Cover Page
Cover Page | 6 Months Ended |
Jun. 30, 2019shares | |
Cover page. | |
Document Type | 10-Q |
Document Quarterly Report | true |
Document Period End Date | Jun. 30, 2019 |
Document Transition Report | false |
Entity File Number | 001-07964 |
Entity Registrant Name | NOBLE ENERGY, INC. |
Entity Incorporation, State or Country Code | DE |
Amendment Flag | false |
Entity Tax Identification Number | 73-0785597 |
Entity Address, Address Line One | 1001 Noble Energy Way |
Entity Address, City or Town | Houston, |
Entity Address, State or Province | TX |
Entity Address, Postal Zip Code | 77070 |
Title of 12(b) Security | Common Stock, $0.01 par value |
Trading Symbol | NBL |
Security Exchange Name | NYSE |
City Area Code | (281) |
Local Phone Number | 872-3100 |
Entity Central Index Key | 0000072207 |
Current Fiscal Year End Date | --12-31 |
Entity Current Reporting Status | Yes |
Entity Interactive Data Current | Yes |
Entity Filer Category | Large Accelerated Filer |
Entity Shell Company | false |
Entity Emerging Growth Company | false |
Entity Small Business | false |
Document Fiscal Year Focus | 2019 |
Document Fiscal Period Focus | Q2 |
Entity Common Stock, Shares Outstanding | 478,253,121 |
Consolidated Statements of Oper
Consolidated Statements of Operations and Comprehensive Income (Loss) - USD ($) shares in Millions, $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | |
Revenues | ||||
Revenue from Sales | $ 1,093 | $ 1,230 | $ 2,145 | $ 2,516 |
Total | 1,093 | 1,230 | 2,145 | 2,516 |
Costs and Expenses | ||||
Production Expense | 260 | 290 | 565 | 609 |
Depreciation, Depletion and Amortization | 528 | 465 | 1,036 | 933 |
General and Administrative | 105 | 105 | 207 | 209 |
Other Operating Expense, Net | 55 | 34 | 104 | 84 |
Gain on Divestitures, Net | 0 | (78) | 0 | (666) |
Asset Impairments | 0 | 0 | 0 | 168 |
Firm Transportation Exit Cost | 0 | 0 | 92 | 0 |
Total | 1,061 | 887 | 2,204 | 1,465 |
Operating Income (Loss) | 32 | 343 | (59) | 1,051 |
Other Expense | ||||
(Gain) Loss on Commodity Derivative Instruments | (60) | 249 | 152 | 328 |
Interest, Net of Amount Capitalized | 63 | 73 | 129 | 146 |
Other Non-Operating Expense, Net | 1 | 11 | 5 | 24 |
Total | 4 | 333 | 286 | 498 |
Income (Loss) Before Income Taxes | 28 | 10 | (345) | 553 |
Income Tax Expense (Benefit) | 20 | 16 | (64) | (15) |
Net Income (Loss) and Comprehensive Income (Loss) Including Noncontrolling Interests | 8 | (6) | (281) | 568 |
Less: Net Income and Comprehensive Income Attributable to Noncontrolling Interests | 18 | 17 | 42 | 37 |
Net (Loss) Income and Comprehensive (Loss) Income Attributable to Noble Energy | $ (10) | $ (23) | $ (323) | $ 531 |
Net (Loss) Income Attributable to Noble Energy Common Shareholders per Share | ||||
Basic ($ per share) | $ (0.02) | $ (0.05) | $ (0.68) | $ 1.09 |
Diluted ($ per share) | $ (0.02) | $ (0.05) | $ (0.68) | $ 1.09 |
Weighted Average Number of Common Shares Outstanding | ||||
Basic (in shares) | 478 | 484 | 478 | 485 |
Diluted (in shares) | 478 | 484 | 478 | 487 |
Oil, NGL and Gas Sales | ||||
Revenues | ||||
Revenue from Sales | $ 954 | $ 1,100 | $ 1,891 | $ 2,273 |
Sales of Purchased Oil and Gas | ||||
Revenues | ||||
Revenue from Sales | 103 | 66 | 177 | 119 |
Costs and Expenses | ||||
Cost of Purchased Oil and Gas | 113 | 71 | 200 | 128 |
Other Revenue | ||||
Revenues | ||||
Revenue from Sales | $ 36 | $ 64 | $ 77 | $ 124 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Jun. 30, 2019 | Dec. 31, 2018 |
Current Assets | ||
Cash and Cash Equivalents | $ 470 | $ 716 |
Accounts Receivable, Net | 575 | 616 |
Other Current Assets | 313 | 418 |
Total Current Assets | 1,358 | 1,750 |
Property, Plant and Equipment | ||
Oil and Gas Properties (Successful Efforts Method of Accounting) | 29,890 | 29,002 |
Property, Plant and Equipment, Other | 1,038 | 891 |
Total Property, Plant and Equipment, Gross | 30,928 | 29,893 |
Accumulated Depreciation, Depletion and Amortization | (12,153) | (11,474) |
Total Property, Plant and Equipment, Net | 18,775 | 18,419 |
Other Noncurrent Assets | 1,516 | 841 |
Total Assets | 21,649 | 21,010 |
Current Liabilities | ||
Accounts Payable – Trade | 1,313 | 1,207 |
Other Current Liabilities | 998 | 519 |
Total Current Liabilities | 2,311 | 1,726 |
Long-Term Debt | 6,866 | 6,574 |
Deferred Income Taxes | 961 | 1,061 |
Other Noncurrent Liabilities | 1,307 | 1,165 |
Total Liabilities | 11,445 | 10,526 |
Commitments and Contingencies | ||
Mezzanine Equity | ||
Redeemable Noncontrolling Interest, Net | 100 | 0 |
Shareholders’ Equity | ||
Preferred Stock – Par Value $1.00 per share; 4 Million Shares Authorized; None Issued | 0 | 0 |
Common Stock – Par Value $0.01 per share; 1 Billion Shares Authorized; 522 Million and 520 Million Shares Issued, respectively | 5 | 5 |
Additional Paid in Capital | 8,244 | 8,203 |
Accumulated Other Comprehensive Loss | (31) | (32) |
Treasury Stock, at Cost; 39 Million Shares | (735) | (730) |
Retained Earnings | 1,546 | 1,980 |
Noble Energy Share of Equity | 9,029 | 9,426 |
Noncontrolling Interests | 1,075 | 1,058 |
Total Shareholders' Equity | 10,104 | 10,484 |
Total Liabilities, Mezzanine Equity and Shareholders' Equity | $ 21,649 | $ 21,010 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Jun. 30, 2019 | Dec. 31, 2018 |
Statement of Financial Position [Abstract] | ||
Preferred stock, par value per share (in dollars per share) | $ 1 | $ 1 |
Preferred stock, shares authorized (in shares) | 4,000,000 | 4,000,000 |
Preferred stock, shares issued (in shares) | 0 | 0 |
Common stock, par value per share (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized (in shares) | 1,000,000,000 | 1,000,000,000 |
Common stock, shares issued (in shares) | 522,000,000 | 520,000,000 |
Treasury stock, 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, 2019 | Jun. 30, 2018 | |
Cash Flows From Operating Activities | ||
Net (Loss) Income Including Noncontrolling Interests | $ (281) | $ 568 |
Adjustments to Reconcile Net (Loss) Income to Net Cash Provided by Operating Activities | ||
Depreciation, Depletion and Amortization | 1,036 | 933 |
Deferred Income Tax Benefit | (101) | (164) |
Loss on Commodity Derivative Instruments | 152 | 328 |
Net Cash Received (Paid) in Settlement of Commodity Derivative Instruments | 15 | (93) |
Other Adjustments for Noncash Items Included in Income | 59 | 57 |
Gain on Divestitures, Net | 0 | (666) |
Asset Impairments | 0 | 168 |
Firm Transportation Exit Cost | 92 | 0 |
Changes in Operating Assets and Liabilities | ||
Decrease in Accounts Receivable | 35 | 76 |
Increase (Decrease) in Accounts Payable | 126 | (24) |
Increase in Partner Advances | 132 | 0 |
Other Current Assets and Liabilities, Net | (108) | (55) |
Other Operating Assets and Liabilities, Net | (65) | (49) |
Net Cash Provided by Operating Activities | 1,092 | 1,079 |
Cash Flows From Investing Activities | ||
Additions to Property, Plant and Equipment | (1,405) | (1,782) |
Acquisitions, Net of Cash Received | 0 | (650) |
Additions to Equity Method Investments | (415) | 0 |
Proceeds from Divestitures, Net | 123 | 1,382 |
Net Cash Used in Investing Activities | (1,697) | (1,050) |
Cash Flows From Financing Activities | ||
Proceeds from Commercial Paper Borrowings, Net | 240 | 0 |
Dividends Paid, Common Stock | (111) | (102) |
Purchase and Retirement of Common Stock | 0 | (130) |
Contributions from Noncontrolling Interest Owners | 21 | 331 |
Proceeds from Issuance of Mezzanine Equity, Net of Offering Costs | 99 | 0 |
Repayment of Senior Notes | (9) | (384) |
Other | (62) | (51) |
Net Cash Provided by (Used in) Financing Activities | 488 | (121) |
Decrease in Cash, Cash Equivalents, and Restricted Cash | (117) | (92) |
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period | 719 | 713 |
Cash, Cash Equivalents, and Restricted Cash at End of Period | 602 | 621 |
Revolving Credit Facility | ||
Cash Flows From Financing Activities | ||
Repayment of Revolving Credit Facilities | (50) | (1,135) |
Proceeds from Revolving Credit Facilities | 50 | 905 |
Noble Midstream Services Revolving Credit Facility | Revolving Credit Facility | ||
Cash Flows From Financing Activities | ||
Repayment of Revolving Credit Facilities | (250) | (165) |
Proceeds from Revolving Credit Facilities | $ 560 | $ 610 |
Consolidated Statements of Shar
Consolidated Statements of Shareholders' Equity - USD ($) $ in Millions | Total | Common Stock | Additional Paid in Capital | Accumulated Other Comprehensive Loss | Treasury Stock at Cost | Retained Earnings | Non- controlling Interests |
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 (Loss) Income | 574 | 554 | 20 | ||||
Stock-based Compensation | 17 | 17 | |||||
Dividends | (48) | (48) | |||||
Distributions to Noncontrolling Interest Owners | (11) | (11) | |||||
Contributions from Noncontrolling Interest Owners | 331 | 331 | |||||
Purchase and Retirement of Common Stock | (67) | (67) | |||||
Clayton Williams Energy Acquisition | (25) | (25) | |||||
Other | (3) | 1 | (6) | 2 | |||
Balance at End of Period at Mar. 31, 2018 | 11,387 | 5 | 8,363 | (29) | (731) | 2,754 | 1,025 |
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 (Loss) Income | 568 | ||||||
Balance at End of Period at Jun. 30, 2018 | 11,281 | 5 | 8,329 | (28) | (731) | 2,677 | 1,029 |
Balance at Beginning of Period at Mar. 31, 2018 | 11,387 | 5 | 8,363 | (29) | (731) | 2,754 | 1,025 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Net (Loss) Income | (6) | (23) | 17 | ||||
Stock-based Compensation | 29 | 29 | |||||
Dividends | (54) | (54) | |||||
Distributions to Noncontrolling Interest Owners | (11) | (11) | |||||
Purchase and Retirement of Common Stock | (63) | (63) | |||||
Other | (1) | 1 | 0 | (2) | |||
Balance at End of Period at Jun. 30, 2018 | 11,281 | 5 | 8,329 | (28) | (731) | 2,677 | 1,029 |
Balance at Beginning of Period at Dec. 31, 2018 | 10,484 | 5 | 8,203 | (32) | (730) | 1,980 | 1,058 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Net (Loss) Income | (289) | (313) | 24 | ||||
Stock-based Compensation | 14 | 14 | |||||
Dividends | (53) | (53) | |||||
Distributions to Noncontrolling Interest Owners | (17) | (17) | |||||
Contributions from Noncontrolling Interest Owners | 10 | 10 | |||||
Other | (6) | 2 | (5) | (3) | |||
Balance at End of Period at Mar. 31, 2019 | 10,143 | 5 | 8,219 | (32) | (735) | 1,614 | 1,072 |
Balance at Beginning of Period at Dec. 31, 2018 | 10,484 | 5 | 8,203 | (32) | (730) | 1,980 | 1,058 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Net (Loss) Income | (281) | ||||||
Balance at End of Period at Jun. 30, 2019 | 10,104 | 5 | 8,244 | (31) | (735) | 1,546 | 1,075 |
Balance at Beginning of Period at Mar. 31, 2019 | 10,143 | 5 | 8,219 | (32) | (735) | 1,614 | 1,072 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Net (Loss) Income | 8 | (10) | 18 | ||||
Stock-based Compensation | 21 | 21 | |||||
Dividends | (58) | (58) | |||||
Distributions to Noncontrolling Interest Owners | (19) | (19) | |||||
Contributions from Noncontrolling Interest Owners | 11 | 11 | |||||
Other | (2) | 4 | 1 | 0 | (7) | ||
Balance at End of Period at Jun. 30, 2019 | $ 10,104 | $ 5 | $ 8,244 | $ (31) | $ (735) | $ 1,546 | $ 1,075 |
Consolidated Statements of Sh_2
Consolidated Statements of Shareholders' Equity (Parenthetical) - $ / shares | 3 Months Ended | |||
Jun. 30, 2019 | Mar. 31, 2019 | Jun. 30, 2018 | Mar. 31, 2018 | |
Statement of Stockholders' Equity [Abstract] | ||||
Cash Dividends per share (in dollars per share) | $ 0.12 | $ 0.12 | $ 0.11 | $ 0.11 |
Organization and Nature of Oper
Organization and Nature of Operations | 6 Months Ended |
Jun. 30, 2019 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization and Nature of Operations | Note 1. Organization and Nature of Operations Noble Energy, Inc. (Noble Energy, we or us) is a leading independent energy company engaged in worldwide crude oil and natural gas exploration and production. Our historical operating areas include: US onshore, primarily the Denver-Julesburg (DJ) Basin, Delaware Basin and Eagle Ford Shale; US offshore Gulf of Mexico (until April 2018); Eastern Mediterranean; and West Africa. Our Midstream segment develops, owns and operates domestic midstream infrastructure assets, as well as invests in other midstream projects, with current focus areas being the DJ and Delaware Basins. |
Basis of Presentation
Basis of Presentation | 6 Months Ended |
Jun. 30, 2019 | |
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, 2019 and December 31, 2018 and for the three and six months ended June 30, 2019 and 2018 contain all normally recurring adjustments considered necessary for a fair presentation of our financial position, results of operations, cash flows and equity for such periods. Certain prior-period amounts have been reclassified to conform to the current period presentation. For the periods presented, net income or loss is materially consistent with comprehensive income or loss. Operating results for the three and six months ended June 30, 2019 are not necessarily indicative of the results that may be expected for the year ending December 31, 2019 . These consolidated financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in our Annual Report on Form 10-K for the year ended December 31, 2018 . Consolidation Our consolidated financial statements include our accounts, the accounts of subsidiaries which Noble Energy wholly owns, and the accounts of Noble Midstream Partners LP (Noble Midstream Partners), which is considered a variable interest entity (VIE) for which Noble Energy is the primary beneficiary. In addition, we use the equity method of accounting for investments in entities that we do not control, but over which we exert significant influence. All significant intercompany balances and transactions have been eliminated upon consolidation. Estimates The preparation of consolidated financial statements in conformity with US GAAP requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ significantly from those estimates. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. Partner Advances Partner advances consist of cash advances from certain of our Eastern Mediterranean field partners pending allocation of capacity in the EMG Pipeline owned by Eastern Mediterranean Gas Company S.A.E (EMG) and pending closing of the planned acquisition of EMG, which is expected to occur in third quarter 2019. The EMG Pipeline is expected to provide future connection from the Israel pipeline network to Egyptian customers. The acquisition of the equity interest in EMG is expected to support delivery of natural gas from our producing fields offshore Israel into Egypt. The cash advances received are reported within restricted cash in our consolidated balance sheets. Leases We determine whether an arrangement contains a lease based on the conveyed rights and obligations at the inception date. If an agreement contains an operating or financing lease, at the commencement date, we record a right-of-use (ROU) asset and a corresponding lease liability based on the present value of the minimum lease payments. As most of our leases do not provide an implicit borrowing rate, to determine the present value of lease payments, we use our hypothetical secured borrowing rate based on information available at lease commencement. Further, we make certain estimates and judgments regarding the lease term and lease payments, noted below. Lease Term Leases with an initial term of 12 months or less are not recorded on the balance sheet and we recognize lease expense for these leases on a straight-line basis over the lease term. Most leases include one or more options to renew, with renewal terms that can extend the lease term from one month to one year or more. Additionally, some of our leases include an option for early termination. We include renewal periods and exclude termination periods from our lease term if, at commencement, it is reasonably likely that we will exercise the option. Lease Payments Certain of our lease agreements include rental payments that are adjusted periodically for inflation or passage of time. These step payments are included within our present value calculation as they are known adjustments at commencement. Some of our lease agreements include variable payments that are excluded from our present value calculation. For example, drilling rig ROU assets and lease liabilities are recorded using the contractual standby rate, which is the fixed, minimum monthly payment, as opposed to the operating rate, which varies depending on the asset's use. Additionally, we have lease agreements that include lease and non-lease components, such as equipment maintenance, which are generally accounted for as a single lease component. For these leases, lease payments include all fixed payments stated within the contract. For office space, lease and non-lease components are accounted for separately. Our lease agreements do not contain any material residual value guarantees that would impact our lease payments. Revenue Recognition We recognize revenue at an amount that reflects the consideration we expect to be entitled to in exchange for transferring goods or services to a customer, using a five-step process, in accordance with ASC 606 – Revenue from Contracts with Customers (ASC 606). Under ASC 606, remaining performance obligations represent the transaction price of firm sales arrangements for which volumes have not been delivered. In Israel, certain of our Tamar natural gas contracts have fixed annual sales volumes and fixed base pricing with annual index escalations. The following table includes estimated revenues, as of June 30, 2019 , for those agreements. Our actual future sales volumes may exceed future minimum volume commitments. (millions) Remainder of 2019 2020 Total Natural Gas Revenues (1) $ 72 $ 116 $ 188 (1) The remaining performance obligations are estimated using the contractual base or floor price provision in effect. Future revenues under these contracts will vary from the amounts above due to components of variable consideration exceeding the contractual base or floor price provision. Redeemable Noncontrolling Interest In March 2019 , Noble Midstream Partners secured a $200 million equity commitment (preferred equity) from GIP CAPS Dos Rios Holding Partnership, L.P. (GIP) to fund capital contributions in connection with Noble Midstream Partners’ 30% equity investment in EPIC Crude Holdings, LP (EPIC Crude Holdings). GIP funded $100 million of the commitment, with associated offering costs of $3 million , and the remaining $100 million is available for a one-year period, subject to certain conditions precedent. The preferred equity is perpetual and has a 6.5% annual dividend rate, payable quarterly in cash, with the ability to defer payment during the first two years following the closing. Noble Midstream Partners can redeem the preferred equity in whole or in part at any time for cash at a predetermined redemption price. GIP can request redemption of the preferred equity following the later of the sixth anniversary of the preferred equity closing or the fifth anniversary of the EPIC crude oil pipeline completion date at a pre-determined base return. As GIP’s redemption right is outside of Noble Midstream Partners’ control, the preferred equity is not considered to be a component of equity on the consolidated balance sheet and, therefore, is reported as mezzanine equity. In addition, because the preferred equity was issued by a subsidiary of Noble Midstream Partners and is held by a third party, it is considered a redeemable noncontrolling interest. Subsequent to issuance, we accrete changes in the redemption value of the preferred equity from the date of issuance to the earliest redemption date of the preferred equity. The accretion is offset against additional paid in capital. See Note 4. Acquisitions and Divestitures and Note 13. Fair Value Measurements and Disclosures . Recently Issued Accounting Standards Financial Instruments: Credit Losses In June 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2016-13 (ASU 2016-13): Financial Instruments – Credit Losses , which replaces the incurred loss impairment methodology used for certain financial instruments with a methodology that reflects current expected credit losses. The current expected credit loss (CECL) model applies to a broad scope of financial instruments, including financial assets measured at amortized cost. CECL also applies to off-balance sheet credit exposures not accounted for as insurance, such as financial guarantees and other unfunded loan commitments. ASU 2016-13 is effective for fiscal years beginning after December 15, 2019, with early adoption permitted, and shall be applied using a modified retrospective approach through a cumulative-effect adjustment to retained earnings as of the beginning of the adoption period. The FASB subsequently issued Accounting Standards Update No. 2019-04 (ASU 2019-04): Codification Improvements to Topic 326, Financial Instruments-Credit Losses, Topic 815, Derivatives, and Topic 825, Financial Instruments and Accounting Standards Update No. 2019-05 (ASU 2019-05): Financial Instruments-Credit Losses (Topic 326)-Targeted Transition Relief . ASU 2019-04 and ASU 2019-05 provide certain codification improvements related to CECL implementation and targeted transition relief consisting of an option to irrevocably elect the fair value option for eligible instruments. 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 will not be significant. As such, we do not believe adoption of the standard will have a material impact on our financial statements. We have developed and are executing an implementation plan, which includes data collection, contract review and assessment, and evaluation of our systems, processes and internal controls. We will continue to monitor changes in our credit portfolio and off-balance sheet exposures as our implementation plan progresses. Recently Adopted Accounting Standards Leases In February 2016, the FASB issued Accounting Standards Update No. 2016-02 (ASU 2016-02), which created Topic 842 – Leases (ASC 842). The standard requires lessees to recognize a ROU asset and lease liability on the balance sheet for the rights and obligations created by leases. ASC 842 also requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. This standard does not apply to leases to explore for or use minerals, oil, natural gas or similar nonregenerative resources, including the intangible right to explore for those resources and rights to use the land in which those natural resources are contained. The new standard provided a number of optional practical expedients. We elected: • the package of transition “practical expedients”, permitting us not to reassess our prior conclusions about lease identification, lease classification and initial direct costs; • the practical expedient pertaining to land easements, allowing us to account for existing land easements under previous accounting policy; and • the practical expedient to not separate lease and non-lease components for the majority of our leases (elected by asset class). We adopted ASC 842 on January 1, 2019 using the modified retrospective method and, therefore, prior period financial statements were not adjusted. At adoption, we recorded ROU assets and lease liabilities of $282 million and $287 million , respectively, primarily related to operating leases. The difference between amounts recorded for ROU assets and amounts recorded for lease liabilities totaled $5 million . This amount was recognized as other operating expense. Our accounting for finance leases remains substantially unchanged. Adoption did not materially impact our consolidated statement of operations and comprehensive income and had no impact on our consolidated statement of cash flows. See Note 8. Leases . Derivatives and Hedging – Targeted Improvements to Accounting for Hedging Activities In August 2017, the FASB issued Accounting Standards Update No. 2017-12 (ASU 2017-12): Derivatives and Hedging – Targeted Improvements to Accounting for Hedging Activities. The update is intended to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. 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. We adopted this ASU on January 1, 2019. The adoption did not have an impact on our financial statements. Intangibles—Goodwill and Other—Internal-Use Software In August 2018, the FASB issued Accounting Standards Update No. 2018-15 (ASU 2018-15): Intangibles—Goodwill and Other—Internal-Use Software, to align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The amended standard is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. We early adopted this ASU in second quarter 2019 using the prospective method. The adoption did not have a material impact on our financial statements. Statements of Operations Information Other statements of operations information is as follows: Three Months Ended June 30, Six Months Ended June 30, (millions) 2019 2018 2019 2018 Other Revenue Income from Equity Method Investees and Other $ 16 $ 49 $ 33 $ 96 Midstream Services Revenues – Third Party 20 15 44 28 Total $ 36 $ 64 $ 77 $ 124 Production Expense Lease Operating Expense $ 122 $ 132 $ 273 $ 287 Production and Ad Valorem Taxes 41 50 90 104 Gathering, Transportation and Processing Expense 96 98 198 191 Other Royalty Expense 1 10 4 27 Total $ 260 $ 290 $ 565 $ 609 Other Operating Expense, Net Exploration Expense $ 33 $ 29 $ 57 $ 64 Marketing Expense 14 9 19 16 Other, Net 8 (4 ) 28 4 Total $ 55 $ 34 $ 104 $ 84 Balance Sheet Information Other balance sheet information is as follows: (millions) June 30, December 31, Accounts Receivable, Net Commodity Sales $ 346 $ 383 Joint Interest Billings 153 137 Other 91 111 Allowance for Doubtful Accounts (15 ) (15 ) Total $ 575 $ 616 Other Current Assets Commodity Derivative Assets $ 30 $ 180 Inventories, Materials and Supplies 68 55 Assets Held for Sale (1) — 133 Restricted Cash (2) 132 3 Prepaid Expenses and Other Current Assets 83 47 Total $ 313 $ 418 Other Noncurrent Assets Equity Method Investments (3) $ 699 $ 286 Operating Lease Right-of-Use Assets (4) 272 — Customer-Related Intangible Assets, Net (5) 294 310 Goodwill (5) 110 110 Other Assets, Noncurrent 141 135 Total $ 1,516 $ 841 Other Current Liabilities Production and Ad Valorem Taxes $ 132 $ 103 Asset Retirement Obligations 85 118 Interest Payable 64 66 Operating Lease Liabilities (4) 88 — Commercial Paper Borrowings 240 — Partner Advances (2) 132 — Other Liabilities, Current 257 232 Total $ 998 $ 519 Other Noncurrent Liabilities Deferred Compensation Liabilities $ 147 $ 147 Asset Retirement Obligations 707 762 Operating Lease Liabilities (4) 190 — Firm Transportation Exit Cost Accrual (6) 144 67 Production and Ad Valorem Taxes 24 83 Other Liabilities, Noncurrent 95 106 Total $ 1,307 $ 1,165 (1) Assets held for sale at December 31, 2018 related to the first quarter 2019 divestiture of non-core acreage in Reeves County, Texas. See Note 4. Acquisitions and Divestitures . (2) See Partner Advances , above. (3) The 2019 amount includes Noble Midstream Partners' $ 369 million investment in EPIC Y-Grade, LP (EPIC Y-Grade) and EPIC Crude Holdings and its $ 39 million investment in Delaware Crossing LLC. See Note 4. Acquisitions and Divestitures . (4) Amounts relate to assets and liabilities recorded as a result of ASC 842 adoption in first quarter 2019. See Note 8. Leases . (5) Amounts relate to assets acquired in the first quarter 2018 Saddle Butte acquisition. Intangible asset balances at June 30, 2019 and December 31, 2018 are net of accumulated amortization of $ 46 million and $30 million , respectively. See Note 4. Acquisitions and Divestitures . (6) See Note 9. Exit Cost – Transportation Commitments . Reconciliation of Total Cash We define total cash as cash, cash equivalents and restricted cash. The following table provides a reconciliation of total cash: Six Months Ended June 30, (millions) 2019 2018 Cash and Cash Equivalents at Beginning of Period $ 716 $ 675 Restricted Cash at Beginning of Period 3 38 Cash, Cash Equivalents, and Restricted Cash at Beginning of Period $ 719 $ 713 Cash and Cash Equivalents at End of Period $ 470 $ 621 Restricted Cash at End of Period 132 — Cash, Cash Equivalents, and Restricted Cash at End of Period $ 602 $ 621 |
Segment Information
Segment Information | 6 Months Ended |
Jun. 30, 2019 | |
Segment Reporting [Abstract] | |
Segment Information | Note 3. Segment Information We have the following reportable segments: United States (US onshore and Gulf of Mexico (until April 2018)); Eastern Mediterranean (Israel and Cyprus); West Africa (Equatorial Guinea, Cameroon and Gabon); Other International (Canada, New Ventures and Colombia); and Midstream. The Midstream segment includes the consolidated accounts of Noble Midstream Partners and other US onshore midstream assets. The geographical reportable segments are in the business of crude oil and natural gas acquisition and exploration, development, and production (Oil and Gas Exploration and Production). The Midstream reportable segment develops, owns, and operates domestic midstream infrastructure assets, as well as invests in other midstream projects. The chief operating decision maker analyzes income before income taxes to assess the performance of Noble Energy's reportable segments as management believes this measure provides useful information in assessing our operating and financial performance across periods. Expenses related to debt, such as interest and other debt-related costs, headquarters depreciation, corporate general and administrative expenses, exit costs and certain costs associated with mitigating the effects of our retained Marcellus Shale firm transportation agreements, are recorded at the Corporate level. Oil and Gas Exploration and Production Midstream (millions) Consolidated United States Eastern Mediter-ranean West Africa Other Int'l United States Intersegment Eliminations and Other (1) Corporate Three Months Ended June 30, 2019 Crude Oil Sales $ 688 $ 617 $ 2 $ 69 $ — $ — $ — $ — NGL Sales 84 84 — — — — — — Natural Gas Sales 182 72 105 5 — — — — Total Crude Oil, NGL and Natural Gas Sales 954 773 107 74 — — — — Sales of Purchased Oil and Gas 103 28 — — — 52 — 23 Income (Loss) from Equity Method Investees and Other 16 1 — 17 — (2 ) — — Midstream Services Revenues – Third Party 20 — — — — 20 — — Intersegment Revenues — — — — — 91 (91 ) — Total Revenues 1,093 802 107 91 — 161 (91 ) 23 Lease Operating Expense 122 114 9 10 — 1 (12 ) — Production and Ad Valorem Taxes 41 40 — — — 1 — — Gathering, Transportation and Processing Expense 96 124 — — — 31 (59 ) — Oil and Gas Exploration and Production Midstream (millions) Consolidated United States Eastern Mediter-ranean West Africa Other Int'l United States Intersegment Eliminations and Other (1) Corporate Other Royalty Expense 1 1 — — — — — — Total Production Expense 260 279 9 10 — 33 (71 ) — Depreciation, Depletion and Amortization 528 457 17 19 — 26 (6 ) 15 Cost of Purchased Oil and Gas 113 28 — — — 48 — 37 Gain on Commodity Derivative Instruments (60 ) (58 ) — (2 ) — — — — Income (Loss) Before Income Taxes 28 70 65 59 (15 ) 46 (15 ) (182 ) Additions to Long-Lived Assets, Excluding Acquisitions 647 478 119 12 2 52 (25 ) 9 Investments in Equity Method Investees 144 — — — — 144 — — 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 — — — — Sales of Purchased Oil and Gas 66 — — — — 42 — 24 Income from Equity Method Investees and Other 49 — — 36 — 13 — — Midstream Services Revenues – Third Party 15 — — — — 15 — — Intersegment Revenues — — — — — 85 (85 ) — Total Revenues 1,230 870 113 153 — 155 (85 ) 24 Lease Operating Expense 132 114 5 19 — — (6 ) — Production and Ad Valorem Taxes 50 48 — — — 2 — — Gathering, Transportation and Processing Expense 98 131 — — — 22 (55 ) — Other Royalty Expense 10 10 — — — — — — Total Production Expense 290 303 5 19 — 24 (61 ) — Depreciation, Depletion and Amortization 465 394 15 26 — 22 (4 ) 12 (Gain) Loss on Divestitures, Net (78 ) 21 10 — — (109 ) — — Cost of Purchased Oil and Gas 71 — — — — 40 — 31 Loss on Commodity Derivative Instruments 249 196 — 53 — — — — Income (Loss) Before Income Taxes 10 (90 ) 62 48 (13 ) 175 (18 ) (154 ) Additions to Long-Lived Assets, Excluding Acquisitions 935 561 216 3 — 155 (18 ) 18 Six Months Ended June 30, 2019 Crude Oil Sales $ 1,300 $ 1,162 $ 3 $ 135 $ — $ — $ — $ — NGL Sales 180 180 — — — — — — Natural Gas Sales 411 180 222 9 — — — — Oil and Gas Exploration and Production Midstream (millions) Consolidated United States Eastern Mediter-ranean West Africa Other Int'l United States Intersegment Eliminations and Other (1) Corporate Total Crude Oil, NGL and Natural Gas Sales 1,891 1,522 225 144 — — — — Sales of Purchased Oil and Gas 177 42 — — — 85 — 50 Income from Equity Method Investees and Other 33 1 — 32 — — — — Midstream Services Revenues – Third Party 44 — — — — 44 — — Intersegment Revenues — — — — — 197 (197 ) Total Revenues 2,145 1,565 225 176 — 326 (197 ) 50 Lease Operating Expense 273 239 19 34 — 2 (21 ) — Production and Ad Valorem Taxes 90 87 — — — 3 — — Gathering, Transportation and Processing Expense 198 266 — — — 60 (128 ) — Other Royalty Expense 4 4 — — — — — — Total Production Expense 565 596 19 34 — 65 (149 ) — Depreciation, Depletion and Amortization 1,036 896 33 39 — 51 (13 ) 30 Cost of Purchased Oil and Gas 200 42 — — — 79 — 79 Firm Transportation Exit Cost 92 — — — — — — 92 Loss on Commodity Derivative Instruments 152 130 — 22 — — — — (Loss) Income Before Income Taxes (345 ) (177 ) 149 70 (31 ) 119 (29 ) (446 ) Additions to Long-Lived Assets, Excluding Acquisitions 1,359 990 251 18 12 118 (48 ) 18 Investments in Equity Method Investees 415 — — — — 415 — — 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 — — — — Sales of Purchased Oil and Gas 119 — — — — 64 — 55 Income from Equity Method Investees and Other 96 — — 71 — 25 — — Midstream Services Revenues – Third Party 28 — — — — 28 — — Intersegment Revenues — — — — — 166 (166 ) — Total Revenues 2,516 1,818 244 282 — 283 (166 ) 55 Lease Operating Expense 287 240 12 41 — — (6 ) — Production and Ad Valorem Taxes 104 101 — — — 3 — — Gathering, Transportation and Processing Expense 191 256 — — — 43 (108 ) — Other Royalty Expense 27 27 — — — — — — Total Production Expense 609 624 12 41 — 46 (114 ) — Oil and Gas Exploration and Production Midstream (millions) Consolidated United States Eastern Mediter-ranean West Africa Other Int'l United States Intersegment Eliminations and Other (1) Corporate Depreciation, Depletion and Amortization 933 800 28 52 — 38 (8 ) 23 (Gain) Loss on Divestitures, Net (666 ) 15 (376 ) — — (305 ) — — Asset Impairments 168 168 — — — — — — Cost of Purchased Oil and Gas 128 — — — — 61 — 67 Loss on Commodity Derivative Instruments 328 260 — 68 — — — — Income (Loss) Before Income Taxes 553 (127 ) 535 112 (27 ) 428 (40 ) (328 ) Additions to Long-Lived Assets, Excluding Acquisitions 1,840 1,095 363 5 2 397 (50 ) 28 June 30, 2019 Property, Plant and Equipment, Net $ 18,775 $ 13,095 $ 2,879 $ 773 $ 36 $ 1,841 $ (185 ) $ 336 December 31, 2018 Property, Plant and Equipment, Net $ 18,419 $ 13,044 $ 2,630 $ 805 $ 37 $ 1,742 $ (145 ) $ 306 (1) The intersegment eliminations related to income 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. |
Acquisitions and Divestitures
Acquisitions and Divestitures | 6 Months Ended |
Jun. 30, 2019 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Acquisitions and Divestitures | Note 4. Acquisitions and Divestitures We maintain an ongoing portfolio management program and have engaged in various transactions over recent years. 2019 Asset Transactions Divestiture of Reeves County Assets In February 2019, we closed the sale of certain proved and unproved non-core acreage in the Delaware Basin totaling approximately 13,000 net acres in Reeves County, Texas. We received cash consideration of approximately $131 million , recognizing no gain or loss on the sale. EPIC Pipeline Investments In first quarter 2019, Noble Midstream Partners exercised and closed options with EPIC Midstream Holdings, LP (EPIC) to acquire a 15% equity interest in EPIC Y-Grade, which is constructing the EPIC Y-Grade pipeline from the Delaware Basin to Corpus Christi, Texas, and a 30% equity interest in EPIC Crude Holdings, which is constructing the EPIC crude oil pipeline also from the Delaware Basin to Corpus Christi, Texas. Cash consideration totaled $227 million. In second quarter 2019, Noble Midstream Partners made additional capital contributions of $28 million and $114 million to EPIC Y-Grade and EPIC Crude Holdings, respectively, to fund its share of pipeline construction costs. These investments are accounted for using the equity method. See Note 2. Basis of Presentation . Delaware Crossing Joint Venture In February 2019, Noble Midstream Partners executed definitive agreements with Salt Creek Midstream LLC (Salt Creek) to form a 50/50 joint venture, Delaware Crossing LLC (Delaware Crossing), to construct a 160 MBbl/d day crude oil pipeline system in the Delaware Basin. For the first six months of 2019 , Noble Midstream Partners made capital contributions of $39 million for construction of the pipeline. This investment is accounted for using the equity method. 2018 Asset Transactions Divestiture of Gulf of Mexico Assets In February 2018, we announced plans to sell our Gulf of Mexico assets for cash consideration of $ 480 million, along with the assumption, by the purchaser, of all abandonment obligations associated with the properties. As of March 31, 2018, we reduced the net book value of the Gulf of Mexico assets to $480 million . In addition, we retained certain transaction related obligations approximating $92 million which were subsequently settled upon closing. During first quarter 2018, we recorded impairment expense of $ 168 million associated with these assets held for sale. The transaction closed in second quarter 2018. We received net proceeds of $383 million and recorded an additional loss of $19 million . Divestiture of 7.5% Interest in Tamar Field In March 2018, we closed the sale of a 7.5% working interest in the Tamar field to Tamar Petroleum Ltd., a publicly traded entity on the Tel Aviv Stock Exchange (Tamar Petroleum, TASE: TMRP). Total consideration included cash of $484 million and 38.5 million shares of Tamar Petroleum that had a publicly traded value of $224 million . Total consideration received from the sale was applied to the field's basis and resulted in the recognition of a pre-tax gain of $386 million and tax expense of $90 million . In October 2018, we sold our shares in Tamar Petroleum for pre-tax proceeds of $163 million , net of transaction expenses. The sale was in accordance with the Israel Natural Gas Framework and completed our obligation to reduce ownership interest in the Tamar field from 32.5% to 25% by year end-2021. Divestiture of Southwest Royalties In January 2018, we closed the sale of our investment in Southwest Royalties, Inc. We received proceeds of $60 million , recognizing no gain or loss on the sale. Divestiture of Marcellus Shale CONE Gathering In January 2018, we closed the sale of our 50% interest in CONE Gathering LLC (CONE Gathering) to CNX Resources Corporation. CONE Gathering owns the general partner of CNX Midstream Partners LP (CNX Midstream Partners, NYSE: CNXM). We received proceeds of $308 million in cash and recognized a pre-tax gain of $196 million . After the sale, we held 21.7 million common units, representing a 34.1% limited partner interest in CNX Midstream Partners. During second quarter 2018, we sold 7.5 million common units, receiving net proceeds of $135 million , net of underwriting fees, and recognized a gain of $109 million . During third quarter 2018, we sold the remaining 14.2 million common units, representing a 22.3% limited partner interest, in CNX Midstream Partners, receiving proceeds net of underwriting fees of approximately $248 million , and recognized a gain of $198 million . Noble Midstream Partners Saddle Butte Acquisition In January 2018, Noble Midstream Partners acquired a 54.4% interest in Black Diamond Gathering LLC (Black Diamond), an entity formed by Black Diamond Gathering Holdings LLC, a wholly-owned subsidiary of Noble Midstream Partners, and Greenfield Midstream, LLC (Greenfield), which completed the acquisition of Saddle Butte Rockies Midstream, LLC and affiliates (collectively, Saddle Butte) from Saddle Butte Pipeline II, LLC. Saddle Butte owns a large-scale integrated gathering system, located in the DJ Basin, which we subsequently renamed the Black Diamond gathering system. Consideration totaled $681 million and Black Diamond is consolidated as a VIE. We accounted for the transaction as a business combination using the acquisition method. The total purchase price was allocated to assets acquired and liabilities assumed based on acquisition date fair values, and we recognized goodwill for the amount of the purchase price exceeding the fair values of the identifiable net assets acquired. The final purchase price allocation included: $206 million to property, plant and equipment; $340 million to customer-related intangible assets (acquired customer contracts); and $110 million |
Capitalized Exploratory Well Co
Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs | 6 Months Ended |
Jun. 30, 2019 | |
Extractive Industries [Abstract] | |
Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs | Note 5. 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. There were no significant changes to our capitalized exploratory well costs during the period. The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced: (millions, except number of projects) June 30, December 31, Exploratory Well Costs Capitalized for a Period of One Year or Less $ 11 $ 6 Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling 351 348 Capitalized Exploratory Well Costs, End of Period $ 362 $ 354 Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling 7 7 Undeveloped Leasehold Costs Undeveloped leasehold costs are derived from allocated fair values as a result of business combinations or other purchases of unproved properties and are subject to impairment testing. We reclassify undeveloped leasehold costs to proved property costs when, as a result of exploration and development activities, probable and possible resources are reclassified to proved reserves, including proved undeveloped reserves. 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 exploration expense related to the respective leases or licenses. Changes in undeveloped leasehold costs were as follows: (millions) Six Months Ended June 30, 2019 Undeveloped Leasehold Costs, Beginning of Period $ 2,306 Additions to Undeveloped Leasehold Costs 50 Transfers to Proved Properties (11 ) Assets Sold (2 ) Undeveloped Leasehold Costs, End of Period $ 2,343 As of June 30, 2019 , undeveloped leasehold costs included $2.1 billion, $100 million, $73 million, and $59 million attributable to the Delaware Basin, Eagle Ford Shale, other US onshore properties, and international properties, respectively. Certain of these costs pertain to acquired leases or licenses that are subject to expiration over the next several years unless production is established on the acreage. Other costs pertain to acreage that is being held by production. |
Asset Retirement Obligations
Asset Retirement Obligations | 6 Months Ended |
Jun. 30, 2019 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | Note 6. Asset Retirement Obligations Asset retirement obligations (ARO) consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. Changes in ARO are as follows: Six Months Ended June 30, (millions) 2019 2018 Asset Retirement Obligations, Beginning Balance $ 880 $ 875 Liabilities Incurred 15 14 Liabilities Settled (56 ) (261 ) Revisions of Estimates (70 ) (10 ) Accretion Expense 23 17 Asset Retirement Obligations, Ending Balance $ 792 $ 635 Six Months Ended June 30, 2019 Liabilities settled relate to abandonment of US onshore properties, primarily in the DJ Basin where we have engaged in a program to plug and abandon older vertical wells. Costs associated with these abandonment activities will be incurred over several years. Revisions of estimates relate primarily to a decrease of $73 million in the DJ Basin as a result of improved cycle times and cost reductions for vertical wells. Six Months Ended June 30, 2018 Liabilities settled include $216 million of liabilities assumed by the purchaser of the Gulf of Mexico assets and $44 million related to abandonment of US onshore properties, primarily in the DJ Basin. Revisions of estimates relate primarily 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 in cost and timing estimates of $7 million |
Debt
Debt | 6 Months Ended |
Jun. 30, 2019 | |
Debt Disclosure [Abstract] | |
Debt | Note 7. Debt Debt consists of the following: June 30, 2019 December 31, 2018 (millions, except percentages) Debt Interest Rate Debt Interest Rate Noble Energy, Excluding Noble Midstream Partners Revolving Credit Facility, due March 9, 2023 $ — — % $ — — % Commercial Paper Borrowings 240 (1 ) — — % Senior Notes and Debentures 5,884 (2 ) 5,892 (2 ) Finance Lease Obligations 211 — % 223 — % Total Noble Energy Debt, Excluding Noble Midstream Partners Debt 6,335 6,115 Noble Midstream Partners Noble Midstream Services Revolving Credit Facility, due March 9, 2023 (3) 370 3.77 % 60 3.67 % Noble Midstream Services Term Loan Credit Facility, due July 31, 2021 500 3.51 % 500 3.42 % Total Noble Midstream Partners Debt 870 560 Total Debt 7,205 6,675 Net Unamortized Discounts and Debt Issuance Costs (58 ) (60 ) Total Debt, Net of Unamortized Discounts and Debt Issuance Costs 7,147 6,615 Less Amounts Due Within One Year Commercial Paper Borrowings (240 ) — Finance Lease Obligations (41 ) (41 ) Long-Term Debt Due After One Year $ 6,866 $ 6,574 (1) As of June 30, 2019 , the weighted average interest rate for outstanding commercial paper was 3.04% . (2) As of June 30, 2019 and December 31, 2018 , the Senior Notes and Debentures had weighted average interest rates of 5.00% and 5.01% , respectively. (3) As of June 30, 2019 and December 31, 2018 , the Noble Midstream Services Revolving Credit Facility had $ 800 million of capacity. Amounts available for borrowing totaled $ 430 million and $ 740 million, respectively. Commercial Paper Program In first quarter 2019, we established a commercial paper program to provide for short-term funding needs. The program allows for a maximum of $4.0 billion of unsecured commercial paper notes and is supported by Noble Energy’s $4.0 billion Revolving Credit Facility. Our commercial paper notes, which generally have a maturity of less than 30 days, are sold under customary terms in the commercial paper market and notes are either issued at a discounted price relative to the principal face value or bear interest at varying interest rates on a fixed or floating basis. Such discounted prices or interest rates are dependent on market conditions and ratings assigned to the commercial paper program by credit agencies at the time of commercial paper issuance. At June 30, 2019 , outstanding commercial paper borrowings totaled $240 million , leaving $ 3.8 billion available for borrowing under our $4.0 billion Revolving Credit Facility. Redemption of Senior Notes In June 2019, we redeemed $8 million of Senior Notes due June 1, 2024 that we assumed in the 2015 merger with Rosetta Resources, Inc. for approximately $9 million , including call premium and interest. Fair Value of Debt See Note 13. Fair Value Measurements and Disclosures . |
Leases
Leases | 6 Months Ended |
Jun. 30, 2019 | |
Leases [Abstract] | |
Leases | Note 8. Leases In the normal course of business, we enter into operating and finance lease agreements to support our operations. Operating leases include primarily office space for our corporate and field locations, US onshore compressors and drilling rigs, vessels and helicopters for offshore operations, storage facilities, and other miscellaneous assets. Finance leases include corporate office space, a trunkline in the DJ Basin, a floating production, storage and offloading vessel (FPSO) in West Africa, and vehicles. Our leasing activity is recorded and presented on a gross basis, with the exception of the FPSO which is recorded net to our interest. Balance Sheet Information ROU assets and lease liabilities ar e as follows: (millions) Balance Sheet Location June 30, 2019 ROU Assets Operating Leases (1) Other Noncurrent Assets $ 272 Finance Leases (2) Total Property, Plant and Equipment, Net 175 Total ROU Assets $ 447 Lease Liabilities Current Liabilities Operating Leases Other Current Liabilities $ 88 Finance Leases Other Current Liabilities 41 Noncurrent Liabilities Operating Leases Other Noncurrent Liabilities 190 Finance Leases Long-Term Debt 170 Total Lease Liabilities $ 489 (1) Operating lease ROU assets include primarily office space of $117 million , compressors of $88 million , and drilling rigs of $35 million . (2) Finance lease ROU assets include primarily office space of $94 million , net of accumulated amortization. Statement of Operations Information The components of lease cost are as follows: (millions) Statement of Operations Location Three Months Ended June 30, 2019 Six Months Ended June 30, 2019 Operating Lease Cost (1) $ 26 $ 51 Finance Lease Cost Amortization Expense Depreciation, Depletion and Amortization 9 17 Interest Expense Interest, Net of Amount Capitalized 4 7 Short-term Lease Cost (2) (1) 143 269 Variable Lease Cost (3) (1) — — Sublease Income General and Administrative (1 ) (2 ) Total Lease Cost $ 181 $ 342 (1) Cost classification varies depending on the leased asset. Costs are primarily included within production expense and general and administrative expense. In addition, in accordance with the successful efforts method of accounting, certain lease costs may be capitalized when incurred, as part of oil and gas properties on our consolidated balance sheet. (2) Short-term lease costs relate primarily to hydraulic fracturing services, well-to-well drilling rig contracts and other miscellaneous lease agreements. Amount excludes costs for leases with an initial term of one month or less. (3) Variable lease costs were de minimis for second quarter and the first six months of 2019 . Cash Flow Information Supplemental cash flow information is as follows: Six Months Ended June 30, 2019 (millions) Operating Leases Finance Leases Cash Paid for Amounts Included in the Measurement of Lease Liabilities Operating Cash Flows $ 30 $ 6 Financing Cash Flows — 20 Investing Cash Flows 18 — ROU Assets Obtained in Exchange for Lease Liabilities (1) 58 8 (1) Amounts exclude the impact of adopting ASC 842 on January 1, 2019. See Note 2. Basis of Presentation . Maturity of Lease Liabilities Maturities of lease liabilities as of June 30, 2019 are as follows: (millions) Operating Leases Finance Leases Total Remainder of 2019 $ 50 $ 25 $ 75 2020 85 48 133 2021 48 33 81 2022 33 23 56 2023 21 21 42 2024 and Thereafter 80 105 185 Total Lease Liabilities, Undiscounted 317 255 572 Less: Imputed Interest 39 44 83 Total Lease Liabilities (1) $ 278 $ 211 $ 489 (1) Includes the current portions of $ 88 million and $ 41 million for operating and finance leases, respectively. Lease commitments as of December 31, 2018 were as follows: (millions) Operating Leases Finance Leases Total 2019 $ 91 $ 52 $ 143 2020 74 46 120 2021 59 31 90 2022 62 22 84 2023 50 20 70 2024 and Thereafter 176 104 280 Total Lease Liabilities, Undiscounted $ 512 $ 275 $ 787 Other Information Other information related to our leases is as follows: June 30, 2019 Weighted-Average Remaining Lease Term Operating Leases 5.9 years Finance Leases 7.9 years Weighted-Average Discount Rate Operating Leases 4.40 % Finance Leases 5.01 % |
Leases | Note 8. Leases In the normal course of business, we enter into operating and finance lease agreements to support our operations. Operating leases include primarily office space for our corporate and field locations, US onshore compressors and drilling rigs, vessels and helicopters for offshore operations, storage facilities, and other miscellaneous assets. Finance leases include corporate office space, a trunkline in the DJ Basin, a floating production, storage and offloading vessel (FPSO) in West Africa, and vehicles. Our leasing activity is recorded and presented on a gross basis, with the exception of the FPSO which is recorded net to our interest. Balance Sheet Information ROU assets and lease liabilities ar e as follows: (millions) Balance Sheet Location June 30, 2019 ROU Assets Operating Leases (1) Other Noncurrent Assets $ 272 Finance Leases (2) Total Property, Plant and Equipment, Net 175 Total ROU Assets $ 447 Lease Liabilities Current Liabilities Operating Leases Other Current Liabilities $ 88 Finance Leases Other Current Liabilities 41 Noncurrent Liabilities Operating Leases Other Noncurrent Liabilities 190 Finance Leases Long-Term Debt 170 Total Lease Liabilities $ 489 (1) Operating lease ROU assets include primarily office space of $117 million , compressors of $88 million , and drilling rigs of $35 million . (2) Finance lease ROU assets include primarily office space of $94 million , net of accumulated amortization. Statement of Operations Information The components of lease cost are as follows: (millions) Statement of Operations Location Three Months Ended June 30, 2019 Six Months Ended June 30, 2019 Operating Lease Cost (1) $ 26 $ 51 Finance Lease Cost Amortization Expense Depreciation, Depletion and Amortization 9 17 Interest Expense Interest, Net of Amount Capitalized 4 7 Short-term Lease Cost (2) (1) 143 269 Variable Lease Cost (3) (1) — — Sublease Income General and Administrative (1 ) (2 ) Total Lease Cost $ 181 $ 342 (1) Cost classification varies depending on the leased asset. Costs are primarily included within production expense and general and administrative expense. In addition, in accordance with the successful efforts method of accounting, certain lease costs may be capitalized when incurred, as part of oil and gas properties on our consolidated balance sheet. (2) Short-term lease costs relate primarily to hydraulic fracturing services, well-to-well drilling rig contracts and other miscellaneous lease agreements. Amount excludes costs for leases with an initial term of one month or less. (3) Variable lease costs were de minimis for second quarter and the first six months of 2019 . Cash Flow Information Supplemental cash flow information is as follows: Six Months Ended June 30, 2019 (millions) Operating Leases Finance Leases Cash Paid for Amounts Included in the Measurement of Lease Liabilities Operating Cash Flows $ 30 $ 6 Financing Cash Flows — 20 Investing Cash Flows 18 — ROU Assets Obtained in Exchange for Lease Liabilities (1) 58 8 (1) Amounts exclude the impact of adopting ASC 842 on January 1, 2019. See Note 2. Basis of Presentation . Maturity of Lease Liabilities Maturities of lease liabilities as of June 30, 2019 are as follows: (millions) Operating Leases Finance Leases Total Remainder of 2019 $ 50 $ 25 $ 75 2020 85 48 133 2021 48 33 81 2022 33 23 56 2023 21 21 42 2024 and Thereafter 80 105 185 Total Lease Liabilities, Undiscounted 317 255 572 Less: Imputed Interest 39 44 83 Total Lease Liabilities (1) $ 278 $ 211 $ 489 (1) Includes the current portions of $ 88 million and $ 41 million for operating and finance leases, respectively. Lease commitments as of December 31, 2018 were as follows: (millions) Operating Leases Finance Leases Total 2019 $ 91 $ 52 $ 143 2020 74 46 120 2021 59 31 90 2022 62 22 84 2023 50 20 70 2024 and Thereafter 176 104 280 Total Lease Liabilities, Undiscounted $ 512 $ 275 $ 787 Other Information Other information related to our leases is as follows: June 30, 2019 Weighted-Average Remaining Lease Term Operating Leases 5.9 years Finance Leases 7.9 years Weighted-Average Discount Rate Operating Leases 4.40 % Finance Leases 5.01 % |
Exit Costs - Transportation Com
Exit Costs - Transportation Commitments | 6 Months Ended |
Jun. 30, 2019 | |
Commitments and Contingencies Disclosure [Abstract] | |
Exit Costs - Transportation Commitments | Note 9. Exit Cost – Transportation Commitments In connection with the divestiture of Marcellus Shale upstream assets in 2017, we retained certain financial commitments on pipelines flowing natural gas production inside and outside of the Marcellus Basin. These financial commitments represent commitments to pay transportation fees; thus, we have no commitment to physically transport minimum volumes of natural gas. Since closing, we have continued efforts to commercialize these firm transportation commitments, including permanent assignment of capacity, negotiation of capacity releases, utilization of capacity through purchase and transport of third-party natural gas, and other potential arrangements. In the event we execute a permanent assignment of capacity, we no longer have a contractual obligation to the pipeline company and, as such, our gross contractual commitment is reduced. In the event we execute a capacity release or utilize capacity through the purchase and transport of natural gas, we remain the primary obligor to the pipeline company. While our gross contractual commitment is not reduced, except through use under those arrangements, we would receive future cash payments from the third-parties with whom we negotiated a capacity release or from the sale of purchased natural gas to third-parties. As of June 30, 2019 , our gross retained firm transportation commitment for the remaining obligations under these agreements, which have remaining terms of approximately three to fourteen years, is approximately $ 1.0 billion , undiscounted. Leach Xpress and Rayne Xpress Permanent Assignment In January 2019, we executed agreements on the Leach Xpress and Rayne Xpress pipelines to permanently assign remaining capacity to a third-party effective January 1, 2021, extending through the end of the contract. The permanent assignment reduced our total financial commitment by approximately $350 million , undiscounted. As a result of the assignment, we recorded firm transportation exit cost of $92 million, discounted, related to future commitments to the third party. We will continue efforts to mitigate the impact of these transportation agreements during 2019 and 2020. Financial Statement Impact In addition to the retained firm transportation commitments, we have the following accrued discounted liabilities associated with exit cost activities, including the permanent assignment described above: Six Months Ended June 30, (millions) 2019 2018 Balance at Beginning of Period (1) $ 80 $ 90 Firm Transportation Exit Cost Accrual 92 — Payments, Net of Accretion (5 ) (7 ) Balance at End of Period 167 83 Less: Current Portion Included in Other Current Liabilities 23 12 Long-term Portion Included in Other Noncurrent Liabilities $ 144 $ 71 (1) Amounts include the current portion of $13 million which is included in other current liabilities in our consolidated balance sheets. Revenues and expenses associated with capacity release agreements and purchases and sales of natural gas are as follows: Three Months Ended June 30, Six Months Ended June 30, (millions) 2019 2018 2019 2018 Sales of Purchased Gas (1) $ 23 $ 24 $ 50 $ 55 Cost of Purchased Gas and Related Expense Cost of Purchased of Gas 22 23 49 53 Utilized Firm Transportation Expense (2) 15 6 30 11 Unutilized Firm Transportation Expense — 2 — 3 Cost of Purchased Gas and Related Expense, Total (3) $ 37 $ 31 $ 79 $ 67 (1) Amounts are included in sales of purchased oil and gas within our statements of operations. (2) Includes the net impact of the difference in the firm transportation contract rates and rates agreed to in the capacity releases, as well as transportation expenses associated with transport of purchased natural gas. (3) |
Commitments and Contingencies
Commitments and Contingencies | 6 Months Ended |
Jun. 30, 2019 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Note 10. Commitments and Contingencies Legal Proceedings We are involved in various legal proceedings in the ordinary course of business. These proceedings are subject to the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters, and we believe that the ultimate disposition of such proceedings will not have a material adverse effect on our financial position, results of operations or cash flows. Colorado Clean Water Act Referral Notice In September 2018, we received a letter from the Department of Justice (DOJ) requesting an opportunity to discuss settlement of alleged Clean Water Act violations at an upstream production facility and a midstream gathering facility in Weld County, Colorado. In April 2019, we met with the DOJ and Environmental Protection Agency enforcement personnel to discuss potential settlement of the alleged violations. Given the ongoing status of settlement discussions, we are currently unable to predict the ultimate outcome of this action, but believe the resolution will not have a material adverse effect on our financial position, results of operations or cash flows. |
Income Taxes
Income Taxes | 6 Months Ended |
Jun. 30, 2019 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Note 11. Income Taxes Income tax expense (benefit) consists of the following: Three Months Ended June 30, Six Months Ended June 30, (millions, except percentages) 2019 2018 2019 2018 Current $ 21 $ 23 $ 37 $ 149 Deferred (1 ) (7 ) (101 ) (164 ) Total Income Tax Expense (Benefit) $ 20 $ 16 $ (64 ) $ (15 ) Effective Tax Rate 71.4 % 160.0 % 18.6 % (2.7 )% Effective Tax Rate (ETR) At the end of each interim period, we apply a forecasted annualized ETR to current period earnings or loss before tax, which can produce interim ETR fluctuations. The ETR for the six months ended June 30, 2019 varied as compared with 2018 , primarily due to a $145 million discrete tax benefit recorded in 2018 as a result of the intent of the US Department of the Treasury and Internal Revenue Service to issue additional regulatory guidance associated with the Tax Cuts and Jobs Act and the transition tax. In addition, current tax expense for the six months ended June 30, 2018 includes foreign taxes related to a gain on the 2018 divestiture of a 7.5% interest in the Tamar field. In our major tax jurisdictions, the earliest years remaining open to examination are as follows: US – 2014 , Israel – 2015 (2013 with respect to Israel Oil Profits Tax) and Equatorial Guinea – 2013 . |
Derivative Instruments and Hedg
Derivative Instruments and Hedging Activities | 6 Months Ended |
Jun. 30, 2019 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Instruments and Hedging Activities | Note 12. Derivative Instruments and Hedging Activities Objective and Strategies for Using Derivative Instruments We enter into crude oil and natural gas price hedging arrangements in an effort to mitigate the effects of commodity price volatility and enhance the predictability of cash flows for a portion of our crude oil and natural gas production. While these instruments mitigate the cash flow risk of future decreases in commodity prices, they may also curtail benefits from future increases in commodity prices. Unsettled Commodity Derivative Instruments As of June 30, 2019 , the following crude oil derivative contracts were outstanding: Swaps Collars Settlement Period Type of Contract Index Bbls Per Day Weighted Average Differential Weighted Average Fixed Price Weighted Average Short Put Price Weighted Average Floor Price Weighted Average Ceiling Price 2019 Swaps NYMEX WTI 28,000 $ — $ 58.70 $ — $ — $ — 2019 Three-Way Collars NYMEX WTI 33,000 — — 49.35 59.35 72.25 2019 Sold Calls (1) NYMEX WTI 20,000 — 60.00 — — — 2019 Swaps ICE Brent 5,000 — 57.00 — — — 2019 Three-Way Collars ICE Brent 3,000 — — 43.00 50.00 64.07 2019 Basis Swaps (2) 27,000 (3.23 ) — — — — 2020 Swaption NYMEX WTI 5,000 — 61.79 — — — 2020 Swaps NYMEX WTI 7,000 — 60.00 — — — 2020 Three-Way Collars NYMEX WTI 30,000 — — 48.33 57.87 64.27 2020 Basis Swaps (2) 15,000 (5.01 ) — — — — (1) We entered into crude oil contracts receiving premiums for establishing a maximum price that would be settled for the notional volumes covered by the respective contracts. (2) We entered into crude oil basis swap contracts to establish a fixed amount for the differential between pricing in Midland, Texas, and Cushing, Oklahoma. The weighted average differential represents the amount of reduction to Cushing, Oklahoma prices for the notional volumes covered by the basis swap contracts. As of June 30, 2019 , the following natural gas derivative contracts were outstanding: Swaps Collars Settlement Period Type of Contract Index MMBtu Per Day Weighted Average Differential Weighted Average Fixed Price Weighted Average Short Put Price Weighted Average Floor Price Weighted Average Ceiling Price 2019 Three-Way Collars NYMEX HH 104,000 $ — $ — $ 2.25 $ 2.65 $ 2.95 2019 Swaps NYMEX HH 46,000 — 3.00 — — — 2019 Basis Swaps CIG (1) 123,500 (0.64 ) — — — — 2019 Basis Swaps WAHA (1) 47,500 (1.28 ) — — — — 2020 Basis Swaps CIG (1) 54,000 (0.61 ) — — — — 2020 Basis Swaps WAHA (1) 49,500 (1.05 ) — — — — (1) We entered into natural gas basis swap contracts to establish a fixed amount for the differential between the noted index pricing and NYMEX Henry Hub. The weighted average differential represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes covered by the basis swap contracts. Fair Value Amounts The fair values of commodity derivative instruments in our consolidated balance sheets were as follows: Asset Derivative Instruments Liability Derivative Instruments (millions) Balance Sheet Location June 30, 2019 December 31, 2018 Balance Sheet Location June 30, 2019 December 31, 2018 Commodity Derivative Instruments Other Current Assets $ 30 $ 180 Other Current Liabilities $ 42 $ 1 Other Noncurrent Assets 11 — Other Noncurrent Liabilities 13 26 Total $ 41 $ 180 $ 55 $ 27 See Note 13. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of our derivative instruments. Gains and Losses on Commodity Derivative Instruments The effect of commodity derivative instruments on our consolidated statements of operations and comprehensive income was as follows: Three Months Ended June 30, Six Months Ended June 30, (millions) 2019 2018 2019 2018 Cash (Received) Paid in Settlement of Commodity Derivative Instruments Crude Oil $ 7 $ 66 $ (2 ) $ 96 Natural Gas (8 ) (1 ) (13 ) (3 ) Total Cash (Received) Paid in Settlement of Commodity Derivative Instruments (1 ) 65 (15 ) 93 Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments Crude Oil (54 ) 181 169 231 Natural Gas (5 ) 3 (2 ) 4 Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments (59 ) 184 167 235 Loss (Gain) on Commodity Derivative Instruments Crude Oil (47 ) 247 167 327 Natural Gas (13 ) 2 (15 ) 1 Total (Gain) Loss on Commodity Derivative Instruments $ (60 ) $ 249 $ 152 $ 328 |
Fair Value Measurements and Dis
Fair Value Measurements and Disclosures | 6 Months Ended |
Jun. 30, 2019 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements and Disclosures | Note 13. Fair Value Measurements and Disclosures Assets and Liabilities Measured at Fair Value on a Recurring Basis Cash and Cash Equivalents, Accounts Receivable and Accounts Payable The carrying amounts approximate fair value due to the short-term nature or maturity of the instruments. Mutual Fund Investments Our mutual fund investments consist of various publicly-traded mutual funds that include investments ranging from equities to money market instruments. Fair values are based on quoted market prices for identical assets. Commodity Derivative Instruments We estimate the fair values of our derivative instruments using published forward commodity price curves as of the date of the estimate. The discount rate used in the cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates. In addition, for collars, we estimate the values of put options sold and contract floors and ceilings using an option pricing model which considers market volatility, market prices and contract terms. See Note 12. Derivative Instruments and Hedging Activities . Deferred Compensation Liability Fair value is dependent upon the fair values of mutual fund investments and shares of our common stock held in a rabbi trust. See Mutual Fund Investments, above . Stock-Based Compensation Liability A portion of the value of the liability associated with our phantom unit plan is dependent upon the fair value of Noble Energy common stock at the end of each reporting period. Measurement information for assets and liabilities measured at fair value on a recurring basis is as follows: Fair Value Measurements Using (millions) Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Adjustment (1) Fair Value Measurement June 30, 2019 Financial Assets: Mutual Fund Investments $ 42 $ — $ — $ — $ 42 Commodity Derivative Instruments — 63 — (22 ) 41 Financial Liabilities: Commodity Derivative Instruments — (77 ) — 22 (55 ) Portion of Deferred Compensation Liability Measured at Fair Value (48 ) — — — (48 ) Stock Based Compensation Liability Measured at Fair Value (2 ) — — — (2 ) December 31, 2018 Financial Assets: Mutual Fund Investments $ 38 $ — $ — $ — $ 38 Commodity Derivative Instruments — 187 — (7 ) 180 Financial Liabilities: Commodity Derivative Instruments — (34 ) — 7 (27 ) Portion of Deferred Compensation Liability Measured at Fair Value (43 ) — — — (43 ) Stock Based Compensation Liability Measured at Fair Value (8 ) — — — (8 ) (1) Amount represents the impact of netting provisions within our master agreements allowing us to net cash settled asset and liability positions with the same counterparty. Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Firm Transportation Exit Cost Accrual In January 2019, we recorded a firm transportation exit cost liability at fair value of $92 million, representing the discounted present value of our remaining obligation under a permanent pipeline capacity assignment in the Marcellus Shale. See Note 9. Exit Cost – Transportation Commitments . Redeemable Noncontrolling Interest In March 2019, we recorded redeemable noncontrolling interest associated with the issuance of GIP preferred equity at fair value of $97 million , including issuance date proceeds of $100 million netted with associated issuance costs of $3 million . See Note 2. Basis of Presentation . Additional Fair Value Disclosures Debt The fair value of fixed-rate, public debt is estimated based on published market prices. As such, we consider the fair value of this debt to be a Level 1 measurement on the fair value hierarchy. Our non-public debt, including our Revolving Credit Facility, Noble Midstream Services Revolving Credit Facility, Noble Midstream Services Term Loan Credit Facility and commercial paper borrowings, are subject to variable interest rates. The fair value is estimated based on significant other observable inputs; thus, we consider the fair values to be Level 2 measurements on the fair value hierarchy. See Note 7. Debt . Fair value information regarding our debt is as follows: June 30, 2019 December 31, 2018 (millions) Carrying Amount Fair Value (1) Carrying Amount Fair Value Debt (2) $ 6,994 $ 7,465 $ 6,452 $ 6,121 (1) As of June 30, 2019 , the difference between the carrying amount and fair value is primarily due to low US treasury rates. (2) Excludes unamortized discount, debt issuance costs and finance lease obligations. See Note 8. Leases . |
Net (Loss) Income Per Share Att
Net (Loss) Income Per Share Attributable to Noble Energy Common Shareholders | 6 Months Ended |
Jun. 30, 2019 | |
Earnings Per Share [Abstract] | |
Net (Loss) Income Per Share Attributable to Noble Energy Common Shareholders | Note 14. Net (Loss) Income Per Share Attributable to Noble Energy Common Shareholders Noble Energy's basic (loss) income per share of common stock is computed by dividing net (loss) income attributable to Noble Energy by the weighted average number of shares of Noble Energy common stock outstanding during each period. The following table summarizes the calculation of basic and diluted (loss) income per share: Three Months Ended June 30, Six Months Ended June 30, (millions, except per share amounts) 2019 2018 2019 2018 Net (Loss) Income and Comprehensive (Loss) Income Attributable to Noble Energy $ (10 ) $ (23 ) $ (323 ) $ 531 Weighted Average Number of Shares Outstanding, Basic (1) 478 484 478 485 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 478 484 478 487 (Loss) Income Per Share, Basic $ (0.02 ) $ (0.05 ) $ (0.68 ) $ 1.09 (Loss) Income Per Share, Diluted $ (0.02 ) $ (0.05 ) $ (0.68 ) $ 1.09 Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above 15 14 15 14 (1) Decrease in weighted average number of shares outstanding reflects the impact of Noble Energy common stock repurchased in 2018 pursuant to our $750 million share repurchase program. |
Basis of Presentation (Policies
Basis of Presentation (Policies) | 6 Months Ended |
Jun. 30, 2019 | |
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, 2019 and December 31, 2018 and for the three and six months ended June 30, 2019 and 2018 contain all normally recurring adjustments considered necessary for a fair presentation of our financial position, results of operations, cash flows and equity for such periods. Certain prior-period amounts have been reclassified to conform to the current period presentation. For the periods presented, net income or loss is materially consistent with comprehensive income or loss. Operating results for the three and six months ended June 30, 2019 are not necessarily indicative of the results that may be expected for the year ending December 31, 2019 . These consolidated financial statements should be read in conjunction with the consolidated financial statements and accompanying notes included in our Annual Report on Form 10-K for the year ended December 31, 2018 . |
Consolidation | Consolidation Our consolidated financial statements include our accounts, the accounts of subsidiaries which Noble Energy wholly owns, and the accounts of Noble Midstream Partners LP (Noble Midstream Partners), which is considered a variable interest entity (VIE) for which Noble Energy is the primary beneficiary. In addition, we use the equity method of accounting for investments in entities that we do not control, but over which we exert significant influence. All significant intercompany balances and transactions have been eliminated upon consolidation. |
Estimates | 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. |
Partner Advances | Partner Advances Partner advances consist of cash advances from certain of our Eastern Mediterranean field partners pending allocation of capacity in the EMG Pipeline owned by Eastern Mediterranean Gas Company S.A.E (EMG) and pending closing of the planned acquisition of EMG, which is expected to occur in third quarter 2019. The EMG Pipeline is expected to provide future connection from the Israel pipeline network to Egyptian customers. The acquisition of the equity interest in EMG is expected to support delivery of natural gas from our producing fields offshore Israel into Egypt. The cash advances received are reported within restricted cash in our consolidated balance sheets. |
Leases | Leases We determine whether an arrangement contains a lease based on the conveyed rights and obligations at the inception date. If an agreement contains an operating or financing lease, at the commencement date, we record a right-of-use (ROU) asset and a corresponding lease liability based on the present value of the minimum lease payments. As most of our leases do not provide an implicit borrowing rate, to determine the present value of lease payments, we use our hypothetical secured borrowing rate based on information available at lease commencement. Further, we make certain estimates and judgments regarding the lease term and lease payments, noted below. Lease Term Leases with an initial term of 12 months or less are not recorded on the balance sheet and we recognize lease expense for these leases on a straight-line basis over the lease term. Most leases include one or more options to renew, with renewal terms that can extend the lease term from one month to one year or more. Additionally, some of our leases include an option for early termination. We include renewal periods and exclude termination periods from our lease term if, at commencement, it is reasonably likely that we will exercise the option. Lease Payments Certain of our lease agreements include rental payments that are adjusted periodically for inflation or passage of time. These step payments are included within our present value calculation as they are known adjustments at commencement. Some of our lease agreements include variable payments that are excluded from our present value calculation. For example, drilling rig ROU assets and lease liabilities are recorded using the contractual standby rate, which is the fixed, minimum monthly payment, as opposed to the operating rate, which varies depending on the asset's use. Additionally, we have lease agreements that include lease and non-lease components, such as equipment maintenance, which are generally accounted for as a single lease component. For these leases, lease payments include all fixed payments stated within the contract. For office space, lease and non-lease components are accounted for separately. Our lease agreements do not contain any material residual value guarantees that would impact our lease payments. |
Revenue Recognition | Revenue Recognition We recognize revenue at an amount that reflects the consideration we expect to be entitled to in exchange for transferring goods or services to a customer, using a five-step process, in accordance with ASC 606 – Revenue from Contracts with Customers (ASC 606). |
Redeemable Noncontrolling Interest | Redeemable Noncontrolling Interest In March 2019 , Noble Midstream Partners secured a $200 million equity commitment (preferred equity) from GIP CAPS Dos Rios Holding Partnership, L.P. (GIP) to fund capital contributions in connection with Noble Midstream Partners’ 30% equity investment in EPIC Crude Holdings, LP (EPIC Crude Holdings). GIP funded $100 million of the commitment, with associated offering costs of $3 million , and the remaining $100 million is available for a one-year period, subject to certain conditions precedent. The preferred equity is perpetual and has a 6.5% annual dividend rate, payable quarterly in cash, with the ability to defer payment during the first two years following the closing. Noble Midstream Partners can redeem the preferred equity in whole or in part at any time for cash at a predetermined redemption price. GIP can request redemption of the preferred equity following the later of the sixth anniversary of the preferred equity closing or the fifth anniversary of the EPIC crude oil pipeline completion date at a pre-determined base return. |
Recently Issued and Recently Adopted Accounting Standards | Recently Issued Accounting Standards Financial Instruments: Credit Losses In June 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2016-13 (ASU 2016-13): Financial Instruments – Credit Losses , which replaces the incurred loss impairment methodology used for certain financial instruments with a methodology that reflects current expected credit losses. The current expected credit loss (CECL) model applies to a broad scope of financial instruments, including financial assets measured at amortized cost. CECL also applies to off-balance sheet credit exposures not accounted for as insurance, such as financial guarantees and other unfunded loan commitments. ASU 2016-13 is effective for fiscal years beginning after December 15, 2019, with early adoption permitted, and shall be applied using a modified retrospective approach through a cumulative-effect adjustment to retained earnings as of the beginning of the adoption period. The FASB subsequently issued Accounting Standards Update No. 2019-04 (ASU 2019-04): Codification Improvements to Topic 326, Financial Instruments-Credit Losses, Topic 815, Derivatives, and Topic 825, Financial Instruments and Accounting Standards Update No. 2019-05 (ASU 2019-05): Financial Instruments-Credit Losses (Topic 326)-Targeted Transition Relief . ASU 2019-04 and ASU 2019-05 provide certain codification improvements related to CECL implementation and targeted transition relief consisting of an option to irrevocably elect the fair value option for eligible instruments. 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 will not be significant. As such, we do not believe adoption of the standard will have a material impact on our financial statements. We have developed and are executing an implementation plan, which includes data collection, contract review and assessment, and evaluation of our systems, processes and internal controls. We will continue to monitor changes in our credit portfolio and off-balance sheet exposures as our implementation plan progresses. Recently Adopted Accounting Standards Leases In February 2016, the FASB issued Accounting Standards Update No. 2016-02 (ASU 2016-02), which created Topic 842 – Leases (ASC 842). The standard requires lessees to recognize a ROU asset and lease liability on the balance sheet for the rights and obligations created by leases. ASC 842 also requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. This standard does not apply to leases to explore for or use minerals, oil, natural gas or similar nonregenerative resources, including the intangible right to explore for those resources and rights to use the land in which those natural resources are contained. The new standard provided a number of optional practical expedients. We elected: • the package of transition “practical expedients”, permitting us not to reassess our prior conclusions about lease identification, lease classification and initial direct costs; • the practical expedient pertaining to land easements, allowing us to account for existing land easements under previous accounting policy; and • the practical expedient to not separate lease and non-lease components for the majority of our leases (elected by asset class). We adopted ASC 842 on January 1, 2019 using the modified retrospective method and, therefore, prior period financial statements were not adjusted. At adoption, we recorded ROU assets and lease liabilities of $282 million and $287 million , respectively, primarily related to operating leases. The difference between amounts recorded for ROU assets and amounts recorded for lease liabilities totaled $5 million . This amount was recognized as other operating expense. Our accounting for finance leases remains substantially unchanged. Adoption did not materially impact our consolidated statement of operations and comprehensive income and had no impact on our consolidated statement of cash flows. See Note 8. Leases . Derivatives and Hedging – Targeted Improvements to Accounting for Hedging Activities In August 2017, the FASB issued Accounting Standards Update No. 2017-12 (ASU 2017-12): Derivatives and Hedging – Targeted Improvements to Accounting for Hedging Activities. The update is intended to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. 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. We adopted this ASU on January 1, 2019. The adoption did not have an impact on our financial statements. Intangibles—Goodwill and Other—Internal-Use Software In August 2018, the FASB issued Accounting Standards Update No. 2018-15 (ASU 2018-15): Intangibles—Goodwill and Other—Internal-Use Software, |
Basis of Presentation (Tables)
Basis of Presentation (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | The following table includes estimated revenues, as of June 30, 2019 , for those agreements. Our actual future sales volumes may exceed future minimum volume commitments. (millions) Remainder of 2019 2020 Total Natural Gas Revenues (1) $ 72 $ 116 $ 188 (1) |
Statement of Operations Information | Other statements of operations information is as follows: Three Months Ended June 30, Six Months Ended June 30, (millions) 2019 2018 2019 2018 Other Revenue Income from Equity Method Investees and Other $ 16 $ 49 $ 33 $ 96 Midstream Services Revenues – Third Party 20 15 44 28 Total $ 36 $ 64 $ 77 $ 124 Production Expense Lease Operating Expense $ 122 $ 132 $ 273 $ 287 Production and Ad Valorem Taxes 41 50 90 104 Gathering, Transportation and Processing Expense 96 98 198 191 Other Royalty Expense 1 10 4 27 Total $ 260 $ 290 $ 565 $ 609 Other Operating Expense, Net Exploration Expense $ 33 $ 29 $ 57 $ 64 Marketing Expense 14 9 19 16 Other, Net 8 (4 ) 28 4 Total $ 55 $ 34 $ 104 $ 84 |
Balance Sheet Information Table | Other balance sheet information is as follows: (millions) June 30, December 31, Accounts Receivable, Net Commodity Sales $ 346 $ 383 Joint Interest Billings 153 137 Other 91 111 Allowance for Doubtful Accounts (15 ) (15 ) Total $ 575 $ 616 Other Current Assets Commodity Derivative Assets $ 30 $ 180 Inventories, Materials and Supplies 68 55 Assets Held for Sale (1) — 133 Restricted Cash (2) 132 3 Prepaid Expenses and Other Current Assets 83 47 Total $ 313 $ 418 Other Noncurrent Assets Equity Method Investments (3) $ 699 $ 286 Operating Lease Right-of-Use Assets (4) 272 — Customer-Related Intangible Assets, Net (5) 294 310 Goodwill (5) 110 110 Other Assets, Noncurrent 141 135 Total $ 1,516 $ 841 Other Current Liabilities Production and Ad Valorem Taxes $ 132 $ 103 Asset Retirement Obligations 85 118 Interest Payable 64 66 Operating Lease Liabilities (4) 88 — Commercial Paper Borrowings 240 — Partner Advances (2) 132 — Other Liabilities, Current 257 232 Total $ 998 $ 519 Other Noncurrent Liabilities Deferred Compensation Liabilities $ 147 $ 147 Asset Retirement Obligations 707 762 Operating Lease Liabilities (4) 190 — Firm Transportation Exit Cost Accrual (6) 144 67 Production and Ad Valorem Taxes 24 83 Other Liabilities, Noncurrent 95 106 Total $ 1,307 $ 1,165 (1) Assets held for sale at December 31, 2018 related to the first quarter 2019 divestiture of non-core acreage in Reeves County, Texas. See Note 4. Acquisitions and Divestitures . (2) See Partner Advances , above. (3) The 2019 amount includes Noble Midstream Partners' $ 369 million investment in EPIC Y-Grade, LP (EPIC Y-Grade) and EPIC Crude Holdings and its $ 39 million investment in Delaware Crossing LLC. See Note 4. Acquisitions and Divestitures . (4) Amounts relate to assets and liabilities recorded as a result of ASC 842 adoption in first quarter 2019. See Note 8. Leases . (5) Amounts relate to assets acquired in the first quarter 2018 Saddle Butte acquisition. Intangible asset balances at June 30, 2019 and December 31, 2018 are net of accumulated amortization of $ 46 million and $30 million , respectively. See Note 4. Acquisitions and Divestitures . (6) See Note 9. Exit Cost – Transportation Commitments . |
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) 2019 2018 Cash and Cash Equivalents at Beginning of Period $ 716 $ 675 Restricted Cash at Beginning of Period 3 38 Cash, Cash Equivalents, and Restricted Cash at Beginning of Period $ 719 $ 713 Cash and Cash Equivalents at End of Period $ 470 $ 621 Restricted Cash at End of Period 132 — Cash, Cash Equivalents, and Restricted Cash at End of Period $ 602 $ 621 |
Segment Information (Tables)
Segment Information (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Segment Reporting [Abstract] | |
Segment Information | Oil and Gas Exploration and Production Midstream (millions) Consolidated United States Eastern Mediter-ranean West Africa Other Int'l United States Intersegment Eliminations and Other (1) Corporate Three Months Ended June 30, 2019 Crude Oil Sales $ 688 $ 617 $ 2 $ 69 $ — $ — $ — $ — NGL Sales 84 84 — — — — — — Natural Gas Sales 182 72 105 5 — — — — Total Crude Oil, NGL and Natural Gas Sales 954 773 107 74 — — — — Sales of Purchased Oil and Gas 103 28 — — — 52 — 23 Income (Loss) from Equity Method Investees and Other 16 1 — 17 — (2 ) — — Midstream Services Revenues – Third Party 20 — — — — 20 — — Intersegment Revenues — — — — — 91 (91 ) — Total Revenues 1,093 802 107 91 — 161 (91 ) 23 Lease Operating Expense 122 114 9 10 — 1 (12 ) — Production and Ad Valorem Taxes 41 40 — — — 1 — — Gathering, Transportation and Processing Expense 96 124 — — — 31 (59 ) — Oil and Gas Exploration and Production Midstream (millions) Consolidated United States Eastern Mediter-ranean West Africa Other Int'l United States Intersegment Eliminations and Other (1) Corporate Other Royalty Expense 1 1 — — — — — — Total Production Expense 260 279 9 10 — 33 (71 ) — Depreciation, Depletion and Amortization 528 457 17 19 — 26 (6 ) 15 Cost of Purchased Oil and Gas 113 28 — — — 48 — 37 Gain on Commodity Derivative Instruments (60 ) (58 ) — (2 ) — — — — Income (Loss) Before Income Taxes 28 70 65 59 (15 ) 46 (15 ) (182 ) Additions to Long-Lived Assets, Excluding Acquisitions 647 478 119 12 2 52 (25 ) 9 Investments in Equity Method Investees 144 — — — — 144 — — 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 — — — — Sales of Purchased Oil and Gas 66 — — — — 42 — 24 Income from Equity Method Investees and Other 49 — — 36 — 13 — — Midstream Services Revenues – Third Party 15 — — — — 15 — — Intersegment Revenues — — — — — 85 (85 ) — Total Revenues 1,230 870 113 153 — 155 (85 ) 24 Lease Operating Expense 132 114 5 19 — — (6 ) — Production and Ad Valorem Taxes 50 48 — — — 2 — — Gathering, Transportation and Processing Expense 98 131 — — — 22 (55 ) — Other Royalty Expense 10 10 — — — — — — Total Production Expense 290 303 5 19 — 24 (61 ) — Depreciation, Depletion and Amortization 465 394 15 26 — 22 (4 ) 12 (Gain) Loss on Divestitures, Net (78 ) 21 10 — — (109 ) — — Cost of Purchased Oil and Gas 71 — — — — 40 — 31 Loss on Commodity Derivative Instruments 249 196 — 53 — — — — Income (Loss) Before Income Taxes 10 (90 ) 62 48 (13 ) 175 (18 ) (154 ) Additions to Long-Lived Assets, Excluding Acquisitions 935 561 216 3 — 155 (18 ) 18 Six Months Ended June 30, 2019 Crude Oil Sales $ 1,300 $ 1,162 $ 3 $ 135 $ — $ — $ — $ — NGL Sales 180 180 — — — — — — Natural Gas Sales 411 180 222 9 — — — — Oil and Gas Exploration and Production Midstream (millions) Consolidated United States Eastern Mediter-ranean West Africa Other Int'l United States Intersegment Eliminations and Other (1) Corporate Total Crude Oil, NGL and Natural Gas Sales 1,891 1,522 225 144 — — — — Sales of Purchased Oil and Gas 177 42 — — — 85 — 50 Income from Equity Method Investees and Other 33 1 — 32 — — — — Midstream Services Revenues – Third Party 44 — — — — 44 — — Intersegment Revenues — — — — — 197 (197 ) Total Revenues 2,145 1,565 225 176 — 326 (197 ) 50 Lease Operating Expense 273 239 19 34 — 2 (21 ) — Production and Ad Valorem Taxes 90 87 — — — 3 — — Gathering, Transportation and Processing Expense 198 266 — — — 60 (128 ) — Other Royalty Expense 4 4 — — — — — — Total Production Expense 565 596 19 34 — 65 (149 ) — Depreciation, Depletion and Amortization 1,036 896 33 39 — 51 (13 ) 30 Cost of Purchased Oil and Gas 200 42 — — — 79 — 79 Firm Transportation Exit Cost 92 — — — — — — 92 Loss on Commodity Derivative Instruments 152 130 — 22 — — — — (Loss) Income Before Income Taxes (345 ) (177 ) 149 70 (31 ) 119 (29 ) (446 ) Additions to Long-Lived Assets, Excluding Acquisitions 1,359 990 251 18 12 118 (48 ) 18 Investments in Equity Method Investees 415 — — — — 415 — — 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 — — — — Sales of Purchased Oil and Gas 119 — — — — 64 — 55 Income from Equity Method Investees and Other 96 — — 71 — 25 — — Midstream Services Revenues – Third Party 28 — — — — 28 — — Intersegment Revenues — — — — — 166 (166 ) — Total Revenues 2,516 1,818 244 282 — 283 (166 ) 55 Lease Operating Expense 287 240 12 41 — — (6 ) — Production and Ad Valorem Taxes 104 101 — — — 3 — — Gathering, Transportation and Processing Expense 191 256 — — — 43 (108 ) — Other Royalty Expense 27 27 — — — — — — Total Production Expense 609 624 12 41 — 46 (114 ) — Oil and Gas Exploration and Production Midstream (millions) Consolidated United States Eastern Mediter-ranean West Africa Other Int'l United States Intersegment Eliminations and Other (1) Corporate Depreciation, Depletion and Amortization 933 800 28 52 — 38 (8 ) 23 (Gain) Loss on Divestitures, Net (666 ) 15 (376 ) — — (305 ) — — Asset Impairments 168 168 — — — — — — Cost of Purchased Oil and Gas 128 — — — — 61 — 67 Loss on Commodity Derivative Instruments 328 260 — 68 — — — — Income (Loss) Before Income Taxes 553 (127 ) 535 112 (27 ) 428 (40 ) (328 ) Additions to Long-Lived Assets, Excluding Acquisitions 1,840 1,095 363 5 2 397 (50 ) 28 June 30, 2019 Property, Plant and Equipment, Net $ 18,775 $ 13,095 $ 2,879 $ 773 $ 36 $ 1,841 $ (185 ) $ 336 December 31, 2018 Property, Plant and Equipment, Net $ 18,419 $ 13,044 $ 2,630 $ 805 $ 37 $ 1,742 $ (145 ) $ 306 (1) The intersegment eliminations related to income 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. |
Capitalized Exploratory Well _2
Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Extractive Industries [Abstract] | |
Aging of Capitalized Well Costs | The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced: (millions, except number of projects) June 30, December 31, Exploratory Well Costs Capitalized for a Period of One Year or Less $ 11 $ 6 Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling 351 348 Capitalized Exploratory Well Costs, End of Period $ 362 $ 354 Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling 7 7 |
Rollforward of Undeveloped Lease Costs | Changes in undeveloped leasehold costs were as follows: (millions) Six Months Ended June 30, 2019 Undeveloped Leasehold Costs, Beginning of Period $ 2,306 Additions to Undeveloped Leasehold Costs 50 Transfers to Proved Properties (11 ) Assets Sold (2 ) Undeveloped Leasehold Costs, End of Period $ 2,343 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Changes in Asset Retirement Obligations | Changes in ARO are as follows: Six Months Ended June 30, (millions) 2019 2018 Asset Retirement Obligations, Beginning Balance $ 880 $ 875 Liabilities Incurred 15 14 Liabilities Settled (56 ) (261 ) Revisions of Estimates (70 ) (10 ) Accretion Expense 23 17 Asset Retirement Obligations, Ending Balance $ 792 $ 635 |
Debt (Tables)
Debt (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Debt Disclosure [Abstract] | |
Schedule of Debt | Debt consists of the following: June 30, 2019 December 31, 2018 (millions, except percentages) Debt Interest Rate Debt Interest Rate Noble Energy, Excluding Noble Midstream Partners Revolving Credit Facility, due March 9, 2023 $ — — % $ — — % Commercial Paper Borrowings 240 (1 ) — — % Senior Notes and Debentures 5,884 (2 ) 5,892 (2 ) Finance Lease Obligations 211 — % 223 — % Total Noble Energy Debt, Excluding Noble Midstream Partners Debt 6,335 6,115 Noble Midstream Partners Noble Midstream Services Revolving Credit Facility, due March 9, 2023 (3) 370 3.77 % 60 3.67 % Noble Midstream Services Term Loan Credit Facility, due July 31, 2021 500 3.51 % 500 3.42 % Total Noble Midstream Partners Debt 870 560 Total Debt 7,205 6,675 Net Unamortized Discounts and Debt Issuance Costs (58 ) (60 ) Total Debt, Net of Unamortized Discounts and Debt Issuance Costs 7,147 6,615 Less Amounts Due Within One Year Commercial Paper Borrowings (240 ) — Finance Lease Obligations (41 ) (41 ) Long-Term Debt Due After One Year $ 6,866 $ 6,574 (1) As of June 30, 2019 , the weighted average interest rate for outstanding commercial paper was 3.04% . (2) As of June 30, 2019 and December 31, 2018 , the Senior Notes and Debentures had weighted average interest rates of 5.00% and 5.01% , respectively. (3) As of June 30, 2019 and December 31, 2018 , the Noble Midstream Services Revolving Credit Facility had $ 800 million of capacity. Amounts available for borrowing totaled $ 430 million and $ 740 million, respectively. |
Leases (Tables)
Leases (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Leases [Abstract] | |
Summary of Operating and Finance Lease | ROU assets and lease liabilities ar e as follows: (millions) Balance Sheet Location June 30, 2019 ROU Assets Operating Leases (1) Other Noncurrent Assets $ 272 Finance Leases (2) Total Property, Plant and Equipment, Net 175 Total ROU Assets $ 447 Lease Liabilities Current Liabilities Operating Leases Other Current Liabilities $ 88 Finance Leases Other Current Liabilities 41 Noncurrent Liabilities Operating Leases Other Noncurrent Liabilities 190 Finance Leases Long-Term Debt 170 Total Lease Liabilities $ 489 (1) Operating lease ROU assets include primarily office space of $117 million , compressors of $88 million , and drilling rigs of $35 million . (2) Finance lease ROU assets include primarily office space of $94 million , net of accumulated amortization. Other information related to our leases is as follows: June 30, 2019 Weighted-Average Remaining Lease Term Operating Leases 5.9 years Finance Leases 7.9 years Weighted-Average Discount Rate Operating Leases 4.40 % Finance Leases 5.01 % |
Lease Expense | The components of lease cost are as follows: (millions) Statement of Operations Location Three Months Ended June 30, 2019 Six Months Ended June 30, 2019 Operating Lease Cost (1) $ 26 $ 51 Finance Lease Cost Amortization Expense Depreciation, Depletion and Amortization 9 17 Interest Expense Interest, Net of Amount Capitalized 4 7 Short-term Lease Cost (2) (1) 143 269 Variable Lease Cost (3) (1) — — Sublease Income General and Administrative (1 ) (2 ) Total Lease Cost $ 181 $ 342 (1) Cost classification varies depending on the leased asset. Costs are primarily included within production expense and general and administrative expense. In addition, in accordance with the successful efforts method of accounting, certain lease costs may be capitalized when incurred, as part of oil and gas properties on our consolidated balance sheet. (2) Short-term lease costs relate primarily to hydraulic fracturing services, well-to-well drilling rig contracts and other miscellaneous lease agreements. Amount excludes costs for leases with an initial term of one month or less. (3) Variable lease costs were de minimis for second quarter and the first six months of 2019 |
Supplemental Cash Flow Information | Supplemental cash flow information is as follows: Six Months Ended June 30, 2019 (millions) Operating Leases Finance Leases Cash Paid for Amounts Included in the Measurement of Lease Liabilities Operating Cash Flows $ 30 $ 6 Financing Cash Flows — 20 Investing Cash Flows 18 — ROU Assets Obtained in Exchange for Lease Liabilities (1) 58 8 (1) Amounts exclude the impact of adopting ASC 842 on January 1, 2019. See Note 2. Basis of Presentation . |
Operating Lease Liability Maturity | Maturities of lease liabilities as of June 30, 2019 are as follows: (millions) Operating Leases Finance Leases Total Remainder of 2019 $ 50 $ 25 $ 75 2020 85 48 133 2021 48 33 81 2022 33 23 56 2023 21 21 42 2024 and Thereafter 80 105 185 Total Lease Liabilities, Undiscounted 317 255 572 Less: Imputed Interest 39 44 83 Total Lease Liabilities (1) $ 278 $ 211 $ 489 (1) Includes the current portions of $ 88 million and $ 41 |
Finance Lease Liability Maturity | Maturities of lease liabilities as of June 30, 2019 are as follows: (millions) Operating Leases Finance Leases Total Remainder of 2019 $ 50 $ 25 $ 75 2020 85 48 133 2021 48 33 81 2022 33 23 56 2023 21 21 42 2024 and Thereafter 80 105 185 Total Lease Liabilities, Undiscounted 317 255 572 Less: Imputed Interest 39 44 83 Total Lease Liabilities (1) $ 278 $ 211 $ 489 (1) Includes the current portions of $ 88 million and $ 41 |
Schedule of Future Minimum Rental Payments for Operating Leases | Lease commitments as of December 31, 2018 were as follows: (millions) Operating Leases Finance Leases Total 2019 $ 91 $ 52 $ 143 2020 74 46 120 2021 59 31 90 2022 62 22 84 2023 50 20 70 2024 and Thereafter 176 104 280 Total Lease Liabilities, Undiscounted $ 512 $ 275 $ 787 |
Schedule of Future Minimum Lease Payments for Finance Leases | Lease commitments as of December 31, 2018 were as follows: (millions) Operating Leases Finance Leases Total 2019 $ 91 $ 52 $ 143 2020 74 46 120 2021 59 31 90 2022 62 22 84 2023 50 20 70 2024 and Thereafter 176 104 280 Total Lease Liabilities, Undiscounted $ 512 $ 275 $ 787 |
Exit Costs - Transportation C_2
Exit Costs - Transportation Commitments (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Commitments and Contingencies Disclosure [Abstract] | |
Rollforward of Accrued Transportation Commitment | In addition to the retained firm transportation commitments, we have the following accrued discounted liabilities associated with exit cost activities, including the permanent assignment described above: Six Months Ended June 30, (millions) 2019 2018 Balance at Beginning of Period (1) $ 80 $ 90 Firm Transportation Exit Cost Accrual 92 — Payments, Net of Accretion (5 ) (7 ) Balance at End of Period 167 83 Less: Current Portion Included in Other Current Liabilities 23 12 Long-term Portion Included in Other Noncurrent Liabilities $ 144 $ 71 (1) Amounts include the current portion of $13 million which is included in other current liabilities in our consolidated balance sheets. Revenues and expenses associated with capacity release agreements and purchases and sales of natural gas are as follows: Three Months Ended June 30, Six Months Ended June 30, (millions) 2019 2018 2019 2018 Sales of Purchased Gas (1) $ 23 $ 24 $ 50 $ 55 Cost of Purchased Gas and Related Expense Cost of Purchased of Gas 22 23 49 53 Utilized Firm Transportation Expense (2) 15 6 30 11 Unutilized Firm Transportation Expense — 2 — 3 Cost of Purchased Gas and Related Expense, Total (3) $ 37 $ 31 $ 79 $ 67 (1) Amounts are included in sales of purchased oil and gas within our statements of operations. (2) Includes the net impact of the difference in the firm transportation contract rates and rates agreed to in the capacity releases, as well as transportation expenses associated with transport of purchased natural gas. (3) |
Income Taxes (Tables)
Income Taxes (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Income Tax Disclosure [Abstract] | |
Income Tax Provision (Benefit) | Income tax expense (benefit) consists of the following: Three Months Ended June 30, Six Months Ended June 30, (millions, except percentages) 2019 2018 2019 2018 Current $ 21 $ 23 $ 37 $ 149 Deferred (1 ) (7 ) (101 ) (164 ) Total Income Tax Expense (Benefit) $ 20 $ 16 $ (64 ) $ (15 ) Effective Tax Rate 71.4 % 160.0 % 18.6 % (2.7 )% |
Derivative Instruments and He_2
Derivative Instruments and Hedging Activities (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Unsettled Derivative Instruments | As of June 30, 2019 , the following crude oil derivative contracts were outstanding: Swaps Collars Settlement Period Type of Contract Index Bbls Per Day Weighted Average Differential Weighted Average Fixed Price Weighted Average Short Put Price Weighted Average Floor Price Weighted Average Ceiling Price 2019 Swaps NYMEX WTI 28,000 $ — $ 58.70 $ — $ — $ — 2019 Three-Way Collars NYMEX WTI 33,000 — — 49.35 59.35 72.25 2019 Sold Calls (1) NYMEX WTI 20,000 — 60.00 — — — 2019 Swaps ICE Brent 5,000 — 57.00 — — — 2019 Three-Way Collars ICE Brent 3,000 — — 43.00 50.00 64.07 2019 Basis Swaps (2) 27,000 (3.23 ) — — — — 2020 Swaption NYMEX WTI 5,000 — 61.79 — — — 2020 Swaps NYMEX WTI 7,000 — 60.00 — — — 2020 Three-Way Collars NYMEX WTI 30,000 — — 48.33 57.87 64.27 2020 Basis Swaps (2) 15,000 (5.01 ) — — — — (1) We entered into crude oil contracts receiving premiums for establishing a maximum price that would be settled for the notional volumes covered by the respective contracts. (2) We entered into crude oil basis swap contracts to establish a fixed amount for the differential between pricing in Midland, Texas, and Cushing, Oklahoma. The weighted average differential represents the amount of reduction to Cushing, Oklahoma prices for the notional volumes covered by the basis swap contracts. As of June 30, 2019 , the following natural gas derivative contracts were outstanding: Swaps Collars Settlement Period Type of Contract Index MMBtu Per Day Weighted Average Differential Weighted Average Fixed Price Weighted Average Short Put Price Weighted Average Floor Price Weighted Average Ceiling Price 2019 Three-Way Collars NYMEX HH 104,000 $ — $ — $ 2.25 $ 2.65 $ 2.95 2019 Swaps NYMEX HH 46,000 — 3.00 — — — 2019 Basis Swaps CIG (1) 123,500 (0.64 ) — — — — 2019 Basis Swaps WAHA (1) 47,500 (1.28 ) — — — — 2020 Basis Swaps CIG (1) 54,000 (0.61 ) — — — — 2020 Basis Swaps WAHA (1) 49,500 (1.05 ) — — — — (1) We entered into natural gas basis swap contracts to establish a fixed amount for the differential between the noted index pricing and NYMEX Henry Hub. The weighted average differential represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes covered by the basis swap contracts. |
Fair Value of Derivative Instruments | The fair values of commodity derivative instruments in our consolidated balance sheets were as follows: Asset Derivative Instruments Liability Derivative Instruments (millions) Balance Sheet Location June 30, 2019 December 31, 2018 Balance Sheet Location June 30, 2019 December 31, 2018 Commodity Derivative Instruments Other Current Assets $ 30 $ 180 Other Current Liabilities $ 42 $ 1 Other Noncurrent Assets 11 — Other Noncurrent Liabilities 13 26 Total $ 41 $ 180 $ 55 $ 27 |
Derivative Instruments, (Gain) Loss | The effect of commodity derivative instruments on our consolidated statements of operations and comprehensive income was as follows: Three Months Ended June 30, Six Months Ended June 30, (millions) 2019 2018 2019 2018 Cash (Received) Paid in Settlement of Commodity Derivative Instruments Crude Oil $ 7 $ 66 $ (2 ) $ 96 Natural Gas (8 ) (1 ) (13 ) (3 ) Total Cash (Received) Paid in Settlement of Commodity Derivative Instruments (1 ) 65 (15 ) 93 Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments Crude Oil (54 ) 181 169 231 Natural Gas (5 ) 3 (2 ) 4 Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments (59 ) 184 167 235 Loss (Gain) on Commodity Derivative Instruments Crude Oil (47 ) 247 167 327 Natural Gas (13 ) 2 (15 ) 1 Total (Gain) Loss on Commodity Derivative Instruments $ (60 ) $ 249 $ 152 $ 328 |
Fair Value Measurements and D_2
Fair Value Measurements and Disclosures (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Fair Value Disclosures [Abstract] | |
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis | Measurement information for assets and liabilities measured at fair value on a recurring basis is as follows: Fair Value Measurements Using (millions) Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Adjustment (1) Fair Value Measurement June 30, 2019 Financial Assets: Mutual Fund Investments $ 42 $ — $ — $ — $ 42 Commodity Derivative Instruments — 63 — (22 ) 41 Financial Liabilities: Commodity Derivative Instruments — (77 ) — 22 (55 ) Portion of Deferred Compensation Liability Measured at Fair Value (48 ) — — — (48 ) Stock Based Compensation Liability Measured at Fair Value (2 ) — — — (2 ) December 31, 2018 Financial Assets: Mutual Fund Investments $ 38 $ — $ — $ — $ 38 Commodity Derivative Instruments — 187 — (7 ) 180 Financial Liabilities: Commodity Derivative Instruments — (34 ) — 7 (27 ) Portion of Deferred Compensation Liability Measured at Fair Value (43 ) — — — (43 ) Stock Based Compensation Liability Measured at Fair Value (8 ) — — — (8 ) (1) Amount represents the impact of netting provisions within our master agreements allowing us to net cash settled asset and liability positions with the same counterparty. |
Additional fair value disclosures | Fair value information regarding our debt is as follows: June 30, 2019 December 31, 2018 (millions) Carrying Amount Fair Value (1) Carrying Amount Fair Value Debt (2) $ 6,994 $ 7,465 $ 6,452 $ 6,121 (1) As of June 30, 2019 , the difference between the carrying amount and fair value is primarily due to low US treasury rates. (2) Excludes unamortized discount, debt issuance costs and finance lease obligations. See Note 8. Leases . |
Net (Loss) Income Per Share A_2
Net (Loss) Income Per Share Attributable to Noble Energy Common Shareholders (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Earnings Per Share [Abstract] | |
Schedule of earnings per share | The following table summarizes the calculation of basic and diluted (loss) income per share: Three Months Ended June 30, Six Months Ended June 30, (millions, except per share amounts) 2019 2018 2019 2018 Net (Loss) Income and Comprehensive (Loss) Income Attributable to Noble Energy $ (10 ) $ (23 ) $ (323 ) $ 531 Weighted Average Number of Shares Outstanding, Basic (1) 478 484 478 485 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 478 484 478 487 (Loss) Income Per Share, Basic $ (0.02 ) $ (0.05 ) $ (0.68 ) $ 1.09 (Loss) Income Per Share, Diluted $ (0.02 ) $ (0.05 ) $ (0.68 ) $ 1.09 Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above 15 14 15 14 (1) Decrease in weighted average number of shares outstanding reflects the impact of Noble Energy common stock repurchased in 2018 pursuant to our $750 million share repurchase program. |
Basis of Presentation - Narrati
Basis of Presentation - Narrative (Details) - USD ($) $ in Millions | Jan. 01, 2019 | Mar. 31, 2019 | Jun. 30, 2019 | Jun. 30, 2018 | Mar. 25, 2019 | Dec. 31, 2018 |
Finite-Lived Intangible Assets [Line Items] | ||||||
Goodwill | $ 110 | $ 110 | ||||
ROU Assets | 272 | $ 0 | ||||
Lease liabilities | 278 | |||||
Proceeds from issuance of preferred equity | 99 | $ 0 | ||||
ASU 2016-02 | ||||||
Finite-Lived Intangible Assets [Line Items] | ||||||
ROU Assets | $ 282 | |||||
Lease liabilities | 287 | |||||
Deferred tax impact | $ 5 | |||||
Noble Midstream | ||||||
Finite-Lived Intangible Assets [Line Items] | ||||||
Equity commitment | $ 100 | $ 200 | ||||
Proceeds from issuance of preferred equity | $ 100 | |||||
Issuance costs of preferred equity | $ 3 | |||||
Annual dividend rate | 6.50% | |||||
EPIC Crude Holdings, LP | Noble Midstream | ||||||
Finite-Lived Intangible Assets [Line Items] | ||||||
Step acquisition, percentage acquired | 30.00% |
Basis of Presentation - Stateme
Basis of Presentation - Statements of Operations Information (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | |
Other Revenue | ||||
Revenue from Sales | $ 1,093 | $ 1,230 | $ 2,145 | $ 2,516 |
Production Expense | ||||
Lease Operating Expense | 122 | 132 | 273 | 287 |
Production and Ad Valorem Taxes | 41 | 50 | 90 | 104 |
Gathering, Transportation and Processing Expense | 96 | 98 | 198 | 191 |
Total | 260 | 290 | 565 | 609 |
Other Operating Expense, Net | ||||
Exploration Expense | 33 | 29 | 57 | 64 |
Marketing Expense | 14 | 9 | 19 | 16 |
Other, Net | 8 | (4) | 28 | 4 |
Total | 55 | 34 | 104 | 84 |
Other Revenue | ||||
Other Revenue | ||||
Revenue from Sales | 36 | 64 | 77 | 124 |
Income from Equity Method Investees and Other | ||||
Other Revenue | ||||
Revenue from Sales | 16 | 49 | 33 | 96 |
Midstream Services Revenues – Third Party | ||||
Other Revenue | ||||
Revenue from Sales | 20 | 15 | 44 | 28 |
Other Royalty Expense | ||||
Production Expense | ||||
Cost of Purchased Oil and Gas | $ 1 | $ 10 | $ 4 | $ 27 |
Basis of Presentation - Balance
Basis of Presentation - Balance Sheet Information (Details) - USD ($) $ in Millions | Jun. 30, 2019 | Dec. 31, 2018 | Jun. 30, 2018 | Dec. 31, 2017 |
Accounts Receivable, Net | ||||
Commodity Sales | $ 346 | $ 383 | ||
Joint Interest Billings | 153 | 137 | ||
Other | 91 | 111 | ||
Allowance for Doubtful Accounts | (15) | (15) | ||
Total | 575 | 616 | ||
Other Current Assets | ||||
Commodity Derivative Assets | 30 | 180 | ||
Inventories, Materials and Supplies | 68 | 55 | ||
Assets Held for Sale | 0 | 133 | ||
Restricted Cash | 132 | 3 | $ 0 | $ 38 |
Prepaid Expenses and Other Current Assets | 83 | 47 | ||
Total | 313 | 418 | ||
Other Noncurrent Assets | ||||
Equity Method Investments | 699 | 286 | ||
Operating Lease Right of Use Assets | 272 | 0 | ||
Customer-Related Intangible Assets, Net | 294 | 310 | ||
Goodwill | 110 | 110 | ||
Other Assets, Noncurrent | 141 | 135 | ||
Total | 1,516 | 841 | ||
Other Current Liabilities | ||||
Production and Ad Valorem Taxes | 132 | 103 | ||
Asset Retirement Obligations | 85 | 118 | ||
Interest Payable | 64 | 66 | ||
Operating Lease Liabilities | 88 | 0 | ||
Commercial Paper Borrowings | 240 | 0 | ||
Partner Advances | 132 | 0 | ||
Other Liabilities, Current | 257 | 232 | ||
Total | 998 | 519 | ||
Other Noncurrent Liabilities | ||||
Deferred Compensation Liabilities | 147 | 147 | ||
Asset Retirement Obligations | 707 | 762 | ||
Operating Lease Liabilities | 190 | 0 | ||
Firm Transportation Exit Cost Accrual | 144 | 67 | ||
Production and Ad Valorem Taxes | 24 | 83 | ||
Other Liabilities, Noncurrent | 95 | 106 | ||
Total | 1,307 | 1,165 | ||
Accumulated amortization | 46 | $ 30 | ||
EPIC Investments | Noble Midstream | ||||
Other Noncurrent Assets | ||||
Equity Method Investments | 369 | |||
Delaware Crossing JV | Noble Midstream | ||||
Other Noncurrent Assets | ||||
Equity Method Investments | $ 39 |
Basis of Presentation - Compone
Basis of Presentation - Components of Cash, Cash Equivalents and Restricted Cash (Details) - USD ($) $ in Millions | Jun. 30, 2019 | Dec. 31, 2018 | Jun. 30, 2018 | Dec. 31, 2017 |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||||
Cash and Cash Equivalents | $ 470 | $ 716 | $ 621 | $ 675 |
Restricted Cash | 132 | 3 | 0 | 38 |
Cash, Cash Equivalents, and Restricted Cash | $ 602 | $ 719 | $ 621 | $ 713 |
Basis of Presentation - Perform
Basis of Presentation - Performance Obligation, Expected Timing (Details) $ in Millions | Jun. 30, 2019USD ($) |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Natural Gas Revenues | $ 188 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-04-01 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Expected timing | 6 months |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-07-01 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Natural Gas Revenues | $ 72 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Expected timing | 1 year |
Natural Gas Revenues | $ 116 |
Segment Information - Operating
Segment Information - Operating Results by Segment (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | |
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | $ 1,093 | $ 1,230 | $ 2,145 | $ 2,516 |
Revenues | 1,093 | 1,230 | 2,145 | 2,516 |
Lease Operating Expense | 122 | 132 | 273 | 287 |
Production and Ad Valorem Taxes | 41 | 50 | 90 | 104 |
Gathering, Transportation and Processing Expense | 96 | 98 | 198 | 191 |
Total Production Expense | 260 | 290 | 565 | 609 |
Marcellus Shale Exit Cost | 92 | |||
Depreciation, Depletion and Amortization | 528 | 465 | 1,036 | 933 |
(Gain) Loss on Divestitures, Net | 0 | (78) | 0 | (666) |
Asset Impairments | 168 | |||
(Gain) Loss on Commodity Derivative Instruments | (60) | 249 | 152 | 328 |
Income (Loss) Before Income Taxes | 28 | 10 | (345) | 553 |
Additions to Long-Lived Assets, Excluding Acquisitions | 647 | 935 | 1,359 | 1,840 |
Investments in Equity Method Investees | 144 | 415 | 0 | |
Intersegment Eliminations | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | (91) | (85) | (197) | (166) |
Lease Operating Expense | (12) | (6) | (21) | (6) |
Production and Ad Valorem Taxes | 0 | 0 | 0 | 0 |
Gathering, Transportation and Processing Expense | (59) | (55) | (128) | (108) |
Total Production Expense | (71) | (61) | (149) | (114) |
Marcellus Shale Exit Cost | 0 | |||
Depreciation, Depletion and Amortization | (6) | (4) | (13) | (8) |
(Gain) Loss on Divestitures, Net | 0 | 0 | ||
Asset Impairments | 0 | |||
(Gain) Loss on Commodity Derivative Instruments | 0 | 0 | 0 | 0 |
Income (Loss) Before Income Taxes | (15) | (18) | (29) | (40) |
Additions to Long-Lived Assets, Excluding Acquisitions | (25) | (18) | (48) | (50) |
Investments in Equity Method Investees | 0 | 0 | ||
Corporate | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 23 | 24 | 50 | 55 |
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 Production Expense | 0 | 0 | 0 | 0 |
Marcellus Shale Exit Cost | 92 | |||
Depreciation, Depletion and Amortization | 15 | 12 | 30 | 23 |
(Gain) Loss on Divestitures, Net | 0 | 0 | ||
Asset Impairments | 0 | |||
(Gain) Loss on Commodity Derivative Instruments | 0 | 0 | 0 | 0 |
Income (Loss) Before Income Taxes | (182) | (154) | (446) | (328) |
Additions to Long-Lived Assets, Excluding Acquisitions | 9 | 18 | 18 | 28 |
Investments in Equity Method Investees | 0 | 0 | ||
United States | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 802 | 870 | 1,565 | 1,818 |
Lease Operating Expense | 114 | 114 | 239 | 240 |
Production and Ad Valorem Taxes | 40 | 48 | 87 | 101 |
Gathering, Transportation and Processing Expense | 124 | 131 | 266 | 256 |
Total Production Expense | 279 | 303 | 596 | 624 |
Marcellus Shale Exit Cost | 0 | |||
Depreciation, Depletion and Amortization | 457 | 394 | 896 | 800 |
(Gain) Loss on Divestitures, Net | 21 | 15 | ||
Asset Impairments | 168 | |||
(Gain) Loss on Commodity Derivative Instruments | (58) | 196 | 130 | 260 |
Income (Loss) Before Income Taxes | 70 | (90) | (177) | (127) |
Additions to Long-Lived Assets, Excluding Acquisitions | 478 | 561 | 990 | 1,095 |
Investments in Equity Method Investees | 0 | 0 | ||
United States | Noble Midstream | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 161 | 155 | 326 | 283 |
Lease Operating Expense | 1 | 0 | 2 | 0 |
Production and Ad Valorem Taxes | 1 | 2 | 3 | 3 |
Gathering, Transportation and Processing Expense | 31 | 22 | 60 | 43 |
Total Production Expense | 33 | 24 | 65 | 46 |
Marcellus Shale Exit Cost | 0 | |||
Depreciation, Depletion and Amortization | 26 | 22 | 51 | 38 |
(Gain) Loss on Divestitures, Net | (109) | (305) | ||
Asset Impairments | 0 | |||
(Gain) Loss on Commodity Derivative Instruments | 0 | 0 | 0 | 0 |
Income (Loss) Before Income Taxes | 46 | 175 | 119 | 428 |
Additions to Long-Lived Assets, Excluding Acquisitions | 52 | 155 | 118 | 397 |
Investments in Equity Method Investees | 144 | 415 | ||
United States | Intersegment Eliminations | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 91 | 85 | 197 | 166 |
Eastern Mediterranean | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 107 | 113 | 225 | 244 |
Lease Operating Expense | 9 | 5 | 19 | 12 |
Production and Ad Valorem Taxes | 0 | 0 | 0 | 0 |
Gathering, Transportation and Processing Expense | 0 | 0 | 0 | 0 |
Total Production Expense | 9 | 5 | 19 | 12 |
Marcellus Shale Exit Cost | 0 | |||
Depreciation, Depletion and Amortization | 17 | 15 | 33 | 28 |
(Gain) Loss on Divestitures, Net | 10 | (376) | ||
Asset Impairments | 0 | |||
(Gain) Loss on Commodity Derivative Instruments | 0 | 0 | 0 | 0 |
Income (Loss) Before Income Taxes | 65 | 62 | 149 | 535 |
Additions to Long-Lived Assets, Excluding Acquisitions | 119 | 216 | 251 | 363 |
Investments in Equity Method Investees | 0 | 0 | ||
West Africa | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 91 | 153 | 176 | 282 |
Lease Operating Expense | 10 | 19 | 34 | 41 |
Production and Ad Valorem Taxes | 0 | 0 | 0 | 0 |
Gathering, Transportation and Processing Expense | 0 | 0 | 0 | 0 |
Total Production Expense | 10 | 19 | 34 | 41 |
Marcellus Shale Exit Cost | 0 | |||
Depreciation, Depletion and Amortization | 19 | 26 | 39 | 52 |
(Gain) Loss on Divestitures, Net | 0 | 0 | ||
Asset Impairments | 0 | |||
(Gain) Loss on Commodity Derivative Instruments | (2) | 53 | 22 | 68 |
Income (Loss) Before Income Taxes | 59 | 48 | 70 | 112 |
Additions to Long-Lived Assets, Excluding Acquisitions | 12 | 3 | 18 | 5 |
Investments in Equity Method Investees | 0 | 0 | ||
Other Int'l | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 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 Production Expense | 0 | 0 | 0 | 0 |
Marcellus Shale Exit Cost | 0 | |||
Depreciation, Depletion and Amortization | 0 | 0 | 0 | 0 |
(Gain) Loss on Divestitures, Net | 0 | 0 | ||
Asset Impairments | 0 | |||
(Gain) Loss on Commodity Derivative Instruments | 0 | 0 | 0 | 0 |
Income (Loss) Before Income Taxes | (15) | (13) | (31) | (27) |
Additions to Long-Lived Assets, Excluding Acquisitions | 2 | 0 | 12 | 2 |
Investments in Equity Method Investees | 0 | 0 | ||
Oil, NGL and Gas Sales | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 954 | 1,100 | 1,891 | 2,273 |
Oil, NGL and Gas Sales | Intersegment Eliminations | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 0 | 0 | 0 | 0 |
Oil, NGL and Gas Sales | Corporate | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 0 | 0 | 0 | 0 |
Oil, NGL and Gas Sales | United States | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 773 | 870 | 1,522 | 1,818 |
Oil, NGL and Gas Sales | United States | Noble Midstream | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 0 | 0 | 0 | 0 |
Oil, NGL and Gas Sales | Eastern Mediterranean | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 107 | 113 | 225 | 244 |
Oil, NGL and Gas Sales | West Africa | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 74 | 117 | 144 | 211 |
Oil, NGL and Gas Sales | Other Int'l | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 0 | 0 | 0 | 0 |
Crude Oil Sales | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 688 | 749 | 1,300 | 1,522 |
Crude Oil Sales | Intersegment Eliminations | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 0 | 0 | 0 | 0 |
Crude Oil Sales | Corporate | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 0 | 0 | 0 | 0 |
Crude Oil Sales | United States | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 617 | 635 | 1,162 | 1,317 |
Crude Oil Sales | United States | Noble Midstream | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 0 | 0 | 0 | 0 |
Crude Oil Sales | Eastern Mediterranean | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 2 | 2 | 3 | 4 |
Crude Oil Sales | West Africa | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 69 | 112 | 135 | 201 |
Crude Oil Sales | Other Int'l | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 0 | 0 | 0 | 0 |
NGL Sales | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 84 | 137 | 180 | 283 |
NGL Sales | Intersegment Eliminations | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 0 | 0 | 0 | 0 |
NGL Sales | Corporate | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 0 | 0 | 0 | 0 |
NGL Sales | United States | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 84 | 137 | 180 | 283 |
NGL Sales | United States | Noble Midstream | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 0 | 0 | 0 | 0 |
NGL Sales | Eastern Mediterranean | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 0 | 0 | 0 | 0 |
NGL Sales | West Africa | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 0 | 0 | 0 | 0 |
NGL Sales | Other Int'l | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 0 | 0 | 0 | 0 |
Natural Gas Sales | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 182 | 214 | 411 | 468 |
Natural Gas Sales | Intersegment Eliminations | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 0 | 0 | 0 | 0 |
Natural Gas Sales | Corporate | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 0 | 0 | 0 | 0 |
Natural Gas Sales | United States | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 72 | 98 | 180 | 218 |
Natural Gas Sales | United States | Noble Midstream | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 0 | 0 | 0 | 0 |
Natural Gas Sales | Eastern Mediterranean | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 105 | 111 | 222 | 240 |
Natural Gas Sales | West Africa | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 5 | 5 | 9 | 10 |
Natural Gas Sales | Other Int'l | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 0 | 0 | 0 | 0 |
Cost of Purchased of Gas | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 103 | 66 | 177 | 119 |
Cost of Purchased Oil and Gas | 113 | 71 | 200 | 128 |
Cost of Purchased of Gas | Intersegment Eliminations | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 0 | 0 | 0 | 0 |
Cost of Purchased Oil and Gas | 0 | 0 | ||
Cost of Purchased of Gas | Corporate | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 23 | 24 | 50 | 55 |
Cost of Purchased Oil and Gas | 37 | 31 | 49 | 53 |
Cost of Purchased of Gas | United States | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 28 | 0 | 42 | 0 |
Cost of Purchased Oil and Gas | 28 | 0 | ||
Cost of Purchased of Gas | United States | Noble Midstream | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 52 | 42 | 85 | 64 |
Cost of Purchased Oil and Gas | 48 | 40 | ||
Cost of Purchased of Gas | Eastern Mediterranean | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 0 | 0 | 0 | 0 |
Cost of Purchased Oil and Gas | 0 | 0 | ||
Cost of Purchased of Gas | West Africa | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 0 | 0 | 0 | 0 |
Cost of Purchased Oil and Gas | 0 | 0 | ||
Cost of Purchased of Gas | Other Int'l | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 0 | 0 | 0 | 0 |
Cost of Purchased Oil and Gas | 0 | 0 | ||
Income (Loss) from Equity Method Investees and Other | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 16 | 49 | 33 | 96 |
Income (Loss) from Equity Method Investees and Other | Intersegment Eliminations | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 0 | 0 | 0 | 0 |
Income (Loss) from Equity Method Investees and Other | Corporate | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 0 | 0 | 0 | 0 |
Income (Loss) from Equity Method Investees and Other | United States | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 1 | 0 | 1 | 0 |
Income (Loss) from Equity Method Investees and Other | United States | Noble Midstream | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | (2) | 13 | 0 | 25 |
Income (Loss) from Equity Method Investees and Other | Eastern Mediterranean | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 0 | 0 | 0 | 0 |
Income (Loss) from Equity Method Investees and Other | West Africa | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 17 | 36 | 32 | 71 |
Income (Loss) from Equity Method Investees and Other | Other Int'l | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 0 | 0 | 0 | 0 |
Midstream Services Revenues – Third Party | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 20 | 15 | 44 | 28 |
Midstream Services Revenues – Third Party | Intersegment Eliminations | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 0 | 0 | 0 | 0 |
Midstream Services Revenues – Third Party | Corporate | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 0 | 0 | 0 | 0 |
Midstream Services Revenues – Third Party | United States | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 0 | 0 | 0 | 0 |
Midstream Services Revenues – Third Party | United States | Noble Midstream | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 20 | 15 | 44 | 28 |
Midstream Services Revenues – Third Party | United States | Intersegment Eliminations | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 0 | 0 | ||
Midstream Services Revenues – Third Party | Eastern Mediterranean | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 0 | 0 | 0 | 0 |
Midstream Services Revenues – Third Party | West Africa | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 0 | 0 | 0 | 0 |
Midstream Services Revenues – Third Party | Other Int'l | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenue from Sales | 0 | 0 | 0 | 0 |
Other Royalty Expense | ||||
Segment Reporting Information [Line Items] | ||||
Cost of Purchased Oil and Gas | 1 | 10 | 4 | 27 |
Other Royalty Expense | Intersegment Eliminations | ||||
Segment Reporting Information [Line Items] | ||||
Cost of Purchased Oil and Gas | 0 | 0 | 0 | 0 |
Other Royalty Expense | Corporate | ||||
Segment Reporting Information [Line Items] | ||||
Cost of Purchased Oil and Gas | 0 | 0 | 0 | 0 |
Other Royalty Expense | United States | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Cost of Purchased Oil and Gas | 1 | 10 | 4 | 27 |
Other Royalty Expense | United States | Noble Midstream | ||||
Segment Reporting Information [Line Items] | ||||
Cost of Purchased Oil and Gas | 0 | 0 | 0 | 0 |
Other Royalty Expense | Eastern Mediterranean | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Cost of Purchased Oil and Gas | 0 | 0 | 0 | 0 |
Other Royalty Expense | West Africa | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Cost of Purchased Oil and Gas | 0 | 0 | 0 | 0 |
Other Royalty Expense | Other Int'l | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Cost of Purchased Oil and Gas | 0 | 0 | 0 | 0 |
Cost of Purchased Oil and Gas | ||||
Segment Reporting Information [Line Items] | ||||
Cost of Purchased Oil and Gas | 200 | 128 | ||
Cost of Purchased Oil and Gas | Intersegment Eliminations | ||||
Segment Reporting Information [Line Items] | ||||
Cost of Purchased Oil and Gas | 0 | 0 | ||
Cost of Purchased Oil and Gas | Corporate | ||||
Segment Reporting Information [Line Items] | ||||
Cost of Purchased Oil and Gas | $ 22 | $ 23 | 79 | 67 |
Cost of Purchased Oil and Gas | United States | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Cost of Purchased Oil and Gas | 42 | 0 | ||
Cost of Purchased Oil and Gas | United States | Noble Midstream | ||||
Segment Reporting Information [Line Items] | ||||
Cost of Purchased Oil and Gas | 79 | 61 | ||
Cost of Purchased Oil and Gas | Eastern Mediterranean | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Cost of Purchased Oil and Gas | 0 | 0 | ||
Cost of Purchased Oil and Gas | West Africa | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Cost of Purchased Oil and Gas | 0 | 0 | ||
Cost of Purchased Oil and Gas | Other Int'l | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Cost of Purchased Oil and Gas | $ 0 | $ 0 |
Segment Information - Assets an
Segment Information - Assets and Goodwill by Segment (Details) - USD ($) $ in Millions | Jun. 30, 2019 | Dec. 31, 2018 |
Segment Reporting Information [Line Items] | ||
Assets, net of AHFS | $ 18,775 | $ 18,419 |
Operating Segments | United States | ||
Segment Reporting Information [Line Items] | ||
Assets, net of AHFS | 13,095 | 13,044 |
Operating Segments | Eastern Mediterranean | ||
Segment Reporting Information [Line Items] | ||
Assets, net of AHFS | 2,879 | 2,630 |
Operating Segments | West Africa | ||
Segment Reporting Information [Line Items] | ||
Assets, net of AHFS | 773 | 805 |
Operating Segments | Other Int'l | ||
Segment Reporting Information [Line Items] | ||
Assets, net of AHFS | 36 | 37 |
Noble Midstream | United States | ||
Segment Reporting Information [Line Items] | ||
Assets, net of AHFS | 1,841 | 1,742 |
Intersegment Eliminations | ||
Segment Reporting Information [Line Items] | ||
Assets, net of AHFS | (185) | (145) |
Corporate | ||
Segment Reporting Information [Line Items] | ||
Assets, net of AHFS | $ 336 | $ 306 |
Acquisitions and Divestitures -
Acquisitions and Divestitures - Narrative (Details) a in Thousands, shares in Millions, $ in Millions | 1 Months Ended | 3 Months Ended | 6 Months Ended | |||||||||||
Feb. 28, 2019USD ($)aMMBbls | Oct. 31, 2018USD ($) | Mar. 31, 2018USD ($)shares | Jan. 31, 2018USD ($) | Jun. 30, 2019USD ($) | Sep. 30, 2018USD ($)shares | Jun. 30, 2018USD ($)shares | Mar. 31, 2018USD ($) | Jun. 30, 2019USD ($) | Jun. 30, 2018USD ($) | Dec. 31, 2021 | Dec. 31, 2018USD ($) | Feb. 28, 2018USD ($) | Feb. 01, 2018shares | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Cash consideration | $ 699 | $ 699 | $ 286 | |||||||||||
Capital contributions | 144 | 415 | $ 0 | |||||||||||
Asset Impairments | 0 | $ 0 | 0 | 168 | ||||||||||
Cash consideration | 0 | (650) | ||||||||||||
Gain (loss) on divestiture | 0 | (78) | 0 | (666) | ||||||||||
Proceeds from divestiture | 123 | $ 1,382 | ||||||||||||
Intangible assets | 294 | 294 | 310 | |||||||||||
Goodwill | $ 110 | $ 110 | $ 110 | |||||||||||
CONE Gathering LLC | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Gain (loss) on divestiture | $ (196) | $ (198) | $ (109) | |||||||||||
Ownership | 50.00% | 22.30% | 34.10% | |||||||||||
Shares sold (in shares) | shares | 14.2 | 7.5 | ||||||||||||
Proceeds from divestiture | $ 308 | $ 248 | $ 135 | |||||||||||
Noble Midstream | Saddle Butte | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Consideration | $ 681 | |||||||||||||
Property, plant and equipment | $ 206 | $ 206 | ||||||||||||
Intangible assets | 340 | 340 | ||||||||||||
Goodwill | $ 110 | $ 110 | ||||||||||||
EPIC Y-Grade, LP | Noble Midstream | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Step acquisition, percentage acquired | 15.00% | 15.00% | ||||||||||||
Cash consideration | $ 227 | $ 227 | ||||||||||||
Capital contributions | $ 28 | |||||||||||||
EPIC Crude Holdings, LP | Noble Midstream | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Step acquisition, percentage acquired | 30.00% | 30.00% | ||||||||||||
Capital contributions | $ 114 | |||||||||||||
Delaware Crossing JV | Noble Midstream | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Cash consideration | $ 39 | $ 39 | ||||||||||||
Pipeline capacity (in MBbl/d) | MMBbls | 160 | |||||||||||||
Tamar and Dalit Fields | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Ownership interest | 32.50% | 32.50% | ||||||||||||
CNX Midstream Partners | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Equity owned (units) | shares | 21.7 | |||||||||||||
Saddle Butte | Noble Midstream | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Ownership interest | 54.40% | |||||||||||||
Disposed by sale | Reeves County Assets | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Proved and unproved non-core acreage sold (in acres) | a | 13 | |||||||||||||
Proceeds from divestitures | $ 131 | |||||||||||||
Disposed by sale | Gulf of Mexico Assets | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Total transaction value | $ 480 | $ 480 | $ 480 | |||||||||||
Retained transaction related obligations | $ 92 | 92 | ||||||||||||
Asset Impairments | $ 168 | |||||||||||||
Gain (loss) on divestiture | 19 | |||||||||||||
Proceeds from divestiture | $ 383 | |||||||||||||
Disposed by sale | Tamar and Dalit Fields | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Percentage ownership sold | 7.50% | 7.50% | ||||||||||||
Cash consideration | $ 484 | |||||||||||||
Shares received in divestiture (in shares) | shares | 38.5 | |||||||||||||
Value of shares | $ 224 | |||||||||||||
Gain (loss) on divestiture | (386) | |||||||||||||
Tax effect | $ 90 | |||||||||||||
Payments for (Proceeds from) Investments | $ 163 | |||||||||||||
Disposed by sale | Southwest Royalties | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Proceeds from sale | $ 60 | |||||||||||||
Scenario, Forecast | Tamar and Dalit Fields | ||||||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Ownership interest | 25.00% |
Capitalized Exploratory Well _3
Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs - Aging of Capitalized Exploratory Well Costs (Details) $ in Millions | Jun. 30, 2019USD ($)project | Dec. 31, 2018USD ($)project |
Extractive Industries [Abstract] | ||
Exploratory Well Costs Capitalized for a Period of One Year or Less | $ 11 | $ 6 |
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 351 | 348 |
Capitalized Exploratory Well Costs, End of Period | $ 362 | $ 354 |
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling | project | 7 | 7 |
Capitalized Exploratory Well _4
Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs - Rollforward of Undeveloped Leasehold Costs (Details) $ in Millions | 6 Months Ended |
Jun. 30, 2019USD ($) | |
Proved Developed and Undeveloped Reserves [Roll Forward] | |
Undeveloped Leasehold Costs, Beginning of Period | $ 2,306 |
Additions to Undeveloped Leasehold Costs | 50 |
Transfers to Proved Properties | (11) |
Assets Sold | (2) |
Undeveloped Leasehold Costs, End of Period | $ 2,343 |
Capitalized Exploratory Well _5
Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs - Narrative (Details) $ in Millions | 6 Months Ended |
Jun. 30, 2019USD ($) | |
Delaware Basin | |
Projects with Exploratory Well Costs Capitalized for More than One Year Since The Commencement of Drilling [Line Items] | |
Capitalized undeveloped leasehold cost | $ 2,100 |
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 | 100 |
Other US Onshore Properties | |
Projects with Exploratory Well Costs Capitalized for More than One Year Since The Commencement of Drilling [Line Items] | |
Capitalized undeveloped leasehold cost | 73 |
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 | $ 59 |
Asset Retirement Obligations -
Asset Retirement Obligations - ARO Activity (Details) - USD ($) $ in Millions | 6 Months Ended | |
Jun. 30, 2019 | Jun. 30, 2018 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Asset Retirement Obligations, Beginning Balance | $ 880 | $ 875 |
Liabilities Incurred | 15 | 14 |
Liabilities Settled | (56) | (261) |
Revisions of Estimates | (70) | (10) |
Accretion Expense | 23 | 17 |
Asset Retirement Obligations, Ending Balance | $ 792 | $ 635 |
Asset Retirement Obligations _2
Asset Retirement Obligations - Narrative (Details) - USD ($) $ in Millions | 6 Months Ended | |
Jun. 30, 2019 | Jun. 30, 2018 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Increase (Decrease) in Estimates | $ (70) | $ (10) |
Liabilities Settled | 56 | 261 |
DJ Basin | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Increase (Decrease) in Estimates | $ (73) | |
Gulf of Mexico Assets | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Liabilities Settled | 216 | |
Onshore US | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Increase (Decrease) in Estimates | 7 | |
Liabilities Settled | 44 | |
North Sea abandonment project | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Increase (Decrease) in Estimates | (11) | |
Eastern Mediterranean | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Increase (Decrease) in Estimates | $ 6 |
Debt - Summary of Debt (Details
Debt - Summary of Debt (Details) - USD ($) $ in Millions | 6 Months Ended | |
Jun. 30, 2019 | Dec. 31, 2018 | |
Debt Instrument [Line Items] | ||
Finance Lease Obligations | $ 211 | |
Total Debt | 7,205 | $ 6,675 |
Net Unamortized Discounts and Debt Issuance Costs | (58) | (60) |
Total Debt | 7,147 | 6,615 |
Commercial Paper Borrowings | (240) | 0 |
Finance Lease Obligations | (41) | (41) |
Long-Term Debt Due After One Year | $ 6,866 | 6,574 |
Weighted average interest rate, commercial paper | 3.04% | |
Noble Midstream Services Revolving Credit Facility | ||
Debt Instrument [Line Items] | ||
Maximum borrowing capacity | $ 800 | |
Available borrowing capacity | $ 430 | $ 740 |
Senior Notes and Debentures | ||
Debt Instrument [Line Items] | ||
Weighted average interest rate | 5.00% | 5.01% |
Noble Energy | ||
Debt Instrument [Line Items] | ||
Finance Lease Obligations | $ 211 | $ 223 |
Finance Lease Obligations, Interest Rate | 0.00% | 0.00% |
Total Debt | $ 6,335 | $ 6,115 |
Noble Energy | Revolving Credit Facility, due March 9, 2023 | ||
Debt Instrument [Line Items] | ||
Debt | $ 0 | $ 0 |
Interest Rate | 0.00% | 0.00% |
Noble Energy | Commercial Paper | ||
Debt Instrument [Line Items] | ||
Debt | $ 240 | $ 0 |
Noble Energy | Senior Notes and Debentures | ||
Debt Instrument [Line Items] | ||
Debt | 5,884 | 5,892 |
Noble Midstream Partners | ||
Debt Instrument [Line Items] | ||
Total Debt | 870 | 560 |
Noble Midstream Partners | Revolving Credit Facility | Noble Midstream Services Revolving Credit Facility, due March 9, 2023 | ||
Debt Instrument [Line Items] | ||
Debt | $ 370 | $ 60 |
Interest Rate | 3.77% | 3.67% |
Noble Midstream Partners | Revolving Credit Facility | Noble Midstream Services Term Loan Credit Facility, due July 31, 2021 | ||
Debt Instrument [Line Items] | ||
Debt | $ 500 | $ 500 |
Interest Rate | 3.51% | 3.42% |
Debt - Narrative (Details)
Debt - Narrative (Details) - USD ($) | 1 Months Ended | 6 Months Ended | |
Jun. 30, 2019 | Jun. 30, 2019 | Jun. 30, 2018 | |
Debt Instrument [Line Items] | |||
Commercial paper | $ 240,000,000 | $ 240,000,000 | |
Repayments of senior notes | 9,000,000 | $ 384,000,000 | |
Commercial Paper | |||
Debt Instrument [Line Items] | |||
Borrowing capacity | 4,000,000,000 | 4,000,000,000 | |
Available borrowing capacity | 3,800,000,000 | $ 3,800,000,000 | |
Senior Notes due June 1, 2024 | |||
Debt Instrument [Line Items] | |||
Debt redemption | 8,000,000 | ||
Repayments of senior notes | $ 9,000,000 |
Leases - Right-of-use Assets an
Leases - Right-of-use Assets and Liability (Details) - USD ($) $ in Millions | Jun. 30, 2019 | Dec. 31, 2018 |
ROU Assets | ||
Operating Leases | $ 272 | $ 0 |
Finance Leases | 175 | |
Total ROU Assets | 447 | |
Current Liabilities | ||
Operating Leases | 88 | 0 |
Finance Leases | 41 | 41 |
Noncurrent Liabilities | ||
Operating Leases | 190 | $ 0 |
Finance Leases | 170 | |
Total Lease Liabilities | 489 | |
Office Space | ||
ROU Assets | ||
Operating Leases | 117 | |
Finance Leases | 94 | |
Compressors | ||
ROU Assets | ||
Operating Leases | 88 | |
Drilling Rigs | ||
ROU Assets | ||
Operating Leases | $ 35 |
Leases - Lease Expense (Details
Leases - Lease Expense (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended |
Jun. 30, 2019 | Jun. 30, 2019 | |
Leases [Abstract] | ||
Operating Lease Cost | $ 26 | $ 51 |
Finance Lease Cost | ||
Amortization Expense | 9 | 17 |
Interest Expense | 4 | 7 |
Short-term Lease Cost | 143 | 269 |
Variable Lease Cost | 0 | 0 |
Sublease Income | (1) | (2) |
Total Lease Cost | $ 181 | $ 342 |
Leases - Cash Flow Information
Leases - Cash Flow Information (Details) $ in Millions | 6 Months Ended |
Jun. 30, 2019USD ($) | |
Cash Flow, Lessee [Abstract] | |
Operating Cash Flows, Operating Leases | $ 30 |
Operating Cash Flows, Finance Leases | 6 |
Financing Cash Flows, Finance Leases | 20 |
Investing Cash Flows, Operating Leases | 18 |
ROU Assets Obtained in Exchange for Lease Liability, Operating | 58 |
ROU Assets Obtained in Exchange for Lease Liability, Finance | $ 8 |
Leases - Lease Maturity (Detail
Leases - Lease Maturity (Details) - USD ($) $ in Millions | Jun. 30, 2019 | Dec. 31, 2018 |
Operating Leases | ||
Remainder of 2019 | $ 50 | |
2020 | 85 | |
2021 | 48 | |
2022 | 33 | |
2023 | 21 | |
2024 and thereafter | 80 | |
Total Lease Liabilities, Undiscounted | 317 | |
Less: Imputed Interest | 39 | |
Total Lease Liabilities | 278 | |
Finance Leases | ||
Remainder of 2019 | 25 | |
2020 | 48 | |
2021 | 33 | |
2022 | 23 | |
2023 | 21 | |
2024 and Thereafter | 105 | |
Total Lease Liabilities, Undiscounted | 255 | |
Less: Imputed Interest | 44 | |
Total Lease Liabilities | 211 | |
Liabilities | 11,445 | $ 10,526 |
Total | ||
Remainder of 2019 | 75 | |
2019 | 143 | |
2020 | 133 | 120 |
2021 | 81 | 90 |
2022 | 56 | 84 |
2023 | 42 | 70 |
2024 and Thereafter | 185 | 280 |
Total Lease Liabilities, Undiscounted | 572 | 787 |
Liabilities, Undiscounted Excess Amount | 83 | |
Lease Liability | 489 | |
Operating lease liability, current | 88 | 0 |
Finance lease liability, current | $ 41 | 41 |
Operating Leases | ||
2019 | 91 | |
2020 | 74 | |
2021 | 59 | |
2022 | 62 | |
2023 | 50 | |
2024 and Thereafter | 176 | |
Total Lease Liabilities, Undiscounted | 512 | |
Finance Leases | ||
2019 | 52 | |
2020 | 46 | |
2021 | 31 | |
2022 | 22 | |
2023 | 20 | |
2024 and Thereafter | 104 | |
Total Lease Liabilities, Undiscounted | $ 275 |
Leases - Lease Term and Discoun
Leases - Lease Term and Discount Rates (Details) | Jun. 30, 2019 |
Weighted-Average Remaining Lease Term (Years) | |
Operating Leases | 5 years 10 months 24 days |
Finance Leases | 7 years 10 months 24 days |
Weighted-Average Discount Rate | |
Operating Leases | 4.40% |
Finance Leases | 5.01% |
Exit Costs - Transportation C_3
Exit Costs - Transportation Commitments - Narrative (Details) - USD ($) $ in Millions | 1 Months Ended | 6 Months Ended | |
Jan. 31, 2019 | Jun. 30, 2019 | Jun. 30, 2018 | |
Long-term Purchase Commitment [Line Items] | |||
Reduction of transportation contracts | $ 350 | ||
Marcellus Shale Firm Transportation Agreement | |||
Long-term Purchase Commitment [Line Items] | |||
Commitment amount | $ 1,000 | ||
Firm Transportation Exit Cost Accrual | $ 92 | $ 0 | |
Minimum | Marcellus Shale Firm Transportation Agreement | |||
Long-term Purchase Commitment [Line Items] | |||
Term | 3 years | ||
Maximum | Marcellus Shale Firm Transportation Agreement | |||
Long-term Purchase Commitment [Line Items] | |||
Term | 14 years |
Exit Costs - Transportation C_4
Exit Costs - Transportation Commitments - Rollfoward of Accrued Transportation Commitment (Details) - Marcellus Shale Firm Transportation Agreement - USD ($) $ in Millions | 6 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Dec. 31, 2018 | |
Rollforward Of Contractual Obligations [Roll Forward] | |||
Balance at Beginning of Period | $ 80 | $ 90 | |
Firm Transportation Exit Cost Accrual | 92 | 0 | |
Payments, Net of Accretion | (5) | (7) | |
Balance at End of Period | 167 | 83 | |
Other Current Liabilities | |||
Rollforward Of Contractual Obligations [Roll Forward] | |||
Balance at End of Period | 23 | 12 | |
Accrued exit costs, current | $ 13 | ||
Other Noncurrent Liabilities | |||
Rollforward Of Contractual Obligations [Roll Forward] | |||
Balance at End of Period | $ 144 | $ 71 |
Exit Costs - Transportation C_5
Exit Costs - Transportation Commitments - Income Statement Disclosures (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | |
Long-term Purchase Commitment [Line Items] | ||||
Revenue from Sales | $ 1,093 | $ 1,230 | $ 2,145 | $ 2,516 |
Corporate | ||||
Long-term Purchase Commitment [Line Items] | ||||
Revenue from Sales | 23 | 24 | 50 | 55 |
Purchased Gas | ||||
Long-term Purchase Commitment [Line Items] | ||||
Revenue from Sales | 103 | 66 | 177 | 119 |
Cost of Purchased Oil and Gas | 113 | 71 | 200 | 128 |
Purchased Gas | Corporate | ||||
Long-term Purchase Commitment [Line Items] | ||||
Revenue from Sales | 23 | 24 | 50 | 55 |
Cost of Purchased Oil and Gas | 37 | 31 | 49 | 53 |
Cost of Purchased of Gas | ||||
Long-term Purchase Commitment [Line Items] | ||||
Cost of Purchased Oil and Gas | 200 | 128 | ||
Cost of Purchased of Gas | Corporate | ||||
Long-term Purchase Commitment [Line Items] | ||||
Cost of Purchased Oil and Gas | 22 | 23 | 79 | 67 |
Utilized Firm Transportation Expense | Corporate | ||||
Long-term Purchase Commitment [Line Items] | ||||
Cost of Purchased Oil and Gas | 15 | 6 | 30 | 11 |
Unutilized Firm Transportation Expense | Corporate | ||||
Long-term Purchase Commitment [Line Items] | ||||
Cost of Purchased Oil and Gas | $ 0 | $ 2 | $ 0 | $ 3 |
Income Taxes - Components of In
Income Taxes - Components of Income Tax (Benefit) (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | |
Income Tax Disclosure [Abstract] | ||||
Current | $ 21 | $ 23 | $ 37 | $ 149 |
Deferred | (1) | (7) | (101) | (164) |
Total Income Tax Expense (Benefit) | $ 20 | $ 16 | $ (64) | $ (15) |
Effective Tax Rate | 71.40% | 160.00% | 18.60% | (2.70%) |
Income Taxes - Narrative (Detai
Income Taxes - Narrative (Details) - USD ($) $ in Millions | 6 Months Ended | |
Jun. 30, 2019 | Mar. 31, 2018 | |
Operating Loss Carryforwards [Line Items] | ||
Tax benefit from Tax Reform Legislation and Toll Tax | $ 145 | |
Tamar and Dalit Fields | Disposed by sale | ||
Operating Loss Carryforwards [Line Items] | ||
Percentage of divestiture farmed out | 7.50% |
Derivative Instruments and He_3
Derivative Instruments and Hedging Activities - Summary of Outstanding Derivative Contracts (Details) | Jun. 30, 2019bbl / dMMBTU / d$ / bbl$ / MMBTU |
Crude Oil Contract | NYMEX WTI - Swaps 2019 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 28,000 |
Crude Oil Contract | NYMEX WTI - Three-Way Collars 2019 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 33,000 |
Crude Oil Contract | NYMEX WTI - Sold Calls 2019 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 20,000 |
Weighted Average Fixed Price ($ per bbl) | 60 |
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 | NYMEX WTI - Swaps 2020 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 7,000 |
Crude Oil Contract | NYMEX WTI - Three-Way Collars 2020 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | bbl / d | 30,000 |
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 HH - Three-Way Collars 2019 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | MMBTU / d | 104,000 |
Weighted Average Short Put Price ($ per bbl) | $ / MMBTU | 2.25 |
Weighted Average Floor Price ($ per bbl) | $ / MMBTU | 2.65 |
Weighted Average Ceiling Price ($ per bbl) | $ / MMBTU | 2.95 |
Natural Gas Contract | NYMEX HH - Swaps 2019 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | MMBTU / d | 46,000 |
Natural Gas Contract | CIG - Basis Swaps 2019 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | MMBTU / d | 123,500 |
Weighted Average Differential ($ per bbl) | $ / MMBTU | (0.64) |
Natural Gas Contract | WAHA - Basis Swaps 2019 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | MMBTU / d | 47,500 |
Weighted Average Differential ($ per bbl) | $ / MMBTU | (1.28) |
Natural Gas Contract | CIG - Basis Swaps 2020 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | MMBTU / d | 54,000 |
Weighted Average Differential ($ per bbl) | $ / MMBTU | (0.61) |
Natural Gas Contract | WAHA - Basis Swaps 2020 | |
Derivative [Line Items] | |
Bbls Per Day (Bbls per day) | MMBTU / d | 49,500 |
Weighted Average Differential ($ per bbl) | $ / MMBTU | (1.05) |
Swaps | Crude Oil Contract | NYMEX WTI - Swaps 2019 | |
Derivative [Line Items] | |
Weighted Average Fixed Price ($ per bbl) | 58.70 |
Swaps | Crude Oil Contract | NYMEX WTI - Swaption 2020 | |
Derivative [Line Items] | |
Weighted Average Fixed Price ($ per bbl) | 61.79 |
Swaps | Crude Oil Contract | NYMEX WTI - Swaps 2020 | |
Derivative [Line Items] | |
Weighted Average Fixed Price ($ per bbl) | 60 |
Swaps | Natural Gas Contract | NYMEX HH - Swaps 2019 | |
Derivative [Line Items] | |
Weighted Average Fixed Price ($ per bbl) | $ / MMBTU | 3 |
Collars | Crude Oil Contract | NYMEX WTI - Three-Way Collars 2019 | |
Derivative [Line Items] | |
Weighted Average Short Put Price ($ per bbl) | 49.35 |
Weighted Average Floor Price ($ per bbl) | 59.35 |
Weighted Average Ceiling Price ($ per bbl) | 72.25 |
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 |
Collars | Crude Oil Contract | NYMEX WTI - Three-Way Collars 2020 | |
Derivative [Line Items] | |
Weighted Average Short Put Price ($ per bbl) | 48.33 |
Weighted Average Floor Price ($ per bbl) | 57.87 |
Weighted Average Ceiling Price ($ per bbl) | 64.27 |
Derivative Instruments and He_4
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, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | Dec. 31, 2018 | |
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value | $ 41 | $ 41 | $ 180 | ||
Derivative Liability, Fair Value | 55 | 55 | 27 | ||
Total Cash (Received) Paid in Settlement of Commodity Derivative Instruments | (1) | $ 65 | (15) | $ 93 | |
Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments | (59) | 184 | 167 | 235 | |
Total (Gain) Loss on Commodity Derivative Instruments | (60) | 249 | 152 | 328 | |
Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value | 30 | 30 | 180 | ||
Other Current Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value | 42 | 42 | 1 | ||
Other Noncurrent Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value | 11 | 11 | 0 | ||
Other Noncurrent Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value | 13 | 13 | $ 26 | ||
Crude Oil | |||||
Derivatives, Fair Value [Line Items] | |||||
Total Cash (Received) Paid in Settlement of Commodity Derivative Instruments | 7 | 66 | (2) | 96 | |
Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments | (54) | 181 | 169 | 231 | |
Total (Gain) Loss on Commodity Derivative Instruments | (47) | 247 | 167 | 327 | |
Natural Gas | |||||
Derivatives, Fair Value [Line Items] | |||||
Total Cash (Received) Paid in Settlement of Commodity Derivative Instruments | (8) | (1) | (13) | (3) | |
Total Non-cash Portion of (Gain) Loss on Commodity Derivative Instruments | (5) | 3 | (2) | 4 | |
Total (Gain) Loss on Commodity Derivative Instruments | $ (13) | $ 2 | $ (15) | $ 1 |
Fair Value Measurements and D_3
Fair Value Measurements and Disclosures - Assets and Liabilities Measured on a Recurring Basis (Details) - USD ($) $ in Millions | Jun. 30, 2019 | Dec. 31, 2018 |
Financial Assets: | ||
Mutual Fund Investments | $ 38 | |
Commodity Derivative Instruments | $ 41 | 180 |
Financial Liabilities Fair Value Disclosure [Abstract] | ||
Commodity Derivative Instruments | (55) | (27) |
Portion of Deferred Compensation Liability Measured at Fair Value | (48) | (43) |
Stock Based Compensation Liability Measured at Fair Value | (2) | (8) |
Quoted Prices in Active Markets (Level 1) | ||
Financial Assets: | ||
Mutual Fund Investments | 38 | |
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 | (48) | (43) |
Stock Based Compensation Liability Measured at Fair Value | (2) | (8) |
Significant Other Observable Inputs (Level 2) | ||
Financial Assets: | ||
Mutual Fund Investments | 0 | |
Commodity Derivative Instruments | 63 | 187 |
Financial Liabilities Fair Value Disclosure [Abstract] | ||
Commodity Derivative Instruments | (77) | (34) |
Portion of Deferred Compensation Liability Measured at Fair Value | 0 | 0 |
Stock Based Compensation Liability Measured at Fair Value | 0 | 0 |
Significant Unobservable Inputs (Level 3) | ||
Financial Assets: | ||
Mutual Fund 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 |
Scenario, Adjustment | ||
Financial Assets: | ||
Mutual Fund Investments | 0 | |
Commodity Derivative Instruments | (22) | (7) |
Financial Liabilities Fair Value Disclosure [Abstract] | ||
Commodity Derivative Instruments | 22 | 7 |
Portion of Deferred Compensation Liability Measured at Fair Value | 0 | 0 |
Stock Based Compensation Liability Measured at Fair Value | 0 | $ 0 |
Mutual Fund Investments | ||
Financial Assets: | ||
Mutual Fund Investments | 42 | |
Mutual Fund Investments | Quoted Prices in Active Markets (Level 1) | ||
Financial Assets: | ||
Mutual Fund Investments | 42 | |
Mutual Fund Investments | Significant Other Observable Inputs (Level 2) | ||
Financial Assets: | ||
Mutual Fund Investments | 0 | |
Mutual Fund Investments | Significant Unobservable Inputs (Level 3) | ||
Financial Assets: | ||
Mutual Fund Investments | 0 | |
Mutual Fund Investments | Scenario, Adjustment | ||
Financial Assets: | ||
Mutual Fund Investments | $ 0 |
Fair Value Measurements and D_4
Fair Value Measurements and Disclosures - Narrative (Details) - USD ($) $ in Millions | 1 Months Ended | 6 Months Ended | ||
Mar. 31, 2019 | Jun. 30, 2019 | Jun. 30, 2018 | Dec. 31, 2018 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Redeemable Noncontrolling Interest, Net | $ 97 | $ 100 | $ 0 | |
Proceeds from issuance of preferred equity | 99 | $ 0 | ||
Noble Midstream | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Proceeds from issuance of preferred equity | 100 | |||
Issuance costs of preferred equity | $ 3 | |||
Marcellus Shale Firm Transportation Agreement | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Firm transportation exit cost accrual | $ 92 | $ 0 |
Fair Value Measurements and D_5
Fair Value Measurements and Disclosures - Fair Value of Debt (Details) - USD ($) $ in Millions | Jun. 30, 2019 | Dec. 31, 2018 |
Carrying Amount | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term Debt | $ 6,994 | $ 6,452 |
Fair Value (1) | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Long-term Debt | $ 7,465 | $ 6,121 |
Net (Loss) Income Per Share A_3
Net (Loss) Income Per Share Attributable to Noble Energy Common Shareholders (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | |
Earnings Per Share [Abstract] | ||||
Net Loss and Comprehensive Loss Attributable to Noble Energy | $ (10) | $ (23) | $ (323) | $ 531 |
Weighted Average, Number of Shares Outstanding, Basic (in shares) | 478 | 484 | 478 | 485 |
Incremental Shares from Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust (in shares) | 0 | 0 | 0 | 2 |
Weighted Average, Number of Shares Outstanding, Diluted (in shares) | 478 | 484 | 478 | 487 |
(Loss) Income Per Share, Basic ($ per share) | $ (0.02) | $ (0.05) | $ (0.68) | $ 1.09 |
(Loss) Income Per Share, Diluted ($ per share) | $ (0.02) | $ (0.05) | $ (0.68) | $ 1.09 |
Number of Antidilutive Stock Options, Shares of Restricted Stock, and Shares of Common Stock in Rabbi Trust Excluded from Calculation Above (in shares) | 15 | 14 | 15 | 14 |
Share purchase plan, authorized amount | $ 750 | $ 750 |