allocation (Details) - USD ($) $ in Millions | Apr. 24, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | Dec. 31, 2017 |
Business Acquisition [Line Items] | ||||
Fair Value of Common Stock Issued | $ 1,851 | |||
Plus: Cash Consideration Paid to Clayton Williams Energy Stockholders | 637 | $ 0 | $ 616 | |
Total Purchase Price | 2,488 | |||
Plus Liabilities Assumed by Noble Energy: | ||||
Accounts Payable | 99 | |||
Other Current Liabilities | 38 | |||
Long-Term Deferred Tax Liability | 515 | |||
Long-Term Debt | 595 | |||
Asset Retirement Obligations | 63 | |||
Total Purchase Price Plus Liabilities Assumed | 3,798 | |||
Cash and Cash Equivalents | 21 | |||
Other Current Assets | 70 | |||
Oil and Gas Properties: | ||||
Proved Reserves | 722 | |||
Undeveloped Leasehold Costs | 1,571 | |||
Gathering and Processing Assets | 48 | |||
Asset Retirement Costs | 63 | |||
Other Noncurrent Assets | 12 | |||
Goodwill | 1,291 | $ 1,402 | $ 1,310 | |
Total Asset Value | $ 3,798 |
Derivative Instruments and He39
Derivative Instruments and Hedging Activities - Summary of Outstanding Derivative Contracts (Details) | Jun. 30, 2018bbl / dMMBTU / d$ / bbl$ / MMBTU |
Crude Oil Contract | NYMEX WTI - Swaps 2018 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 66,000 |
Crude Oil Contract | NYMEX WTI - Collars 2018 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 18,000 |
Crude Oil Contract | NYMEX WTI - Three-Way Collars 2018 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 10,000 |
Crude Oil Contract | Dated Brent - Three-Way Collars 2018 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 3,000 |
Crude Oil Contract | ICE Brent - Swaps 2018 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 2,000 |
Crude Oil Contract | ICE Brent - Collars 2018 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 2,000 |
Crude Oil Contract | ICE Brent - Three-Way Collars 2018 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 5,000 |
Crude Oil Contract | Basis Swaps 2018 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 20,000 |
Weighted Average Differential ($ per bbl) | (2.30) |
Crude Oil Contract | NYMEX WTI - Swaps 2019 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 44,000 |
Crude Oil Contract | NYMEX WTI - Three-Way Collars 2019 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 6,000 |
Crude Oil Contract | ICE Brent - Swaps 2019 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 5,000 |
Weighted Average Fixed Price ($ per bbl) | 57 |
Crude Oil Contract | ICE Brent - Three-Way Collars 2019 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 3,000 |
Crude Oil Contract | Basis Swaps 2019 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 27,000 |
Weighted Average Differential ($ per bbl) | (3.23) |
Crude Oil Contract | NYMEX WTI - Swaption 2020 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 5,000 |
Crude Oil Contract | Basis Swaps 2020 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 15,000 |
Weighted Average Differential ($ per bbl) | (5.01) |
Natural Gas Contract | NYMEX WTI - Swaption 2020 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | MMBTU / d | 120,000 |
Weighted Average Fixed Price ($ per bbl) | $ / MMBTU | 0 |
Weighted Average Short Put Price ($ per bbl) | $ / MMBTU | 2.50 |
Weighted Average Floor Price ($ per bbl) | $ / MMBTU | 2.88 |
Weighted Average Ceiling Price ($ per bbl) | $ / MMBTU | 3.65 |
Swaps | Crude Oil Contract | NYMEX WTI - Swaps 2018 | |
Derivative [Line Items] | |
Weighted Average Fixed Price ($ per bbl) | 60.30 |
Swaps | Crude Oil Contract | ICE Brent - Swaps 2018 | |
Derivative [Line Items] | |
Weighted Average Fixed Price ($ per bbl) | 59 |
Swaps | Crude Oil Contract | NYMEX WTI - Swaps 2019 | |
Derivative [Line Items] | |
Weighted Average Fixed Price ($ per bbl) | 58.37 |
Swaps | Crude Oil Contract | NYMEX WTI - Swaption 2020 | |
Derivative [Line Items] | |
Weighted Average Fixed Price ($ per bbl) | 61.79 |
Collars | Crude Oil Contract | NYMEX WTI - Collars 2018 | |
Derivative [Line Items] | |
Weighted Average Floor Price ($ per bbl) | 50.42 |
Weighted Average Ceiling Price ($ per bbl) | 58.82 |
Collars | Crude Oil Contract | NYMEX WTI - Three-Way Collars 2018 | |
Derivative [Line Items] | |
Weighted Average Short Put Price ($ per bbl) | 45.50 |
Weighted Average Floor Price ($ per bbl) | 52.50 |
Weighted Average Ceiling Price ($ per bbl) | 69.09 |
Collars | Crude Oil Contract | Dated Brent - Three-Way Collars 2018 | |
Derivative [Line Items] | |
Weighted Average Short Put Price ($ per bbl) | 40 |
Weighted Average Floor Price ($ per bbl) | 50 |
Weighted Average Ceiling Price ($ per bbl) | 70.41 |
Collars | Crude Oil Contract | ICE Brent - Collars 2018 | |
Derivative [Line Items] | |
Weighted Average Floor Price ($ per bbl) | 50 |
Weighted Average Ceiling Price ($ per bbl) | 55.25 |
Collars | Crude Oil Contract | ICE Brent - Three-Way Collars 2018 | |
Derivative [Line Items] | |
Weighted Average Short Put Price ($ per bbl) | 43 |
Weighted Average Floor Price ($ per bbl) | 50 |
Weighted Average Ceiling Price ($ per bbl) | 59.50 |
Collars | Crude Oil Contract | NYMEX WTI - Three-Way Collars 2019 | |
Derivative [Line Items] | |
Weighted Average Short Put Price ($ per bbl) | 50 |
Weighted Average Floor Price ($ per bbl) | 60 |
Weighted Average Ceiling Price ($ per bbl) | 72.75 |
Collars | Crude Oil Contract | ICE Brent - Three-Way Collars 2019 | |
Derivative [Line Items] | |
Weighted Average Short Put Price ($ per bbl) | 43 |
Weighted Average Floor Price ($ per bbl) | 50 |
Weighted Average Ceiling Price ($ per bbl) | 64.07 |
Derivative Instruments and He40
Derivative Instruments and Hedging Activities - Fair Value Amounts and (Gain) Loss on Commodity Derivative Instruments (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | Dec. 31, 2017 | |
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value | $ 29 | $ 29 | $ 2 | ||
Derivative Liability, Fair Value | 335 | 335 | 73 | ||
Total Cash Paid (Received) in Settlement of Commodity Derivative Instruments | 65 | $ (11) | 93 | $ (14) | |
Total Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments | 184 | (46) | 235 | (153) | |
Total Loss (Gain) on Commodity Derivative Instruments | 249 | (57) | 328 | (167) | |
Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value | 29 | 29 | 2 | ||
Current Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value | 250 | 250 | 58 | ||
Noncurrent Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value | 0 | 0 | 0 | ||
Noncurrent Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value | 85 | 85 | $ 15 | ||
Crude Oil | |||||
Derivatives, Fair Value [Line Items] | |||||
Total Cash Paid (Received) in Settlement of Commodity Derivative Instruments | 66 | (11) | 96 | (16) | |
Total Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments | 181 | (28) | 231 | (91) | |
Total Loss (Gain) on Commodity Derivative Instruments | 247 | (39) | 327 | (107) | |
Natural Gas | |||||
Derivatives, Fair Value [Line Items] | |||||
Total Cash Paid (Received) in Settlement of Commodity Derivative Instruments | (1) | 0 | (3) | 2 | |
Total Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments | 3 | (18) | 4 | (62) | |
Total Loss (Gain) on Commodity Derivative Instruments | $ 2 | $ (18) | $ 1 | $ (60) |
Debt - Summary of Debt (Details
Debt - Summary of Debt (Details) - USD ($) $ in Millions | Jun. 30, 2018 | Dec. 31, 2017 |
Debt Instrument [Line Items] | ||
Total | $ 6,663 | $ 6,859 |
Unamortized Discount | (23) | (24) |
Unamortized Premium | 0 | 12 |
Unamortized Debt Issuance Costs | (38) | (40) |
Total Debt, Net of Unamortized Discount, Premium and Debt Issuance Costs | 6,602 | 6,807 |
Capital Lease Obligations | (47) | (61) |
Long-Term Debt Due After One Year | 6,555 | 6,746 |
Revolving Credit Facility, due March 9, 2023 | ||
Debt Instrument [Line Items] | ||
Debt | $ 0 | $ 230 |
Interest Rate | 0.00% | 2.27% |
Noble Midstream Services Revolving Credit Facility, due March 9, 2023 | ||
Debt Instrument [Line Items] | ||
Debt | $ 530 | $ 85 |
Interest Rate | 3.25% | 2.75% |
Leviathan Term Loan Facility, due February 23, 2025 | ||
Debt Instrument [Line Items] | ||
Debt | $ 0 | $ 0 |
Interest Rate | 0.00% | 0.00% |
Senior Notes, due May 1, 2021 | ||
Debt Instrument [Line Items] | ||
Debt | $ 0 | $ 379 |
Interest Rate | 0.00% | 5.63% |
Senior Notes, due December 15, 2021 | ||
Debt Instrument [Line Items] | ||
Debt | $ 1,000 | $ 1,000 |
Interest Rate | 4.15% | 4.15% |
Senior Notes, due October 15, 2023 | ||
Debt Instrument [Line Items] | ||
Debt | $ 100 | $ 100 |
Interest Rate | 7.25% | 7.25% |
Senior Notes, due November 15, 2024 | ||
Debt Instrument [Line Items] | ||
Debt | $ 650 | $ 650 |
Interest Rate | 3.90% | 3.90% |
Senior Notes, due April 1, 2027 | ||
Debt Instrument [Line Items] | ||
Debt | $ 250 | $ 250 |
Interest Rate | 8.00% | 8.00% |
Senior Notes, due January 15, 2028 | ||
Debt Instrument [Line Items] | ||
Debt | $ 600 | $ 600 |
Interest Rate | 3.85% | 3.85% |
Senior Notes, due March 1, 2041 | ||
Debt Instrument [Line Items] | ||
Debt | $ 850 | $ 850 |
Interest Rate | 6.00% | 6.00% |
Senior Notes, due November 15, 2043 | ||
Debt Instrument [Line Items] | ||
Debt | $ 1,000 | $ 1,000 |
Interest Rate | 5.25% | 5.25% |
Senior Notes, due November 15, 2044 | ||
Debt Instrument [Line Items] | ||
Debt | $ 850 | $ 850 |
Interest Rate | 5.05% | 5.05% |
Senior Notes, due August 15, 2047 | ||
Debt Instrument [Line Items] | ||
Debt | $ 500 | $ 500 |
Interest Rate | 4.95% | 4.95% |
Other Senior Notes and Debentures | ||
Debt Instrument [Line Items] | ||
Debt | $ 92 | $ 92 |
Interest Rate | 7.13% | 7.13% |
Capital Lease Obligations | ||
Debt Instrument [Line Items] | ||
Interest Rate | 0.00% | 0.00% |
Capital Lease Obligations | $ 241 | $ 273 |
Senior Notes, due June 1, 2024 | ||
Debt Instrument [Line Items] | ||
Debt | 8 | |
Senior Debentures due August 1, 2097 | ||
Debt Instrument [Line Items] | ||
Debt | $ 84 |
Debt - Narrative (Details)
Debt - Narrative (Details) - USD ($) | Jul. 31, 2018 | May 31, 2018 | Jun. 30, 2018 | Jun. 30, 2017 | Dec. 31, 2017 | Feb. 24, 2017 |
Debt Instrument [Line Items] | ||||||
Repayment of Senior Notes | $ 384,000,000 | $ 0 | ||||
Unamortized Premium | 0 | $ 12,000,000 | ||||
Revolving Credit Facility, due March 9, 2023 | ||||||
Debt Instrument [Line Items] | ||||||
Maximum borrowing capacity | 4,000,000,000 | |||||
Debt | 0 | 230,000,000 | ||||
Noble Midstream Services Revolving Credit Facility, due March 9, 2023 | ||||||
Debt Instrument [Line Items] | ||||||
Debt | 530,000,000 | 85,000,000 | ||||
Leviathan Term Loan Facility, due February 23, 2025 | ||||||
Debt Instrument [Line Items] | ||||||
Debt | 0 | 0 | ||||
Senior Notes, due May 1, 2021 | ||||||
Debt Instrument [Line Items] | ||||||
Debt | 0 | 379,000,000 | ||||
Repayment of Senior Notes | $ 395,000,000 | |||||
Senior Notes | Senior Notes, due May 1, 2021 | ||||||
Debt Instrument [Line Items] | ||||||
Early call of debt | 379,000,000 | |||||
Unamortized Premium | 10,000,000 | |||||
Interest accrued | 11,000,000 | |||||
Call premium | 5,000,000 | |||||
Gain on early redemption | $ 5,000,000 | |||||
Line of Credit | ||||||
Debt Instrument [Line Items] | ||||||
Debt maturity, 2021 | 1,000,000,000 | |||||
Noble Midstream | Noble Midstream Services Revolving Credit Facility, due March 9, 2023 | ||||||
Debt Instrument [Line Items] | ||||||
Maximum borrowing capacity | 500,000,000 | |||||
Noble Midstream | Line of Credit | ||||||
Debt Instrument [Line Items] | ||||||
Maximum borrowing capacity | $ 800,000,000 | $ 350,000,000 | ||||
Noble Midstream | Line of Credit | Federal Funds Effective Swap Rate | ||||||
Debt Instrument [Line Items] | ||||||
Facility fee and interest rates | 0.50% | |||||
Noble Midstream | Line of Credit | London Interbank Offered Rate (LIBOR) | ||||||
Debt Instrument [Line Items] | ||||||
Facility fee and interest rates | 1.00% | |||||
Line of Credit | Leviathan Term Loan Facility, due February 23, 2025 | ||||||
Debt Instrument [Line Items] | ||||||
Maximum borrowing capacity | $ 1,000,000,000 | |||||
Credit facility draw | $ 625,000,000 | |||||
Maximum final balloon payment allowable | 35.00% | |||||
Commitment fee | 1.00% | |||||
Line of Credit | Leviathan Term Loan Facility, due February 23, 2025 | LIBOR Prior to Production Startup | ||||||
Debt Instrument [Line Items] | ||||||
Facility fee and interest rates | 3.50% | |||||
Line of Credit | Leviathan Term Loan Facility, due February 23, 2025 | LIBOR After Startup Prior to Two Years Before Maturity | ||||||
Debt Instrument [Line Items] | ||||||
Facility fee and interest rates | 3.25% | |||||
Line of Credit | Leviathan Term Loan Facility, due February 23, 2025 | LIBOR Last Two Years Until Maturity | ||||||
Debt Instrument [Line Items] | ||||||
Facility fee and interest rates | 3.75% | |||||
Minimum | Revolving Credit Facility, due March 9, 2023 | ||||||
Debt Instrument [Line Items] | ||||||
Facility fee and interest rates | 0.10% | |||||
Minimum | Revolving Credit Facility, due March 9, 2023 | Eurodollar [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Facility fee and interest rates | 0.90% | |||||
Maximum | Revolving Credit Facility, due March 9, 2023 | ||||||
Debt Instrument [Line Items] | ||||||
Facility fee and interest rates | 0.25% | |||||
Maximum | Revolving Credit Facility, due March 9, 2023 | Eurodollar [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Facility fee and interest rates | 1.50% | |||||
Subsequent Event | Line of Credit | Noble Midstream | ||||||
Debt Instrument [Line Items] | ||||||
Maximum borrowing capacity | $ 500,000,000 | |||||
Subsequent Event | Minimum | Line of Credit | Noble Midstream | Eurodollar [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Facility fee and interest rates | 1.00% | |||||
Subsequent Event | Minimum | Line of Credit | Noble Midstream | Base Rate [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Facility fee and interest rates | 0.00% | |||||
Subsequent Event | Maximum | Line of Credit | Noble Midstream | Eurodollar [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Facility fee and interest rates | 1.50% | |||||
Subsequent Event | Maximum | Line of Credit | Noble Midstream | Base Rate [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Facility fee and interest rates | 0.50% |
Fair Value Measurements and D43
Fair Value Measurements and Disclosures - Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($) $ / shares in Units, $ in Millions | Jun. 30, 2018 | Dec. 31, 2017 |
Financial Liabilities Fair Value Disclosure [Abstract] | ||
Equity owned (units) | 14,217,198 | 21,692,198 |
Tamar Petroleum Ltd | ||
Financial Liabilities Fair Value Disclosure [Abstract] | ||
Equity owned (units) | 38,495,575 | |
Share price (in usd per share) | $ 4.60 | |
Fair Value, Measurements, Recurring | ||
Financial Assets: | ||
Investments | $ 57 | |
Commodity Derivative Instruments | $ 29 | 2 |
Financial Liabilities Fair Value Disclosure [Abstract] | ||
Commodity Derivative Instruments | (335) | (73) |
Portion of Deferred Compensation Liability Measured at Fair Value | (73) | (71) |
Stock Based Compensation Liability Measured at Fair Value | (12) | (10) |
Fair Value, Measurements, Recurring | Quoted Prices in Active Markets (Level 1) | ||
Financial Assets: | ||
Investments | 57 | |
Commodity Derivative Instruments | 0 | 0 |
Financial Liabilities Fair Value Disclosure [Abstract] | ||
Commodity Derivative Instruments | 0 | 0 |
Portion of Deferred Compensation Liability Measured at Fair Value | (73) | (71) |
Stock Based Compensation Liability Measured at Fair Value | (12) | (10) |
Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | ||
Financial Assets: | ||
Investments | 0 | |
Commodity Derivative Instruments | 72 | 7 |
Financial Liabilities Fair Value Disclosure [Abstract] | ||
Commodity Derivative Instruments | (378) | (78) |
Portion of Deferred Compensation Liability Measured at Fair Value | 0 | 0 |
Stock Based Compensation Liability Measured at Fair Value | 0 | 0 |
Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | ||
Financial Assets: | ||
Investments | 0 | |
Commodity Derivative Instruments | 0 | 0 |
Financial Liabilities Fair Value Disclosure [Abstract] | ||
Commodity Derivative Instruments | 0 | 0 |
Portion of Deferred Compensation Liability Measured at Fair Value | 0 | 0 |
Stock Based Compensation Liability Measured at Fair Value | 0 | 0 |
Fair Value, Measurements, Recurring | Scenario, Adjustment | ||
Financial Assets: | ||
Investments | 0 | |
Commodity Derivative Instruments | (43) | (5) |
Financial Liabilities Fair Value Disclosure [Abstract] | ||
Commodity Derivative Instruments | 43 | 5 |
Portion of Deferred Compensation Liability Measured at Fair Value | 0 | 0 |
Stock Based Compensation Liability Measured at Fair Value | 0 | $ 0 |
Mutual Fund Investments | Fair Value, Measurements, Recurring | ||
Financial Assets: | ||
Investments | 57 | |
Mutual Fund Investments | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets (Level 1) | ||
Financial Assets: | ||
Investments | 57 | |
Mutual Fund Investments | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | ||
Financial Assets: | ||
Investments | 0 | |
Mutual Fund Investments | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | ||
Financial Assets: | ||
Investments | 0 | |
Mutual Fund Investments | Fair Value, Measurements, Recurring | Scenario, Adjustment | ||
Financial Assets: | ||
Investments | 0 | |
Investment in Tamar Petroleum Ltd. (38,495,575 Shares) (5) | Fair Value, Measurements, Recurring | ||
Financial Assets: | ||
Investments | 150 | |
Investment in Tamar Petroleum Ltd. (38,495,575 Shares) (5) | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets (Level 1) | ||
Financial Assets: | ||
Investments | 0 | |
Investment in Tamar Petroleum Ltd. (38,495,575 Shares) (5) | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | ||
Financial Assets: | ||
Investments | 150 | |
Investment in Tamar Petroleum Ltd. (38,495,575 Shares) (5) | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | ||
Financial Assets: | ||
Investments | 0 | |
Investment in Tamar Petroleum Ltd. (38,495,575 Shares) (5) | Fair Value, Measurements, Recurring | Scenario, Adjustment | ||
Financial Assets: | ||
Investments | $ 0 |
Fair Value Measurements and D44
Fair Value Measurements and Disclosures - Narrative (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||||
Jun. 30, 2018 | Mar. 31, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | Mar. 14, 2018 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||
Asset Impairments | $ 0 | $ 0 | $ 168 | $ 0 | ||
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Tamar and Dalit Fields | ||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||
Discount percent | 15.00% | |||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Gulf of Mexico Assets | ||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||
Asset Impairments | $ 168 | $ 168 |
Fair Value Measurements and D45
Fair Value Measurements and Disclosures - Fair Value of Equity Method Investments (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Jun. 30, 2018 | Dec. 31, 2017 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Equity owned (units) | 14,217,198 | 21,692,198 |
Carrying Amount | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investment in CNX Midstream Partners (14,217,198 Common Units and 21,692,198 Common Units, respectively) (1) | $ 49 | $ 70,000 |
Fair Value | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Investment in CNX Midstream Partners (14,217,198 Common Units and 21,692,198 Common Units, respectively) (1) | $ 276,000 | $ 364,000 |
CONE Gathering LLC | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Shares sold (in shares) | 7,500,000 |
Fair Value Measurements and D46
Fair Value Measurements and Disclosures - Fair Value of Debt (Details) - USD ($) $ in Millions | Jun. 30, 2018 | Dec. 31, 2017 |
Carrying Amount | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term Debt, Net | $ 6,422 | $ 6,586 |
Fair Value | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term Debt, Net | $ 6,591 | $ 7,142 |
Capitalized Exploratory Well 47
Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs - Narrative (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended |
Mar. 31, 2018 | Jun. 30, 2018 | |
Projects with Exploratory Well Costs Capitalized for More than One Year Since The Commencement of Drilling [Line Items] | ||
Capitalized undeveloped leasehold cost | $ 2,600 | |
Clayton Williams Energy | ||
Projects with Exploratory Well Costs Capitalized for More than One Year Since The Commencement of Drilling [Line Items] | ||
Capitalized undeveloped leasehold cost | 1,600 | |
Onshore US | ||
Projects with Exploratory Well Costs Capitalized for More than One Year Since The Commencement of Drilling [Line Items] | ||
Capitalized undeveloped leasehold cost | 859 | |
Eagle Ford | ||
Projects with Exploratory Well Costs Capitalized for More than One Year Since The Commencement of Drilling [Line Items] | ||
Capitalized undeveloped leasehold cost | 129 | |
Other Int'l | ||
Projects with Exploratory Well Costs Capitalized for More than One Year Since The Commencement of Drilling [Line Items] | ||
Capitalized undeveloped leasehold cost | 53 | |
Held for Sale | Delaware Basin | ||
Projects with Exploratory Well Costs Capitalized for More than One Year Since The Commencement of Drilling [Line Items] | ||
Capitalized undeveloped leasehold cost | 247 | |
Held for Sale | Eagle Ford Shale | ||
Projects with Exploratory Well Costs Capitalized for More than One Year Since The Commencement of Drilling [Line Items] | ||
Capitalized undeveloped leasehold cost | $ 20 | |
Held for Sale | Gulf of Mexico | ||
Projects with Exploratory Well Costs Capitalized for More than One Year Since The Commencement of Drilling [Line Items] | ||
Capitalized undeveloped leasehold cost | $ 43 |
Capitalized Exploratory Well 48
Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs - Changes in Capitalized Exploratory Well Costs (Details) $ in Millions | 6 Months Ended |
Jun. 30, 2018USD ($) | |
Capitalized Exploratory Well Costs [Roll Forward] | |
Capitalized Exploratory Well Costs, Beginning of Period | $ 520 |
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves | 4 |
Reclassified to Assets Held for Sale | (167) |
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves | (1) |
Capitalized Exploratory Well Costs Charged to Expense | 0 |
Capitalized Exploratory Well Costs, End of Period | $ 356 |
Capitalized Exploratory Well 49
Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs - Aging of Capitalized Exploratory Well Costs (Details) $ in Millions | Jun. 30, 2018USD ($)project | Dec. 31, 2017USD ($)project |
Extractive Industries [Abstract] | ||
Exploratory Well Costs Capitalized for a Period of One Year or Less | $ 8 | $ 10 |
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 348 | 510 |
Balance at End of Period | $ 356 | $ 520 |
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling | project | 7 | 8 |
Asset Retirement Obligations -
Asset Retirement Obligations - ARO Activity (Details) - USD ($) $ in Millions | 6 Months Ended | |
Jun. 30, 2018 | Jun. 30, 2017 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Asset Retirement Obligations, Beginning Balance | $ 875 | $ 935 |
Liabilities Incurred | 14 | 82 |
Liabilities Settled | (261) | (32) |
Revisions of Estimates | (10) | (15) |
Accretion Expense | 17 | 23 |
Asset Retirement Obligations, Ending Balance | $ 635 | $ 993 |
Asset Retirement Obligations 51
Asset Retirement Obligations - Narrative (Details) - USD ($) $ in Millions | 6 Months Ended | |
Jun. 30, 2018 | Jun. 30, 2017 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Liabilities Settled | $ 261 | $ 32 |
Revisions of estimates | 10 | 15 |
Liabilities Incurred | 14 | 82 |
Gulf of Mexico Assets | Disposal Group, Disposed of by Sale, Not Discontinued Operations | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Reclassified Liabilities | 216 | |
Liabilities Settled | 44 | |
North Sea | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Revisions of estimates | 11 | |
Eastern Mediterranean | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Revisions of estimates | 6 | |
Onshore US | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Revisions of estimates | $ (7) | |
Marcellus Shale | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Revisions of estimates | 12 | |
US On Shore and Gulf Of Mexico | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Revisions of estimates | 30 | |
West Africa | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Revisions of estimates | 15 | |
Clayton Williams Energy | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Liabilities Incurred | 59 | |
Onshore US | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Liabilities Incurred | $ 23 |
Income Per Share Attributable52
Income Per Share Attributable to Noble Energy (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Earnings Per Share [Abstract] | ||||
Net Loss and Comprehensive Loss Attributable to Noble Energy | $ (23) | $ (1,512) | $ 531 | $ (1,476) |
Weighted Average, Number of Shares Outstanding, Basic (in shares) | 484 | 472 | 485 | 452 |
Incremental Shares from Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust (in shares) | 0 | 0 | 2 | 0 |
Weighted Average, Number of Shares Outstanding, Diluted (in shares) | 484 | 472 | 487 | 452 |
Loss Per Share, Basic ($ per share) | $ (0.05) | $ (3.20) | $ 1.09 | $ (3.27) |
Loss Per Share, Diluted ($ per share) | $ (0.05) | $ (3.20) | $ 1.09 | $ (3.27) |
Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above (in shares) | 14 | 16 | 14 | 15 |
Income Taxes - Components of In
Income Taxes - Components of Income Tax (Benefit) (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Income Tax Disclosure [Abstract] | ||||
Current | $ 23 | $ 37 | $ 149 | $ 49 |
Deferred | (7) | (873) | (164) | (873) |
Total Income Tax Expense (Benefit) | $ (16) | $ 836 | $ 15 | $ 824 |
Effective Tax Rate | 160.00% | 35.80% | (2.70%) | 36.20% |
Income Taxes - Narrative (Detai
Income Taxes - Narrative (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | Mar. 14, 2018 | Dec. 31, 2017 | |
Operating Loss Carryforwards [Line Items] | ||||||
Toll tax accrued | $ 16 | $ 16 | $ 268 | |||
Discrete tax benefit | $ (16) | $ 836 | 15 | $ 824 | ||
One-time Deemed Repatriation | ||||||
Operating Loss Carryforwards [Line Items] | ||||||
Tax benefit from foreign tax credits | $ 252 | |||||
Installment period | 8 years | |||||
Expense related to tax rate change adjustment | $ 107 | |||||
Discrete tax benefit | $ 145 | |||||
Tamar and Dalit Fields | Disposal Group, Disposed of by Sale, Not Discontinued Operations | ||||||
Operating Loss Carryforwards [Line Items] | ||||||
Percentage of divestiture farmed out | 7.50% |
Segment Information - Operating
Segment Information - Operating Results by Segment (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Segment Reporting Information [Line Items] | ||||
Total Crude Oil, NGL and Natural Gas Sales | $ 1,100 | $ 1,017 | $ 2,273 | $ 2,011 |
Income from Equity Method Investees and Other | 64 | 42 | 124 | 84 |
Sales of Purchased Oil and Gas | 66 | 0 | 119 | 0 |
Intersegment Revenues | 0 | 0 | 0 | 0 |
Total | 1,230 | 1,059 | 2,516 | 2,095 |
Lease Operating Expense | 132 | 124 | 287 | 263 |
Production and Ad Valorem Taxes | 50 | 32 | 104 | 73 |
Gathering, Transportation and Processing Expense | 100 | 121 | 195 | 240 |
Total | 292 | 283 | 613 | 586 |
DD&A | 465 | 503 | 933 | 1,031 |
Gain on Divestitures, Net | (78) | 0 | (666) | 0 |
Asset Impairments | 0 | 0 | 168 | 0 |
Purchased Oil and Gas | 71 | 0 | 128 | 0 |
Loss on Marcellus Shale Upstream Divestiture | 2,322 | 2,322 | ||
Loss (Gain) on Commodity Derivative Instruments | 249 | (57) | 328 | (167) |
Income (Loss) Before Income Taxes | 10 | (2,334) | 553 | (2,275) |
Intersegment Eliminations | ||||
Segment Reporting Information [Line Items] | ||||
Total Crude Oil, NGL and Natural Gas Sales | 0 | 0 | 0 | 0 |
Income from Equity Method Investees and Other | 0 | 0 | 0 | 0 |
Sales of Purchased Oil and Gas | 0 | 0 | ||
Intersegment Revenues | (85) | (69) | (166) | (127) |
Total | (85) | (69) | (166) | (127) |
Lease Operating Expense | (6) | (5) | (6) | (2) |
Production and Ad Valorem Taxes | 0 | 0 | 0 | 0 |
Gathering, Transportation and Processing Expense | (55) | (38) | (108) | (72) |
Total | (61) | (43) | (114) | (74) |
DD&A | (4) | 0 | (8) | 0 |
Gain on Divestitures, Net | 0 | 0 | ||
Asset Impairments | 0 | |||
Purchased Oil and Gas | 0 | 0 | ||
Loss on Marcellus Shale Upstream Divestiture | 0 | 0 | ||
Loss (Gain) on Commodity Derivative Instruments | 0 | 0 | 0 | 0 |
Income (Loss) Before Income Taxes | (18) | (13) | (40) | (35) |
Corporate | ||||
Segment Reporting Information [Line Items] | ||||
Total Crude Oil, NGL and Natural Gas Sales | 0 | 0 | 0 | 0 |
Income from Equity Method Investees and Other | 0 | 0 | 0 | 0 |
Sales of Purchased Oil and Gas | 0 | 0 | ||
Intersegment Revenues | 0 | 0 | 0 | 0 |
Total | 0 | 0 | 0 | 0 |
Lease Operating Expense | 0 | 0 | 0 | 0 |
Production and Ad Valorem Taxes | 0 | 0 | 0 | 0 |
Gathering, Transportation and Processing Expense | 0 | 0 | 0 | 0 |
Total | 0 | 0 | 0 | 0 |
DD&A | 12 | 12 | 23 | 22 |
Gain on Divestitures, Net | 0 | 0 | ||
Asset Impairments | 0 | |||
Purchased Oil and Gas | 0 | 0 | ||
Loss on Marcellus Shale Upstream Divestiture | 0 | 0 | ||
Loss (Gain) on Commodity Derivative Instruments | 0 | 0 | 0 | 0 |
Income (Loss) Before Income Taxes | (154) | (234) | (328) | (430) |
United States | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Total Crude Oil, NGL and Natural Gas Sales | 870 | 780 | 1,818 | 1,550 |
Income from Equity Method Investees and Other | 0 | 0 | 0 | 0 |
Sales of Purchased Oil and Gas | 24 | 55 | ||
Intersegment Revenues | 0 | 0 | 0 | 0 |
Total | 894 | 780 | 1,873 | 1,550 |
Lease Operating Expense | 114 | 105 | 240 | 211 |
Production and Ad Valorem Taxes | 48 | 32 | 101 | 72 |
Gathering, Transportation and Processing Expense | 133 | 142 | 260 | 280 |
Total | 305 | 285 | 628 | 573 |
DD&A | 394 | 427 | 800 | 886 |
Gain on Divestitures, Net | 21 | 15 | ||
Asset Impairments | 168 | |||
Purchased Oil and Gas | 31 | 67 | ||
Loss on Marcellus Shale Upstream Divestiture | 2,322 | 2,322 | ||
Loss (Gain) on Commodity Derivative Instruments | 196 | (51) | 260 | (154) |
Income (Loss) Before Income Taxes | (90) | (2,319) | (127) | (2,251) |
United States | Noble Midstream | ||||
Segment Reporting Information [Line Items] | ||||
Total Crude Oil, NGL and Natural Gas Sales | 0 | 0 | 0 | 0 |
Income from Equity Method Investees and Other | 28 | 17 | 53 | 32 |
Sales of Purchased Oil and Gas | 42 | 64 | ||
Intersegment Revenues | 85 | 69 | 166 | 127 |
Total | 155 | 86 | 283 | 159 |
Lease Operating Expense | 0 | 0 | 0 | 0 |
Production and Ad Valorem Taxes | 2 | 0 | 3 | 1 |
Gathering, Transportation and Processing Expense | 22 | 17 | 43 | 32 |
Total | 24 | 17 | 46 | 33 |
DD&A | 22 | 5 | 38 | 10 |
Gain on Divestitures, Net | (109) | (305) | ||
Asset Impairments | 0 | |||
Purchased Oil and Gas | 40 | 61 | ||
Loss on Marcellus Shale Upstream Divestiture | 0 | 0 | ||
Loss (Gain) on Commodity Derivative Instruments | 0 | 0 | 0 | 0 |
Income (Loss) Before Income Taxes | 175 | 58 | 428 | 107 |
Eastern Mediterranean | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Total Crude Oil, NGL and Natural Gas Sales | 113 | 133 | 244 | 265 |
Income from Equity Method Investees and Other | 0 | 0 | 0 | 0 |
Sales of Purchased Oil and Gas | 0 | 0 | ||
Intersegment Revenues | 0 | 0 | 0 | 0 |
Total | 113 | 133 | 244 | 265 |
Lease Operating Expense | 5 | 6 | 12 | 14 |
Production and Ad Valorem Taxes | 0 | 0 | 0 | 0 |
Gathering, Transportation and Processing Expense | 0 | 0 | 0 | 0 |
Total | 5 | 6 | 12 | 14 |
DD&A | 15 | 19 | 28 | 37 |
Gain on Divestitures, Net | 10 | (376) | ||
Asset Impairments | 0 | |||
Purchased Oil and Gas | 0 | 0 | ||
Loss on Marcellus Shale Upstream Divestiture | 0 | 0 | ||
Loss (Gain) on Commodity Derivative Instruments | 0 | 0 | 0 | 0 |
Income (Loss) Before Income Taxes | 62 | 106 | 535 | 207 |
West Africa | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Total Crude Oil, NGL and Natural Gas Sales | 117 | 104 | 211 | 196 |
Income from Equity Method Investees and Other | 36 | 25 | 71 | 52 |
Sales of Purchased Oil and Gas | 0 | 0 | ||
Intersegment Revenues | 0 | 0 | 0 | 0 |
Total | 153 | 129 | 282 | 248 |
Lease Operating Expense | 19 | 18 | 41 | 40 |
Production and Ad Valorem Taxes | 0 | 0 | 0 | 0 |
Gathering, Transportation and Processing Expense | 0 | 0 | 0 | 0 |
Total | 19 | 18 | 41 | 40 |
DD&A | 26 | 39 | 52 | 74 |
Gain on Divestitures, Net | 0 | 0 | ||
Asset Impairments | 0 | |||
Purchased Oil and Gas | 0 | 0 | ||
Loss on Marcellus Shale Upstream Divestiture | 0 | 0 | ||
Loss (Gain) on Commodity Derivative Instruments | 53 | (6) | 68 | (13) |
Income (Loss) Before Income Taxes | 48 | 72 | 112 | 138 |
Other Int'l | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Total Crude Oil, NGL and Natural Gas Sales | 0 | 0 | 0 | 0 |
Income from Equity Method Investees and Other | 0 | 0 | 0 | 0 |
Sales of Purchased Oil and Gas | 0 | 0 | ||
Intersegment Revenues | 0 | 0 | 0 | 0 |
Total | 0 | 0 | 0 | 0 |
Lease Operating Expense | 0 | 0 | 0 | 0 |
Production and Ad Valorem Taxes | 0 | 0 | 0 | 0 |
Gathering, Transportation and Processing Expense | 0 | 0 | 0 | 0 |
Total | 0 | 0 | 0 | 0 |
DD&A | 0 | 1 | 0 | 2 |
Gain on Divestitures, Net | 0 | 0 | ||
Asset Impairments | 0 | |||
Purchased Oil and Gas | 0 | 0 | ||
Loss on Marcellus Shale Upstream Divestiture | 0 | 0 | ||
Loss (Gain) on Commodity Derivative Instruments | 0 | 0 | 0 | 0 |
Income (Loss) Before Income Taxes | (13) | (4) | (27) | (11) |
Crude Oil Sales | ||||
Segment Reporting Information [Line Items] | ||||
Total Crude Oil, NGL and Natural Gas Sales | 749 | 557 | 1,522 | 1,084 |
Crude Oil Sales | Intersegment Eliminations | ||||
Segment Reporting Information [Line Items] | ||||
Total Crude Oil, NGL and Natural Gas Sales | 0 | 0 | 0 | 0 |
Crude Oil Sales | Corporate | ||||
Segment Reporting Information [Line Items] | ||||
Total Crude Oil, NGL and Natural Gas Sales | 0 | 0 | 0 | 0 |
Crude Oil Sales | United States | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Total Crude Oil, NGL and Natural Gas Sales | 635 | 458 | 1,317 | 897 |
Crude Oil Sales | United States | Noble Midstream | ||||
Segment Reporting Information [Line Items] | ||||
Total Crude Oil, NGL and Natural Gas Sales | 0 | 0 | 0 | 0 |
Crude Oil Sales | Eastern Mediterranean | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Total Crude Oil, NGL and Natural Gas Sales | 2 | 1 | 4 | 2 |
Crude Oil Sales | West Africa | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Total Crude Oil, NGL and Natural Gas Sales | 112 | 98 | 201 | 185 |
Crude Oil Sales | Other Int'l | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Total Crude Oil, NGL and Natural Gas Sales | 0 | 0 | 0 | 0 |
NGL Sales | ||||
Segment Reporting Information [Line Items] | ||||
Total Crude Oil, NGL and Natural Gas Sales | 137 | 108 | 283 | 213 |
NGL Sales | Intersegment Eliminations | ||||
Segment Reporting Information [Line Items] | ||||
Total Crude Oil, NGL and Natural Gas Sales | 0 | 0 | 0 | 0 |
NGL Sales | Corporate | ||||
Segment Reporting Information [Line Items] | ||||
Total Crude Oil, NGL and Natural Gas Sales | 0 | 0 | 0 | 0 |
NGL Sales | United States | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Total Crude Oil, NGL and Natural Gas Sales | 137 | 108 | 283 | 213 |
NGL Sales | United States | Noble Midstream | ||||
Segment Reporting Information [Line Items] | ||||
Total Crude Oil, NGL and Natural Gas Sales | 0 | 0 | 0 | 0 |
NGL Sales | Eastern Mediterranean | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Total Crude Oil, NGL and Natural Gas Sales | 0 | 0 | 0 | 0 |
NGL Sales | West Africa | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Total Crude Oil, NGL and Natural Gas Sales | 0 | 0 | 0 | 0 |
NGL Sales | Other Int'l | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Total Crude Oil, NGL and Natural Gas Sales | 0 | 0 | 0 | 0 |
Natural Gas Sales | ||||
Segment Reporting Information [Line Items] | ||||
Total Crude Oil, NGL and Natural Gas Sales | 214 | 352 | 468 | 714 |
Natural Gas Sales | Intersegment Eliminations | ||||
Segment Reporting Information [Line Items] | ||||
Total Crude Oil, NGL and Natural Gas Sales | 0 | 0 | 0 | 0 |
Natural Gas Sales | Corporate | ||||
Segment Reporting Information [Line Items] | ||||
Total Crude Oil, NGL and Natural Gas Sales | 0 | 0 | 0 | 0 |
Natural Gas Sales | United States | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Total Crude Oil, NGL and Natural Gas Sales | 98 | 214 | 218 | 440 |
Natural Gas Sales | United States | Noble Midstream | ||||
Segment Reporting Information [Line Items] | ||||
Total Crude Oil, NGL and Natural Gas Sales | 0 | 0 | 0 | 0 |
Natural Gas Sales | Eastern Mediterranean | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Total Crude Oil, NGL and Natural Gas Sales | 111 | 132 | 240 | 263 |
Natural Gas Sales | West Africa | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Total Crude Oil, NGL and Natural Gas Sales | 5 | 6 | 10 | 11 |
Natural Gas Sales | Other Int'l | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Total Crude Oil, NGL and Natural Gas Sales | 0 | 0 | 0 | 0 |
Other Royalty Expense | ||||
Segment Reporting Information [Line Items] | ||||
Expense | 10 | 6 | 27 | 10 |
Other Royalty Expense | Intersegment Eliminations | ||||
Segment Reporting Information [Line Items] | ||||
Expense | 0 | 0 | 0 | 0 |
Other Royalty Expense | Corporate | ||||
Segment Reporting Information [Line Items] | ||||
Expense | 0 | 0 | 0 | 0 |
Other Royalty Expense | United States | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Expense | 10 | 6 | 27 | 10 |
Other Royalty Expense | United States | Noble Midstream | ||||
Segment Reporting Information [Line Items] | ||||
Expense | 0 | 0 | 0 | 0 |
Other Royalty Expense | Eastern Mediterranean | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Expense | 0 | 0 | 0 | 0 |
Other Royalty Expense | West Africa | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Expense | 0 | 0 | 0 | 0 |
Other Royalty Expense | Other Int'l | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Expense | $ 0 | $ 0 | $ 0 | $ 0 |
Segment Information - Assets an
Segment Information - Assets and Goodwill by Segment (Details) - USD ($) $ in Millions | Jun. 30, 2018 | Dec. 31, 2017 | Apr. 24, 2017 |
Segment Reporting Information [Line Items] | |||
Goodwill | $ 1,402 | $ 1,310 | $ 1,291 |
Assets, net of AHFS | 21,854 | 21,476 | |
Operating Segments | Eastern Mediterranean | |||
Segment Reporting Information [Line Items] | |||
Goodwill | 0 | 0 | |
Assets, net of AHFS | 2,996 | 2,846 | |
Operating Segments | West Africa | |||
Segment Reporting Information [Line Items] | |||
Goodwill | 0 | 0 | |
Assets, net of AHFS | 1,275 | 1,308 | |
Operating Segments | Other Int'l | |||
Segment Reporting Information [Line Items] | |||
Goodwill | 0 | 0 | |
Assets, net of AHFS | 62 | 114 | |
Operating Segments | United States | |||
Segment Reporting Information [Line Items] | |||
Goodwill | 1,291 | 1,310 | |
Assets, net of AHFS | 15,138 | 15,767 | |
Noble Midstream | United States | |||
Segment Reporting Information [Line Items] | |||
Goodwill | 111 | 0 | |
Assets, net of AHFS | 2,280 | 1,357 | |
Intersegment Eliminations | |||
Segment Reporting Information [Line Items] | |||
Goodwill | 0 | 0 | |
Assets, net of AHFS | (140) | (163) | |
Corporate | |||
Segment Reporting Information [Line Items] | |||
Goodwill | 0 | 0 | |
Assets, net of AHFS | $ 243 | $ 247 |
Commitments and Contingencies -
Commitments and Contingencies - Narrative (Details) $ in Millions | 6 Months Ended | 12 Months Ended | 24 Months Ended |
Jun. 30, 2018USD ($)MMBTU | Dec. 31, 2016USD ($) | Dec. 31, 2016USD ($) | |
Other Commitments [Line Items] | |||
Committed transportation volume per day (in MMBtu) | MMBTU | 450,000 | ||
Firm transportation liability | $ 83 | ||
Unutilized commitments expense | 3 | ||
Marcellus Shale Firm Transportation Agreement | |||
Other Commitments [Line Items] | |||
Commitment amount | 1,400 | ||
Consent Decree | |||
Other Commitments [Line Items] | |||
Civil penalty | $ 5 | $ 83 | |
Mitigation projects | 5 | ||
Supplemental environmental projects | $ 4 | ||
Minimum | Marcellus Shale Firm Transportation Agreement | |||
Other Commitments [Line Items] | |||
Term | 4 years | ||
Maximum | Marcellus Shale Firm Transportation Agreement | |||
Other Commitments [Line Items] | |||
Term | 15 years |