Document And Entity Information
Document And Entity Information - USD ($) $ in Billions | 12 Months Ended | |
Dec. 31, 2016 | Jun. 30, 2016 | |
Document Information [Line Items] | ||
Entity Registrant Name | NOBLE ENERGY INC | |
Entity Central Index Key | 72,207 | |
Current Fiscal Year End Date | --12-31 | |
Entity Well-known Seasoned Issuer | Yes | |
Entity Voluntary Filers | No | |
Entity Current Reporting Status | Yes | |
Entity Filer Category | Large Accelerated Filer | |
Entity Public Float | $ 15.4 | |
Entity Common Stock, Shares Outstanding | 430,524,340 | |
Document Fiscal Year Focus | 2,016 | |
Document Fiscal Period Focus | FY | |
Document Type | 10-K | |
Amendment Flag | false | |
Document Period End Date | Dec. 31, 2016 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Revenues | |||
Oil, Gas and NGL Sales | $ 3,389 | $ 3,093 | $ 4,945 |
Income from Equity Method Investees | 102 | 90 | 170 |
Total Revenues | 3,491 | 3,183 | 5,115 |
Costs and Expenses | |||
Production Expense | 1,083 | 979 | 945 |
Exploration Expense | 925 | 488 | 498 |
Depreciation, Depletion and Amortization | 2,454 | 2,131 | 1,759 |
General and Administrative | 399 | 396 | 503 |
Asset Impairments | 92 | 533 | 500 |
Goodwill Impairment | 0 | 779 | 0 |
Other Operating (Income) Expense, Net | 166 | (349) | 8 |
Total Operating Expenses | (4,787) | (5,655) | (4,197) |
Operating (Loss) Income | (1,296) | (2,472) | 918 |
Other (Income) Expense | |||
Loss (Gain) on Commodity Derivative Instruments | 139 | (501) | (976) |
Interest, Net of Amount Capitalized | 328 | 263 | 210 |
Other Non-Operating Expense (Income), Net | 9 | (15) | (26) |
Total Other Expense (Income) | 476 | (253) | (792) |
(Loss) Income Before Income Taxes | (1,772) | (2,219) | 1,710 |
Income Tax (Benefit) Provision | (787) | 222 | 496 |
Income (Loss) from Continuing Operations | (998) | (2,441) | 1,214 |
Net (Loss) Income Including Noncontrolling Interests | (985) | (2,441) | 1,214 |
Less: Net Income Attributable to Noncontrolling Interests | 13 | 0 | 0 |
Net (Loss) Income Attributable to Noble Energy | $ (998) | $ (2,441) | $ 1,214 |
Net (Loss) Income Attributable to Noble Energy per Share of Common Stock | |||
Net Income (in dollars per share) | $ (2.32) | $ (6.07) | $ 3.36 |
Net Income (in dollars per share) | $ (2.32) | $ (6.07) | $ 3.27 |
Weighted Average Number of Shares Outstanding | |||
Weighted Average Number of Shares Outstanding, Basic (in shares) | 430 | 402 | 361 |
Weighted Average Number of Shares Outstanding, Diluted (in shares) | 430 | 402 | 367 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Other Items of Comprehensive Income (Loss) | |||
Net Income (Loss) | $ (985) | $ (2,441) | $ 1,214 |
Net Change in Mutual Fund Investment | 0 | (11) | 0 |
Less Tax Expense | 0 | 4 | 0 |
Net Change in Pension and Other | 3 | 99 | 42 |
Less Tax (Benefit) Expense | (1) | (35) | (15) |
Other Comprehensive Income (Loss) | 2 | 57 | 27 |
Comprehensive (Loss) Income Including Noncontrolling Interests | (983) | (2,384) | 1,241 |
Less: Comprehensive Income Attributable to Noncontrolling Interests | 13 | 0 | 0 |
Comprehensive (Loss) Income Including Noncontrolling Interests | $ (996) | $ (2,384) | $ 1,241 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Current Assets | ||
Cash and Cash Equivalents | $ 1,180 | $ 1,028 |
Accounts Receivable, Net | 615 | 450 |
Commodity Derivative Assets | 0 | 582 |
Other Current Assets | 160 | 216 |
Total Current Assets | 1,955 | 2,276 |
Property, Plant and Equipment | ||
Oil and Gas Properties (Successful Efforts Method of Accounting) | 30,355 | 31,220 |
Property, Plant and Equipment, Other | 909 | 858 |
Total Property, Plant and Equipment, Gross | 31,264 | 32,078 |
Accumulated Depreciation, Depletion and Amortization | (12,716) | (10,778) |
Total Property, Plant and Equipment, Net | 18,548 | 21,300 |
Other Noncurrent Assets | 508 | 620 |
Total Assets | 21,011 | 24,196 |
Current Liabilities | ||
Accounts Payable - Trade | 736 | 1,128 |
Other Current Liabilities | 742 | 677 |
Total Current Liabilities | 1,478 | 1,805 |
Long-Term Debt | 7,011 | 7,976 |
Net Deferred Income Tax Liability | 1,819 | 2,826 |
Other Noncurrent Liabilities | 1,103 | 1,219 |
Total Liabilities | 11,411 | 13,826 |
Shareholders’ Equity | ||
Preferred Stock - Par Value $1.00 per share; 4 Million Shares Authorized, None Issued | 0 | 0 |
Common Stock - Par Value $0.01; 1 Billion and 500 Million Shares Authorized; 471 Million and 470 Million Shares Issued, Respectively | 5 | 5 |
Additional Paid in Capital | 6,450 | 6,360 |
Accumulated Other Comprehensive Loss | (31) | (33) |
Treasury Stock, at Cost; 38 Million Shares | (692) | (688) |
Retained Earnings | 3,556 | 4,726 |
Noble Energy Share of Equity | 9,288 | 10,370 |
Noncontrolling Interests | 312 | 0 |
Total Equity | 9,600 | 10,370 |
Total Liabilities and Equity | $ 21,011 | $ 24,196 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Dec. 31, 2016 | Dec. 31, 2015 |
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 |
Common Stock, par value per share (in dollars per share) | $ 0.01 | $ 0.01 |
Common Stock, shares authorized (in shares) | 1,000,000,000 | 500,000,000 |
Common Stock, Shares, Issued | 471,360,427 | 469,718,512 |
Treasury Stock, Shares | 37,961,316 | 37,925,625 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Cash Flows From Operating Activities [Abstract] | |||
Net Income (Loss) | $ (985) | $ (2,441) | $ 1,214 |
Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities | |||
Depreciation, Depletion and Amortization | 2,454 | 2,131 | 1,759 |
Asset Impairments | 92 | 533 | 500 |
Goodwill Impairment | 0 | 779 | 0 |
Dry Hole Cost | 579 | 266 | 226 |
Deferred Income Taxes | (984) | 116 | 268 |
Loss (Gain) on Commodity Derivative Instruments | 139 | (501) | (976) |
Net Cash Received in Settlement of Commodity Derivative Instruments | 569 | 1,009 | 29 |
Gain on Divestitures | (238) | 0 | (73) |
Allocated Share-based Compensation Expense | 77 | 86 | 87 |
Non-cash Pension Plan Termination Expense | 0 | 82 | 0 |
Gain on Debt Extinguishment | (80) | 0 | 0 |
Undeveloped Leasehold Impairment | 93 | 21 | 0 |
Expiration and Amortization of Unproved Leaseholds | 55 | 92 | 43 |
Other Adjustments for Noncash Items Included in Income | 40 | 18 | 17 |
Changes in Operating Assets and Liabilities, Net of Assets Acquired and Liabilities Assumed | |||
(Increase) Decrease in Accounts Receivable | (164) | 453 | 29 |
(Decrease) Increase in Accounts Payable | (111) | (364) | 318 |
(Decrease) Increase in Current Income Taxes Payable | (32) | (94) | 18 |
(Decrease) Increase in Other Current Liabilities | (63) | (70) | 45 |
Other Operating Assets and Liabilities, Net | (90) | (54) | 2 |
Net Cash Provided by Operating Activities | 1,351 | 2,062 | 3,506 |
Cash Flows From Investing Activities | |||
Additions to Property, Plant and Equipment | (1,541) | (2,979) | (4,871) |
Proceeds from Divestitures | 1,241 | 151 | 321 |
Marcellus Shale Acreage Exchange Consideration | (213) | 0 | 0 |
Cash Acquired in Rosetta Merger | 0 | 61 | 0 |
Additions to Equity Method Investments | (8) | (104) | (71) |
Distributions from Equity Method Investments | 70 | 0 | 156 |
Other | 20 | 0 | 0 |
Net Cash Used in Investing Activities | (431) | (2,871) | (4,465) |
Cash Flows From Financing Activities | |||
Dividends Paid, Common Stock | (172) | (291) | (249) |
Proceeds from Issuance Common Stock | 0 | 1,112 | 0 |
Proceeds from facility | 1,400 | 0 | 0 |
Repayment of facility | 0 | (70) | 0 |
Repayment of Term Loan Facility | (850) | 0 | 0 |
Proceeds from Issuance of Senior Notes, Net | 0 | 0 | 1,478 |
Repayment of Senior Notes | (1,383) | (12) | (200) |
Repayment of Capital Lease Obligation | (53) | (67) | (55) |
Other | (9) | (18) | 51 |
Net Cash (Used in) Provided By Financing Activities | (768) | 654 | 1,025 |
Increase (Decrease) in Cash and Cash Equivalents | 152 | (155) | 66 |
Cash and Cash Equivalents at Beginning of Period | 1,028 | 1,183 | 1,117 |
Cash and Cash Equivalents at End of Period | 1,180 | 1,028 | 1,183 |
Noble Midstream Revolving Credit Facility, due September 20, 2021 | Noble Midstream Partners LP | |||
Cash Flows From Financing Activities | |||
Proceeds from Issuance Common Stock | 299 | 0 | 0 |
Revolving Credit Facility | |||
Cash Flows From Financing Activities | |||
Proceeds from facility | 0 | 0 | 1,050 |
Repayment of facility | $ 0 | $ 0 | $ (1,050) |
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 |
Shareholders Equity, Beginning Balance at Dec. 31, 2013 | $ 9,184 | $ 4 | $ 3,463 | $ (117) | $ (659) | $ 6,493 | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Net Income (Loss) | 1,214 | 0 | 0 | 0 | 0 | 1,214 | |
Stock-based Compensation | 87 | 0 | 87 | 0 | 0 | 0 | |
Exercise of Stock Options | 48 | 0 | 48 | 0 | 0 | 0 | |
Tax Benefits Related to Exercise of Stock Options | 19 | 0 | 19 | 0 | 0 | 0 | |
Dividends | (249) | 0 | 0 | 0 | 0 | (249) | |
Net Change in Other | 22 | 0 | 7 | 27 | (12) | 0 | |
Shareholders Equity, Ending Balance at Dec. 31, 2014 | 10,325 | 4 | 3,624 | (90) | (671) | 7,458 | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Net Income (Loss) | (2,441) | 0 | 0 | 0 | (2,441) | ||
Rosetta Merger | 1,529 | 1 | 1,528 | 0 | 0 | 0 | |
Stock-based Compensation | 86 | 0 | 86 | 0 | 0 | 0 | |
Exercise of Stock Options | 8 | 0 | 8 | 0 | 0 | 0 | |
Tax Benefits Related to Exercise of Stock Options | (1) | 0 | (1) | 0 | 0 | 0 | |
Dividends | (291) | 0 | 0 | 0 | (291) | ||
Rabbi Trust Shares Sold | 1,112 | 0 | 1,112 | 0 | 0 | 0 | |
Net Change in Other | 43 | 0 | 3 | 57 | (17) | 0 | |
Shareholders Equity, Ending Balance at Dec. 31, 2015 | 10,370 | 5 | 6,360 | (33) | (688) | 4,726 | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Net Income (Loss) | (985) | 0 | 0 | 0 | 0 | (998) | $ 13 |
Stock-based Compensation | 68 | 0 | 68 | 0 | 0 | 0 | |
Exercise of Stock Options | 24 | 0 | 24 | 0 | 0 | 0 | |
Tax Benefits Related to Exercise of Stock Options | (6) | 0 | (6) | 0 | 0 | 0 | |
Dividends | (172) | 0 | 0 | 0 | 0 | (172) | |
Issuance of Noble Midstream Partners Common Units, Net of Offering Costs | 299 | 0 | 0 | 0 | 0 | 0 | 299 |
Net Change in Other | 2 | 0 | 4 | 2 | (4) | 0 | |
Shareholders Equity, Ending Balance at Dec. 31, 2016 | $ 9,600 | $ 5 | $ 6,450 | $ (31) | $ (692) | $ 3,556 | $ 312 |
Consolidated Statements of Sha8
Consolidated Statements of Shareholders' Equity (Parenthetical) - $ / shares | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Statement of Stockholders' Equity [Abstract] | |||
Common Stock, Dividends, Per Share, Cash Paid | $ 0.40 | $ 0.72 | $ 0.68 |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | Note 1. Summary of Significant Accounting Policies General 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 operating areas are onshore US (DJ Basin, Eagle Ford Shale, Permian Basin, and Marcellus Shale), deepwater Gulf of Mexico, offshore Eastern Mediterranean and offshore West Africa. Basis of Presentation and Consolidation Accounting policies used by us and our subsidiaries conform to US GAAP. Significant policies are discussed below. Our consolidated accounts include our accounts and the accounts of our wholly-owned subsidiaries. All significant intercompany balances and transactions have been eliminated upon consolidation. Equity Method of Accounting We use the equity method of accounting for investments in entities that we do not control but over which we exert significant influence. Our equity investees own and operate various midstream assets which we consider an essential component of our business and a necessary and integral element to our value chain involving the monetization of natural gas in our Marcellus Shale and West Africa operating areas. With our partners, we engage in joint strategic operational and financial decision making for these entities. In order to reflect the economics associated with our integrated upstream value chain described above, we include income from equity method investees as a component of revenue in our consolidated statements of operations. We carry equity method investments at our share of net assets of the equity investees plus our loans and advances. Differences in the basis of the investment and the separate net asset value of the investee, if any, are amortized into income over the remaining useful life of the underlying assets. See Note 7. Equity Method Investments . Noncontrolling Interests In third quarter 2016, Noble Midstream Partners LP (Noble Midstream Partners), a subsidiary of Noble Energy, completed its initial public offering of common units. As a result, we present our consolidated financial statements with a noncontrolling interest section representing the public's ownership in Noble Midstream Partners. See Note 4. Noble Midstream Partners LP . Consolidated VIE Noble Energy has determined that the partners with equity at risk in Noble Midstream Partners lack the authority, through voting rights or similar rights, to direct the activities that most significantly impact Noble Midstream Partners' economic performance; therefore, Noble Midstream Partners is considered a VIE. Through Noble Energy's ownership interest in Noble Midstream GP LLC (the General Partner to Noble Midstream Partners), Noble Energy has the authority to direct the activities that most significantly affect economic performance and the obligation to absorb losses or the right to receive benefits that could be potentially significant to Noble Midstream Partners. Therefore, Noble Energy is considered the primary beneficiary and consolidates Noble Midstream Partners. Use of Estimates The preparation of consolidated financial statements in conformity with US GAAP requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Estimated quantities of crude oil, natural gas and NGL reserves are the most significant of our estimates. All the reserves data included in this Form 10-K are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil, natural gas and NGLs. There are numerous uncertainties inherent in estimating quantities of proved crude oil, natural gas and NGL reserves. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserves estimates may be different from the quantities of crude oil, natural gas and NGLs that are ultimately recovered. Qualified petroleum engineers in our Houston and Denver offices prepare all reserves estimates for our different geographical regions. These reserves estimates are reviewed and approved by senior engineering staff and division management with final approval by the Senior Vice President – Corporate Development and certain members of senior management. See Supplemental Oil and Gas Information (Unaudited) . Other items subject to estimates and assumptions include the carrying amounts of inventory, property, plant and equipment, goodwill and asset retirement obligations, valuation allowances for receivables and deferred income tax assets, and valuation of derivative instruments, among others. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. Further declines in commodity prices could result in a reduction in our fair value estimates and cause us to perform analyses to determine if our oil and gas properties are impaired. As future commodity prices cannot be determined accurately, actual results could differ significantly from our estimates. See Supplemental Oil and Gas Information (Unaudited) . Reclassification Certain reclassifications have been made to the 2015 and 2014 consolidated financial statements to conform to the 2016 presentation. These reclassifications were not material to the financial statements. Fair Value Measurements Fair value measurements are based on a hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three levels. The fair value hierarchy is as follows: • Level 1 measurements are fair value measurements which use quoted market prices (unadjusted) in active markets for identical assets or liabilities. • Level 2 measurements are fair value measurements which use inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly. • Level 3 measurements are fair value measurements which use unobservable inputs. The fair value hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. We use Level 1 inputs when available as Level 1 inputs generally provide the most reliable evidence of fair value. See Note 13. Fair Value Measurements and Disclosures . Cash and Cash Equivalents For purposes of reporting cash flows, cash and cash equivalents include unrestricted cash on hand and investments with original maturities of three months or less at the time of purchase. Allowance for Doubtful Accounts We routinely assess the recoverability of all material trade and other receivables to determine their collectibility. We accrue a reserve on a receivable when, based on management’s judgment, it is probable that a receivable will not be collected and the amount of such reserve may be reasonably estimated. Inventories Inventories consist primarily of tubular goods and production equipment used in our oil and gas operations, and crude oil produced but not yet sold. Materials and supplies inventories are stated at the lower of cost or net realizable value. The cost of crude oil inventory includes production costs and DD&A of oil and gas properties. See Note 2. Additional Financial Statement Information . Property, Plant and Equipment Significant accounting policies for our property, plant and equipment are as follows: Successful Efforts Method We account for crude oil and natural gas properties under the successful efforts method of accounting. Under this method, costs to acquire mineral interests in crude oil and natural gas properties, drill and equip exploratory wells that find proved reserves, and drill and equip development wells are capitalized. Capitalized costs of producing crude oil and natural gas properties, along with support equipment and facilities, are amortized to expense by the unit-of-production method based on proved crude oil, natural gas and NGL reserves on a field-by-field basis, as estimated by our qualified petroleum engineers. Our policy is to use quarter-end reserves and add back current period production to compute quarterly DD&A expense. Costs of certain gathering facilities or processing plants serving a number of properties or used for third-party processing are depreciated using the straight-line method over the useful lives of the assets ranging from three to thirty years. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized. Repairs and maintenance are expensed as incurred. Property Impairment For our proved properties, we routinely assess whether impairment indicators arise during any given quarter and have processes in place to ensure that we become aware of such indicators. Impairment indicators include, but are not limited to, sustained decreases in commodity prices, negative revisions of proved reserves, and increases in development or operating costs. In the event that impairment indicators exist, we conduct an impairment test. To that end, we estimate future net cash flows expected in connection with the property and compare such future net cash flows to the carrying amount of the property to determine if the carrying amount is recoverable. When the carrying amount of a property exceeds its estimated undiscounted future net cash flows, the carrying amount is reduced to estimated fair value. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future crude oil and natural gas production, commodity prices based on published forward commodity price curves or contract prices as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate. Other long-lived assets, such as our midstream assets, are evaluated for potential impairment whenever events or changes in circumstances indicate that their carrying value may be greater than the undiscounted future net cash flows. Impairment, if any, is measured as the excess of an asset’s carrying amount over its estimated fair value, which is estimated as described above. We recorded property impairment charges in 2016 , 2015 and 2014 and it is possible that other proved oil and gas properties could become impaired in the future due to commodity price declines and/or field performance. See Note 5. Asset Impairments . Unproved Property Impairment Our unproved properties consist of leasehold costs and allocated value to probable and possible reserves from acquisitions. We assess individually significant unproved properties for impairment on a quarterly basis and recognize a loss at the time of impairment by providing an impairment allowance. In determining whether a significant unproved property is impaired we consider numerous factors including, but not limited to, current exploration plans, favorable or unfavorable exploration activity on the property being evaluated and/or adjacent properties, our geologists' evaluation of the property, and the remaining months in the lease term for the property. When we have allocated fair value to an unproved property as the result of a transaction accounted for as a business combination, we use a future cash flow analysis to assess the unproved property for impairment. Cash flows used in the impairment analysis are determined based on management’s estimates of crude oil, natural gas and NGL reserves, future commodity prices and future costs to produce the reserves. Cash flow estimates related to probable and possible reserves are reduced by additional risk-weighting factors. Other individually insignificant unproved properties are amortized on a composite method over an average holding period. We recorded an unproved property impairment charge in 2016 . It is possible that unproved oil and gas properties could become impaired in the future if commodity prices decline. See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs . Properties Acquired in Business Combinations When sufficient market data is not available, we determine the fair values of proved and unproved properties acquired in transactions accounted for as business combinations by preparing our own estimates of cash flows from the production of crude oil, natural gas and NGL reserves. We estimate future prices to apply to the estimated reserves quantities acquired, and estimate future operating and development costs, to arrive at estimates of future net cash flows. For the fair value assigned to proved reserves, future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the business combination. To compensate for the inherent risk of estimating and valuing unproved reserves, discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors. Assets Held for Sale We occasionally market for sale oil and gas properties. At the end of each reporting period, we evaluate our properties being marketed to determine whether any should be reclassified as held for sale. The held for sale criteria include a commitment to a plan to sell; the asset is available for immediate sale; an active program to locate a buyer exists; the sale of the asset is probable and expected to be completed within one year; the asset is being actively marketed for sale; and it is unlikely that significant changes to the plan will be made. If each of these criteria is met, the property is reclassified as held for sale in our consolidated balance sheets and will be valued at the lower of net book value or anticipated sales proceeds less costs to sell. Impairment expense would be recorded for any excess of net book value over anticipated sales proceeds less costs to sell. See Note 3. Acquisitions, Divestitures and Merger . Exploration Costs Geological and geophysical costs, delay rentals, amortization of unproved leasehold costs, and costs to drill exploratory wells that do not find proved reserves are expensed as oil and gas exploration. We carry the costs of an exploratory well as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as we are making sufficient progress assessing the reserves and the economic and operating viability of the project. For certain capital-intensive deepwater Gulf of Mexico or international projects, it may take us more than one year to evaluate the future potential of the exploratory well and make a determination of its economic viability. Our ability to move forward on a project may be dependent on gaining access to transportation or processing facilities or obtaining permits and government or partner approval, the timing of which is beyond our control. In such cases, exploratory well costs remain suspended as long as we are actively pursuing access to necessary facilities and access to such permits and approvals and believe they will be obtained. We assess the status of suspended exploratory well costs on a quarterly basis. See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs . Other Property Other property includes automobiles, trucks, airplanes, office furniture, computer equipment and other fixed assets such as buildings and leasehold improvements. These items are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets or group of assets, which range from 3 to 30 years . Other property also includes linefill which is recorded at cost to produce into the production line. Linefill is not subject to depreciation but is reviewed for impairment. Capitalization of Interest We capitalize interest costs associated with the development and construction of significant properties or projects to bring them to a condition and location necessary for their intended use, which for crude oil and natural gas assets is at first production from the field. Interest is capitalized using an interest rate equivalent to the weighted average rate we pay on long-term debt, including our unsecured revolving credit facility (Revolving Credit Facility) and bonds. Capitalized interest is included in the cost of oil and gas assets and amortized with other costs on a unit-of-production basis. Capitalized interest totaled $84 million in 2016 , $144 million in 2015 , and $116 million in 2014 . Asset Retirement Obligations Asset retirement obligations consist of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. We recognize the fair value of a liability for an ARO in the period in which it is incurred when we have an existing legal obligation associated with the retirement of our oil and gas properties that can reasonably be estimated, with the associated asset retirement cost capitalized as part of the carrying cost of the oil and gas asset. The asset retirement cost is recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at our credit-adjusted risk-free rate. After initial recording, the liability is increased for the passage of time, with the increase being reflected as accretion expense and included in our DD&A expense in the statement of operations. Subsequent adjustments in the cost estimate are reflected in the liability and the amounts continue to be amortized over the useful life of the related long-lived asset. See Note 9. Asset Retirement Obligations . Goodwill Goodwill represents the excess of the cost of an acquired entity over the net amounts assigned to assets acquired and liabilities assumed. Goodwill is subject to annual impairment testing in December (or more frequently as circumstances dictate). During 2015, we reviewed our goodwill balance for impairment in accordance with our accounting policy and identified factors, including continuing declines in commodity prices and the market value of our common stock, indicating that the fair value of our goodwill could have fallen below its book value. As of December 31, 2015, we determined that our goodwill was fully impaired and recognized a loss of $779 million . Our goodwill related primarily to the excess purchase price over amounts assigned to assets and liabilities from the Rosetta Merger in 2015 and the Patina Merger in 2005 and was associated with our US reporting unit. During 2015, goodwill increased $163 million due to the Rosetta Merger and decreased $4 million due to allocations of goodwill to onshore US properties sold. For purposes of determining the goodwill impairment, we estimated the implied fair value of the goodwill using a variety of valuation methods, including the income and market approaches. Our estimate of fair value required us to use significant unobservable inputs, representative of a Level 3 fair value measurement, including assumptions for future crude oil and natural gas production, commodity prices based on forward commodity price curves, operating and development costs and other factors. The analysis supported that the implied fair value of goodwill was zero and, as such, goodwill was fully impaired. Derivative Instruments and Hedging Activities All derivative instruments (including certain derivative instruments embedded in other contracts) are recorded in our consolidated balance sheets as either an asset or liability and measured at fair value. We account for our commodity derivative instruments using mark-to-market accounting and recognize all gains and losses in earnings during the period in which they occur. Our consolidated statements of cash flows includes the non-cash portion of gain and loss on commodity derivative instruments, which represented the difference between the total gain and loss on commodity derivative instruments and the cash received or paid on settlements of commodity derivative instruments during the period. We offset the fair value amounts recognized for derivative instruments and the fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral. The cash collateral (commonly referred to as a “margin”) must arise from derivative instruments recognized at fair value that are executed with the same counterparty under a master arrangement with netting clauses. Stock-Based Compensation Restricted stock and stock options issued to employees and directors are recorded at grant-date fair value. Expense is recognized on a straight-line basis over the employee’s and director’s requisite service period (generally the vesting period of the award) in the consolidated statements of operations. In 2016, we issued cash-settled awards to certain employees in lieu of a portion of restricted stock and stock options. We recognize the value of our cash-settled awards utilizing the liability method as defined under Accounting Standards Codification Topic 718, Compensation - Stock Compensation . The fair value of liability awards is remeasured at each reporting date, based on the fair market value of a share of common stock of the Company as of the reporting date, through the settlement date with the change in fair value recognized as compensation expense over that period. See Note 12. Stock-Based and Other Compensation Plans . Pension and Other Postretirement Benefit Plans We recognize the funded status (the difference between the fair value of plan assets and the projected benefit obligation) of defined benefit pension, restoration and other postretirement benefit plans in the consolidated balance sheets, with a corresponding adjustment to AOCL, net of tax. The amount remaining in AOCL at December 31, 2016 represents unrecognized net actuarial loss and unrecognized prior service cost related to our restoration plan. These amounts are currently being recognized as net periodic benefit cost pursuant to our historical accounting policy for amortizing such amounts. Any actuarial gains and losses that arise during the plan year, but which are not required to be recognized as net periodic benefit cost in the same period, are recognized as a component of AOCL. In third quarter 2015, we completed the process of terminating our noncontributory, tax-qualified defined benefit pension plan through the purchase of annuities for the remaining participants. As a result, we reclassified all remaining unamortized prior service cost and actuarial losses relating to the pension plan from AOCL to earnings. Income Taxes Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized when items of income and expense are recognized in the financial statements in different periods than when recognized in the applicable tax return. Deferred tax assets arise when expenses are recognized in the financial statements before the tax return or when income items are recognized in the tax return prior to the financial statements. Deferred tax assets also arise when operating losses or tax credits are available to offset tax payments due in future years. Deferred tax liabilities arise when income items are recognized in the financial statements before the tax returns or when expenses are recognized in the tax return prior to the financial statements. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the date when the change in the tax rate was enacted. In addition, we provide a deferred tax liability for the US and foreign tax rate differences for the future additional US tax liability on accumulated undistributed foreign earnings of our foreign subsidiaries, net of estimated foreign tax credits. See Note 11. Income Taxes . Treasury Stock We record treasury stock purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as reductions in shareholders’ equity in the consolidated balance sheets. Revenue Recognition and Imbalances We record revenues from the sales of crude oil, natural gas and NGLs when the product is delivered at a fixed or determinable price, title has transferred and collectibility is reasonably assured. Historically, we had certain immaterial domestic natural gas sales agreements for which we previously used the entitlement method to account for imbalances. In 2016, we divested assets which were subject to this accounting and therefore, we no longer have contracts that are accounted for under the entitlement method. Basic and Diluted Earnings (Loss) Per Share Attributable to Noble Energy Basic earnings (loss) per share (EPS) of our common stock is computed on the basis of the weighted average number of shares outstanding during each period. The diluted EPS of our common stock includes the effect of outstanding common stock equivalents such as stock options, shares of restricted stock, and/or shares of our stock held in a rabbi trust, except in periods in which there is a net loss. Contingencies We are subject to legal proceedings, claims and liabilities that arise in the ordinary course of business. We accrue for losses associated with legal claims when such losses are considered probable and the amounts can be reasonably estimated. See Note 18. Commitments and Contingencies . We self-insure the medical and dental coverage provided to certain employees, and the deductibles for workers’ compensation, automobile liability and general liability coverage. Liabilities are accrued for self-insured claims, or when estimated losses exceed coverage limits, and when sufficient information is available to reasonably estimate the amount of the loss. Foreign Currency The US dollar is considered the functional currency for each of our international operations. Transactions that are completed in foreign currencies are remeasured into US dollars and recorded in the financial statements at prevailing foreign exchange rates. Transaction gains or losses are included in other non-operating (income) expense, net in the consolidated statements of operations. Segment Information Accounting policies for geographical segments are the same as those described above. Transfers between segments are accounted for at market value. We do not consider interest income and expense or income tax benefit or expense in our evaluation of the performance of geographical segments. See Note 15. Segment Information . Changes in Shareholders’ Equity On April 28, 2015, our shareholders voted to approve an amendment to the Company’s Certificate of Incorporation to increase the number of authorized shares of our common stock from 500 million to 1 billion shares. Recently Issued Accounting Standards Consolidation - Interests Held through Related Parties That Are under Common Control In October 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2016-17 (ASU 2016-17): Consolidation - Interests Held through Related Parties That Are under Common Control. The update changes the process through which a reporting entity determines whether it is the primary beneficiary of a variable interest entity (VIE). As a result, the single decision maker of a VIE uses economic exposure to determine its classification as the primary beneficiary as opposed to evaluating which party is most closely associated with the VIE. In February 2015, the FASB issued ASU 2015-02, which changed the guidance as to whether an entity is a variable interest entity (VIE) or a voting interest entity and how related parties are considered in the VIE model. During third quarter 2016, Noble Midstream Partners closed on its initial public offering of common units. Under the provisions of both Accounting Standards Updates, Noble Midstream Partners is considered a VIE, and Noble Energy is considered the primary beneficiary of that VIE. We have adopted these provisions, which did not have a material effect on our consolidated financial statements or related disclosures. Leases In February 2016, the FASB issued Accounting Standards Update No. 2016-02 (ASU 2016-02): Leases. The guidance requires lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by leases with terms of more than 12 months. This ASU also requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. The standard will be effective for annual and interim periods beginning after December 15, 2018, with earlier application permitted. In the normal course of business, we enter into capital and operating lease agreements to support our exploration and development operations and lease assets such as drilling rigs, platforms, storage facilities, field services and well equipment, pipeline capacity, office space and other assets. We believe the adoption and implementation of this ASU will likely have a material impact on our balance sheet resulting from an increase in both assets and liabilities relating to our leasing activities. As part of our assessment to date, we have formed an implementation work team, prepared educational and training materials pertinent to this ASU and have begun contract review and documentation. Compensation - Stock Compensation In March 2016, the FASB issued Accounting Standards Update No. 2016-09 (ASU 2016-09): Compensation - Stock Compensation , to reduce complexity and enhance several aspects of accounting and disclosure for share-based payment transactions, including the accounting for income taxes, award forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. The ASU will be effective for annual and interim periods beginning after December 15, 2016, with earlier application permitted. Certain aspects of this guidance will require retrospective application while other aspects are to be applied prospectively. Based upon our evaluation, the adoption of this ASU will not have a material effect on our consolidated financial statements or related disclosures. Financial Instruments - Credit Losses In June 2016, the FASB issued Accounting Standards Update No. 2016-13 (ASU 2016-13): Financial Instruments - Credit Losses , which replaces the incurred loss impairment methodology in current US GAAP with a methodology that reflects expected credit losses. The update is intended to provide financial statement users with more useful information about expected credit losses. The amended guidance is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. We are currently evaluating the effect, if any, that the guidance will have on our consolidated financial statements and related disclosures. Inventory In July 2015, the FASB issued Accounting Standards Update No. 2015-11 (ASU 2015-11): Simplifying the Measurement of Inventory , effective for annual and interim periods beginning after December 15, 2016. ASU 2015-11 changes the inventory measurement principle for entities using the first-in, first out (FIFO) or average cost methods. For entities utilizing one of these methods, the inventory measurement principle will change from lower of cost or market to the lower of cost and net realizable value. We elected to early adopt this ASU as of December 31, 2016 and have applied the new measurement principle to our inventory balance. Adoption of this ASU did not have a material impact on our consolidated financial statements or related disclosures. Revenue Recognition In May 2014, the FASB issued Accounting Standards Update No. 2014-09 (ASU 2014-09), which creates Topic 606, Revenue from Contracts with Customers . In summary, revenue recognition would occur upon the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Additionally, A |
Additional Financial Statement
Additional Financial Statement Information | 12 Months Ended |
Dec. 31, 2016 | |
Additional Financial Statement Information [Abstract] | |
Additional Financial Statement Information | Note 2. Additional Financial Statement Information Additional statements of operations information is as follows: Year Ended December 31, (millions) 2016 2015 2014 Production Expense Lease Operating Expense $ 542 $ 563 $ 593 Production and Ad Valorem Taxes 78 127 184 Transportation and Gathering Expense (1) 463 289 168 Total $ 1,083 $ 979 $ 945 Exploration Expense Leasehold Impairment and Amortization (2) 148 113 43 Dry Hole Cost (2) 579 266 226 Seismic, Geological and Geophysical 76 34 86 Staff Expense 77 43 72 Other 45 32 71 Total 925 488 498 Other Operating (Income) Expense, Net Marketing Expense (3) 58 33 16 Loss on Terminated Contract (4) 41 — — Gain on Divestitures, Net (5) (238 ) — (73 ) Corporate Restructuring Expense (6) 8 51 — Gain on Debt Extinguishment (7) (80 ) — — Pension Plan Expense (8) — 88 — Impact of Rosetta Merger (9) (25 ) 81 — Other, Net 70 96 49 Total $ (166 ) $ 349 $ (8 ) Other Non-Operating (Income) Expense, Net Deferred Compensation Expense (Income) (10) $ 11 $ (12 ) $ (25 ) Other (Income) Expense, Net (2 ) (3 ) (1 ) Total $ 9 $ (15 ) $ (26 ) (1) Certain of our revenue received from purchasers was historically presented with deductions for transportation, gathering, fractionation or processing costs. Beginning in 2016, we have changed our presentation of revenue to no longer include these expenses as deductions from revenue. These costs are now included within production expense. Prior year amounts of $50 million and $14 million for the years ended December 31, 2015 and 2014, respectively, have been reclassified to transportation and gathering expense to conform to the current presentation. (2) See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs . (3) Amounts represent expense for unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments. Prior year amounts of $33 million and $16 million for the years ended December 31, 2015 and 2014, respectively, were previously presented within transportation and gathering expense. These amounts have been reclassified to conform to the current presentation. See Note 18. Commitments and Contingencies . (4) Amount relates to the termination of a rig contract offshore Falkland Islands as a result of a supplier's non-performance. (5) Includes gain related to the sale of 3.5% working interest in the Tamar field, offshore Israel. See Note 3. Acquisitions, Divestitures and Merger . (6) Amount represents expenses associated with organizational activities. (7) Amount relates to the tendering of senior notes assumed in the Rosetta Merger. See Note 10. Long-Term Debt . (8) Amount includes reclassification of the actuarial loss from AOCL related to the re-measurement and termination of our defined benefit pension plan to net income (loss). (9) Amounts represent a purchase price allocation adjustment in 2016 and merger expenses in 2015. See Note 3. Acquisitions, Divestitures and Merger . (10) Amounts represent increases (decreases) in the fair values of shares of our common stock held in a rabbi trust and mutual funds. Additional balance sheet information is as follows: December 31, (millions) 2016 2015 Accounts Receivable, Net Commodity Sales $ 403 $ 298 Joint Interest Billings 106 20 Proceeds Receivable (1) 40 — Other 86 151 Allowance for Doubtful Accounts (20 ) (19 ) Total $ 615 $ 450 Other Current Assets Inventories, Materials and Supplies $ 71 $ 92 Inventories, Crude Oil 18 23 Assets Held for Sale (2) 18 67 Restricted Cash (3) 30 — Prepaid Expenses and Other Assets, Current 23 34 Total $ 160 $ 216 Other Noncurrent Assets Equity Method Investments $ 400 $ 453 Mutual Fund Investments 71 90 Other Assets, Noncurrent 37 77 Total $ 508 $ 620 Other Current Liabilities Production and Ad Valorem Taxes $ 115 $ 166 Commodity Derivative Liabilities, Current 102 — Income Taxes Payable 53 86 Asset Retirement Obligations, Current 160 128 Interest Payable 76 83 Current Portion of Capital Lease and Other Obligations 63 53 Other Liabilities, Current 173 161 Total $ 742 $ 677 Other Noncurrent Liabilities Deferred Compensation Liabilities, Noncurrent $ 218 $ 217 Asset Retirement Obligations, Noncurrent 775 861 Production and Ad Valorem Taxes 47 68 Other Liabilities, Noncurrent 63 73 Total $ 1,103 $ 1,219 (1) Proceeds relate to our farm-out of a 35% interest in Block 12 offshore Cyprus and were received in January 2017. See Note 3. Acquisitions, Divestitures and Merger . (2) Assets held for sale at December 31, 2016 included assets in the Greeley Crescent area of the DJ Basin. Assets held for sale at December 31, 2015 included the Karish and Tanin natural gas discoveries, offshore Israel. See Note 3. Acquisitions, Divestitures and Merger . (3) Represents amount held in escrow at December 31, 2016 for the purchase of certain Permian Basin properties. See Note 3. Acquisitions, Divestitures and Merger . Supplemental statements of cash flow information is as follows: Year Ended December 31, (millions) 2016 2015 2014 Cash Paid During the Year For Interest, Net of Amount Capitalized $ 327 $ 260 $ 189 Income Taxes Paid, Net 236 202 150 Non-Cash Financing and Investing Activities Increase in Capital Lease and Other Obligations 5 55 110 |
Merger, Acquisitions and Divest
Merger, Acquisitions and Divestitures | 12 Months Ended |
Dec. 31, 2016 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Acquisitions, Divestitures and Merger | Note 3. Acquisitions, Divestitures and Merger Pending Acquisition of Clayton Williams Energy, Inc. On January 13, 2017 we executed a definitive agreement to acquire all of the outstanding common stock of Clayton Williams Energy, Inc. for $2.7 billion in Noble Energy stock and cash. The transaction has been unanimously approved by the Boards of Directors of both Noble Energy and Clayton Williams Energy and is subject to approval by stockholders of Clayton Williams Energy. If approved, Clayton Williams Energy stockholders will receive 2.7874 shares of Noble Energy common stock and $34.75 in cash for each share of common stock held. In the aggregate, this totals 55 million shares of Noble Energy stock and $665 million in cash. The value of the transaction, based on Noble Energy's closing stock price as of January 13, 2017, is approximately $3.2 billion in the aggregate including the assumption of approximately $500 million in net debt. We intend to fund the cash portion of the acquisition through a draw on our Revolving Credit Facility. Closing is expected to occur second quarter 2017 and is subject to customary regulatory approvals, approval by the holders of a majority of Clayton Williams Energy common stock, and certain other conditions. Property Acquisition In fourth quarter 2016, we entered an agreement to purchase Permian Basis properties, including seven producing wells. The acquisition, which has a total transaction price of $295 million , will increase our contiguous acreage position in the Reeves County area. In December 2016, we paid initial consideration of $30 million into an escrow account, which is reflected as a restricted asset in our consolidated balance sheet. We paid the remaining consideration and completed the acquisition in January 2017. Termination of Marcellus Shale JDA In fourth quarter 2016, we and CONSOL agreed to terminate our 50-50 Joint Development Agreement (JDA) in the Marcellus Shale. In connection with the terminated JDA, we executed and closed an exchange agreement whereby we and CONSOL each transferred all of our interest in a portion of co-owned properties to one another. As a result, we now hold an almost 100% operated working interest in approximately 363,000 acres, primarily located in northwest West Virginia. In addition to the acreage and production realignment between the two companies, we remitted a cash payment of approximately $213 million to CONSOL at closing. Terminating the JDA resulted in the elimination of the remaining outstanding carried cost obligation due from us. No gain or loss was recognized on the exchange. See Supplementary Data – Supplemental Oil and Gas Information (Unaudited) , below, for discussion of proved reserves divested in connection with the transaction. DJ Acreage Exchange We closed a cashless acreage exchange in the DJ Basin receiving approximately 11,700 net acres within our Wells Ranch development area in exchange for approximately 13,500 net acres primarily from our Bronco area. No gain or loss was recognized. Divestitures We maintain an ongoing portfolio management program. Accordingly, we may periodically divest assets or engage in acreage exchanges. 2016 Asset Sales During 2016, we engaged in the following sales transactions: • entered an agreement to divest certain producing and non-producing properties covering approximately 33,100 net acres in the DJ Basin for proceeds of $505 million . We closed the sale on a portion of the properties in 2016, receiving proceeds of $486 million . We expect to close the sale of the remaining properties, which are classified as held for sale at December 31, 2016, and receive the remai n ing proceeds, subject to post-close adjustments, in mid-2017. Proceeds were applied to reduce field basis with no recognition of gain or loss. • sold additional DJ Basin non-producing properties, certain Eagle Ford properties, our Bowdoin property in northern Montana, and certain other smaller onshore US properties, generating total net proceeds of $152 million , a net loss of $23 million on the Bowdoin sale, and no further gain or loss recognized on the remaining transactions. • sold our 47% interest in the Alon A and Alon C licenses, offshore Israel, which included the Karish and Tanin fields, for a total sales price of $73 million ( $67 million for asset consideration and $6 million from cost adjustments). Proceeds were applied to reduce field basis with no recognition of gain or loss. • sold a 3.5% working interest in the Tamar field, offshore Israel, in compliance with the terms of the Israel Natural Gas Framework, which requires us to reduce our ownership interest in Tamar to 25% by year-end 2021. The sales price totaled $431 million , and we received net cash proceeds of $316 million , after consideration of timing and tax adjustments, at closing. Proceeds were ratably applied to the field's basis and resulted in the recognition of a $261 million gain. • received proceeds of $131 million related to a farm-out agreement for a 35% interest in Block 12, offshore Cyprus, which includes the Aphrodite natural gas discovery. We received the remaining proceeds of $ 40 million in January 2017. Proceeds were applied to reduce field basis with no recognition of gain or loss. See Supplementary Data – Supplemental Oil and Gas Information (Unaudited) , below, for discussion of proved reserves divested in connection with the above transactions. 2015 Asset Sales In 2015, we sold certain non-strategic onshore US properties, receiving proceeds of $151 million , with no gain or loss recorded. 2014 Asset Sale s In 2014, we sold certain non-strategic onshore US properties, receiving proceeds of $135 million , and recorded a net gain of $36 million . We also sold our China assets, receiving proceeds of $186 million , and recorded a gain of $35 million . Aggregated information regarding assets sold is as follows: Year Ended December 31, (millions) 2016 2015 2014 Sales Proceeds $ 1,241 $ 151 $ 321 Less Net Book Value of Assets Sold (993 ) (156 ) (297 ) Asset Retirement Obligations Associated with Assets Sold 7 8 48 Goodwill Allocated to Assets Sold — (4 ) (7 ) Other Closing Adjustments (17 ) 1 8 Gain on Divestitures, Net $ 238 $ — $ 73 Rosetta Merger On July 20, 2015, Noble Energy completed the merger of Rosetta into a subsidiary of Noble Energy (Rosetta Merger). The results of Rosetta's operations since the merger date are included in our consolidated statement of operations. The merger was effected through the issuance of approximately 41 million shares of Noble Energy common stock in exchange for all outstanding shares of Rosetta using a ratio of 0.542 of a share of Noble Energy common stock for each share of Rosetta common stock and the assumption of Rosetta's liabilities, including approximately $2 billion fair value of outstanding debt. The merger added two new onshore US shale positions to our portfolio including approximately 50,000 net acres in the Eagle Ford Shale and 54,000 net acres in the Permian Basin ( 45,000 acres in the Delaware Basin and 9,000 acres in the Midland Basin). In connection with the Rosetta Merger, we incurred merger-related costs of approximately $81 million , including (i) $66 million of severance, consulting, investment, advisory, legal and other merger-related fees, and (ii) $15 million of noncash share-based compensation expense, all of which were expensed and are included in Other Operating (Income) Expense, Net. Purchase Price Allocation The merger was accounted for as a business combination, using the acquisition method. The following table represents the final allocation of the total purchase price of Rosetta to the assets acquired and the liabilities assumed based on the fair values at the merger date, with any excess of the purchase price over the estimated fair values of the identifiable net assets acquired recorded as goodwill. The following table sets forth our final purchase price allocation: (in millions, except stock price) Shares of Noble Energy common stock issued to Rosetta shareholders 41 Noble Energy common stock price on July 20, 2015 $ 36.97 Fair value of common stock issued $ 1,518 Plus: fair value of Rosetta's restricted stock awards and performance awards assumed 10 Plus: Rosetta stock options assumed 1 Total purchase price $ 1,529 Plus: liabilities assumed by Noble Energy Accounts Payable 100 Current Liabilities 37 Long-Term Debt 1,992 Other Long Term Liabilities 23 Asset Retirement Obligation 27 Total purchase price plus liabilities assumed $ 3,708 Fair Value of Rosetta Assets Cash and Equivalents $ 61 Other Current Assets 76 Derivative Instruments 209 Oil and Gas Properties: Proved Properties 1,613 Undeveloped Leaseholds 1,355 Gathering and Processing Assets 207 Asset Retirement Obligation 27 Other Property Plant and Equipment 5 Long Term Deferred Tax Asset 17 Implied Goodwill (1) 138 Total Asset Value $ 3,708 (1) As of December 31, 2015 , our preliminary purchase price allocation reflected goodwill of $163 million based on the fair value of assets acquired and liabilities assumed at the Rosetta Merger date. In conducting our goodwill impairment test as of December 31, 2015 , we determined that our goodwill balance was no longer recoverable and fully impaired it, resulting in a goodwill impairment charge in fourth quarter 2015. In second quarter 2016, we finalized the purchase price allocation and recorded a $25 million gain to other operating expense, net driven by adjustments made based on the filing of the final Rosetta federal income tax return for the period ending on the Rosetta Merger date. The fair value measurements of derivative instruments assumed were determined based on published forward commodity price curves as of the date of the merger and represent Level 2 inputs. Derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates. The fair value measurements of long-term debt were estimated based on published market prices and represent Level 1 inputs. The long-term debt balance includes amounts outstanding under Rosetta's credit facility which was assumed by Noble and repaid subsequent to the merger in third quarter 2015. The fair value measurements of crude oil and natural gas properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of crude oil and natural gas properties included estimates of: (i) recoverable reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average cost of capital rate. These inputs required significant judgments and estimates by management at the time of the valuation and are the most sensitive and may be subject to change. The results of operations attributable to Rosetta are included in our consolidated statement of operations beginning on July 21, 2015. Revenues of $457 million and pre-tax net loss of $20 million , exclusive of a $25 million purchase price allocation adjustment, from Rosetta were generated for the year ended December 31, 2016. Revenues of $181 million and pre-tax net loss of $120 million , inclusive of a $163 million goodwill impairment, from Rosetta were generated from July 21, 2015 to December 31, 2015. Pro Forma Financial Information The following pro forma condensed combined financial information was derived from the historical financial statements of Noble Energy and Rosetta and gives effect to the merger as if it had occurred on January 1, 2014. The below information reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including (i) Noble Energy's common stock and equity awards issued to convert Rosetta's outstanding shares of common stock and equity awards as of the closing date of the merger, (ii) adjustments to conform Rosetta's historical policy of accounting for its oil and natural gas properties from the full cost method to the successful efforts method of accounting, (iii) depletion of Rosetta's fair-valued proved oil and gas properties, and (iv) the estimated tax impacts of the pro forma adjustments. Additionally, pro forma earnings for the year ended December 31, 2015 were adjusted to exclude $81 million of merger-related costs incurred by Noble Energy and $37 million incurred by Rosetta. The pro forma results of operations do not include any cost savings or other synergies that may result from the Rosetta Merger or any estimated costs that have been or will be incurred by us to integrate the Rosetta assets. The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Rosetta Merger taken place on January 1, 2014; furthermore, the financial information is not intended to be a projection of future results. Year Ended December 31, (in millions, except per share amounts) 2016 (1) 2015 2014 Revenues $ 3,491 $ 3,478 $ 6,126 Net (Loss) Income Attributable to Noble Energy (998 ) (2,393 ) 1,607 Earnings (Loss) Per Share Basic $ (2.32 ) $ (5.64 ) $ 4.01 Diluted (2.32 ) (5.64 ) 3.94 (1) No pro forma adjustments were made for the period as Rosetta's operations are included in our consolidated historical results. |
Noble Midstream Partners LP
Noble Midstream Partners LP | 12 Months Ended |
Dec. 31, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Noble Midstream Partners LP | Note 4. Noble Midstream Partners LP Noble Midstream Partners LP In December 2014, we formed Noble Midstream Partners LP, a growth-oriented Delaware master limited partnership, to own, operate, develop and acquire a wide range of domestic midstream infrastructure assets. Noble Midstream Partners' current areas of focus are in the DJ Basin in Colorado and in the Delaware Basin within the Permian Basin in Texas. Initial Public Offering of Noble Midstream Partners LP On September 15, 2016 , Noble Midstream Partners common units began trading on the New York Stock Exchange under the symbol "NBLX." On September 20, 2016 , Noble Midstream Partners completed its public offering of 14,375,000 common units representing limited partner interests in Noble Midstream Partners, which included 1,875,000 common units issued pursuant to the underwriters’ exercise of their option to purchase additional common units, at a price to the public of $22.50 per common unit ( $21.21 per common unit, net of underwriting discounts). In exchange for the contributed assets, Noble Energy received: • 1,527,584 common units, representing a 4.8% limited partner interest in Noble Midstream Partners; • 15,902,584 subordinated units, representing an approximate 50.0% limited partner interest in Noble Midstream Partners; • incentive distribution rights in Noble Midstream Partners; and • the right to receive a cash distribution from Noble Midstream Partners. In addition and concurrent with the closing of the offering, the General Partner retained a non-economic general partnership interest in Noble Midstream Partners, which is not entitled to receive cash distributions. Noble Midstream Partners generated net proceeds of $299 million from the issuance of common units to the public, after deducting the underwriting discount, structuring fees and estimated offering expenses of $24 million . |
Asset Impairments
Asset Impairments | 12 Months Ended |
Dec. 31, 2016 | |
Asset Impairment Charges [Abstract] | |
Asset Impairments | Note 5. Asset Impairments Pre-tax (non-cash) asset impairment charges were as follows: Year Ended December 31, (millions) 2016 2015 2014 Onshore US $ — $ — $ 42 Deepwater Gulf of Mexico — 158 350 Israel 88 36 14 Equatorial Guinea — 339 — North Sea — — 94 Other International and Corporate 4 — — Total $ 92 $ 533 $ 500 2016 Asset Impairments While the Leviathan development project was not formally sanctioned at December 31, 2016, in fourth quarter 2016, we selected the initial development concept for the first phase of development of the Leviathan natural gas project and wrote off $88 million associated with certain development concepts that were not selected. 2015 Asset Impairments During 2015, certain properties in the deepwater Gulf of Mexico, offshore Israel and offshore Equatorial Guinea were written down to their estimated fair values using a discounted cash flow model. The cash flow model included management’s estimates of future crude oil and natural gas production, commodity prices based on forward commodity price curves or contract prices as of the date of the estimate, operating and development costs, and discount rates. Impairment charges of $481 million resulted from reductions in the forward crude oil prices as of December 31, 2015. We also recorded impairment charges of approximately $47 million primarily related to revisions in expected field abandonment and other costs for properties in the deepwater Gulf of Mexico and offshore Israel and $5 million related to the pending sale of our interest in the Alon A and Alon C licenses, offshore Israel, which included the Karish and Tanin fields. 2014 Asset Impairments As a result of declining crude oil prices at the end of 2014, we recorded impairment charges of $250 million related to certain onshore US and deepwater Gulf of Mexico properties. We also recorded impairment charges of $74 million for the South Raton development, deepwater Gulf of Mexico, due to mechanical issues; $51 million related to asset retirement obligation increases for certain properties in the deepwater Gulf of Mexico and offshore Israel; $31 million related to the reclassification of certain non-strategic properties as assets held for sale; and $94 million related to North Sea MacCulloch field abandonment. |
Capitalized Exploratory Well Co
Capitalized Exploratory Well Costs | 12 Months Ended |
Dec. 31, 2016 | |
Capitalized Exploratory Well Costs [Abstract] | |
Capitalized Exploratory Well Costs | Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs Capitalized Exploratory Well Costs We capitalize exploratory well costs until a determination is made that the well has found proved reserves or is deemed noncommercial. If a well is deemed to be noncommercial, the well costs are immediately charged to exploration expense as dry hole cost. Changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and subsequently expensed in the same period: Year Ended December 31, (millions) 2016 2015 2014 Capitalized Exploratory Well Costs, Beginning of Period $ 1,353 $ 1,337 $ 1,301 Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves 84 123 316 Divestitures and Other (1) (143 ) — — Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves or to Assets Held for Sale (2) (1 ) (19 ) (196 ) Capitalized Exploratory Well Costs Charged to Expense (3) (525 ) (88 ) (84 ) Capitalized Exploratory Well Costs, End of Period $ 768 $ 1,353 $ 1,337 (1) The 2016 amount relates to our farm-down of a 35% interest in Block 12 offshore Cyprus to a new partner. (2) The 2015 amount relates primarily to onshore US exploration activity. The 2014 amount relates primarily to the Dantzler well (deepwater Gulf of Mexico), for which we sanctioned a development plan, and the Karish and Tanin wells (offshore Israel), which were reclassified to assets held for sale. (3) Capitalized exploratory well costs charged to expense are included within exploration expense in our consolidated statements of operations. The 2016 amount relates primarily to discoveries offshore West Africa. Following review of additional 3D seismic data, we determined these discoveries were impaired in the current forward outlook for crude oil prices. We also incurred expenses associated with our Silvergate exploratory well in the deepwater Gulf of Mexico. The well did not encounter commercial hydrocarbons and has been plugged and abandoned. The 2015 amount relates primarily to northeast Nevada. After assessing its commercial viability in the current commodity price environment, we elected to discontinue our exploration efforts. The 2014 amount relates to non-strategic onshore US exploratory well costs and the Scotia exploratory well (offshore Falkland Islands) which were determined to be non-commercial. The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced, and the number of projects that have been capitalized for a period greater than one year: December 31, (millions) 2016 2015 2014 Exploratory Well Costs Capitalized for a Period of One Year or Less $ 69 $ 95 $ 247 Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling 699 1,258 1,090 Balance at End of Period $ 768 $ 1,353 $ 1,337 Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling 10 14 13 The following table provides a further aging of those exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling as of December 31, 2016 : Suspended Since Country/Project (millions) Total 2014 - 2015 2012 - 2013 2011 & Prior Progress Deepwater Gulf of Mexico Troubadour 52 5 47 — Evaluating development scenarios for this 2013 natural gas discovery including subsea tieback to existing infrastructure. Katmai 98 98 — — Evaluating development scenarios for this 2014 crude oil discovery. In second quarter 2016, drilling operations at the Katmai 2 appraisal well, located in Green Canyon Block 39, were temporarily abandoned as a result of encountering high pressure in the untested fault block. We are assessing plans to progress appraisal and are evaluating tie-back options. Offshore Equatorial Guinea Felicita (Block O) 45 7 — 9 — 29 Evaluating regional development scenarios for this 2008 gas discovery. During 2014, we conducted additional seismic activity over Blocks I and O and in early 2016, we began analyzing, interpreting and evaluating the acquired seismic data. Yolanda (Block I) 22 3 5 14 A data exchange agreement for the 2007 Yolanda condensate and natural gas discovery has been executed between the governments of Equatorial Guinea and Cameroon. Our natural gas development team is working with the governments of Equatorial Guinea and Cameroon to evaluate natural gas monetization options for both Yolanda and YoYo (Cameroon) discoveries. Offshore Cameroon YoYo (YoYo Block) 54 6 13 35 A data exchange agreement for the 2007 YoYo condensate and natural gas discovery has been executed between the governments of Equatorial Guinea and Cameroon. Our natural gas development team is working with the governments of Equatorial Guinea and Cameroon to evaluate natural gas monetization options for both Yolanda (Equatorial Guinea) and YoYo discoveries. Offshore Israel Leviathan 199 18 77 104 Our development plan was approved by the Government of Israel and we are engaged in natural gas marketing activities to meet both Israeli domestic and regional export demands. We anticipate near-term project sanction and commencement of development activities. Leviathan-1 Deep 85 7 51 27 The well did not reach the target interval in 2012. We are developing future drilling plans to test this deep oil concept, which is held by the Leviathan Development and Production Leases. Dalit 31 4 7 20 Our development plan was approved by the Government of Israel to develop this 2009 natural gas discovery with a tie-in to existing infrastructure at Tamar. Offshore Cyprus Cyprus 89 12 54 23 During first quarter 2016, we received proceeds of $131 million from our 35% farm-down of interest with a partner in Block 12. In second quarter 2016, we submitted an updated development plan and continue to work with the Government of Cyprus to obtain approval of the development plan and the subsequent issuance of an Exploitation License. Receiving an Exploitation License will allow us and our partners to perform the necessary engineering and design studies and progress the project to final investment decision. Other Projects less than $20 million 24 23 — 1 Continuing to assess and evaluate wells. Total $ 699 $ 183 $ 263 $ 253 Undeveloped Leasehold Costs Undeveloped leasehold costs as of December 31, 2016 totaled $2.2 billion , including $2.1 billion related to onshore US unproved properties, $105 million related to deepwater Gulf of Mexico unproved properties, and $32 million related to international unproved properties. We evaluate our exploration opportunities as part of our periodic impairment review. If, based upon a change in exploration plans, availability of capital and suitable rig and drilling equipment, resource potential, comparative economics, changing regulations and/or other factors, an impairment is indicated, we record either (1) impairment expense related to individually significant leases or (2) a decrease in the valuation of our pool of individually insignificant leases. During 2016, we completed our geological evaluation of certain deepwater Gulf of Mexico and offshore Falkland Islands leases and licenses and determined that several, representing $127 million of undeveloped leasehold cost, should be relinquished or exited. As a result, we recognized $93 million of undeveloped leasehold impairment expense and recorded a $34 million decrease in our valuation pool of individually insignificant leases. |
Equity Method Investments
Equity Method Investments | 12 Months Ended |
Dec. 31, 2016 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Equity Method Investments | Note 7. Equity Method Investments Equity Method Investments Equity method investments are included in other noncurrent assets in the consolidated balance sheets, and our share of earnings is reported as income from equity method investees in the consolidated statements of operations. Our share of income taxes incurred directly by the equity method investees is reported in income from equity method investees and is not included in our income tax provision in our consolidated statements of operations. Investments accounted for under the equity method consist primarily of the following: • 50% interest in CONE Gathering LLC (CONE Gathering), which owns and operates natural gas gathering facilities servicing our properties in the Marcellus Shale; • 33.5% interest in CONE Midstream Partners, LP (CONE Midstream), a public master limited partnership, which constructs, owns and operates natural gas gathering and other midstream energy assets in support of our Marcellus Shale activities; • 45% interest in Atlantic Methanol Production Company, LLC (AMPCO), which owns and operates a methanol plant and related facilities in Equatorial Guinea; and • 28% interest in Alba Plant LLC (Alba Plant), which owns and operates a liquefied petroleum gas processing plant in Equatorial Guinea. CONE Midstream Dropdown Transaction In fourth quarter 2016, CONE Midstream, completed its first acquisition of midstream assets (dropdown) from CONE Gathering since its initial public offering in 2014. CONE Gathering subsequently distributed $70 million cash and additional CONE Midstream common units to us. We currently own 7,110,638 common units and 14,581,560 subordinated units of CONE Midstream. Equity method investments are as follows: December 31, (millions) 2016 2015 Equity Method Investments CONE Investments (1) $ 172 $ 214 AMPCO 120 120 Alba Plant 82 87 Other 26 32 Total Equity Method Investments $ 400 $ 453 (1) CONE Investments include CONE Midstream and CONE Gathering. Other At December 31, 2016 , consolidated retained earnings included $95 million related to the undistributed earnings of equity method investees. The carrying value of our AMPCO investment was $12 million higher than the underlying net assets of the investee at December 31, 2016 . The difference is related to capitalized interest which is being amortized into earnings over the remaining useful life of the plant. Summarized, 100% combined financial information for equity method investees is as follows: December 31, (millions) 2016 2015 Balance Sheet Information Current Assets $ 313 $ 343 Noncurrent Assets 1,390 1,418 Current Liabilities 149 229 Noncurrent Liabilities 256 108 Year Ended December 31, (millions) 2016 2015 2014 Statements of Operations Information Operating Revenues $ 667 $ 645 $ 1,142 Operating Expenses 355 393 405 Operating Income 312 252 737 Other (Income) Net (7 ) (9 ) (9 ) Income Before Income Taxes 319 261 746 Income Tax Provision 60 46 172 Net Income $ 259 $ 215 $ 574 |
Derivative Instruments and Hedg
Derivative Instruments and Hedging Activities | 12 Months Ended |
Dec. 31, 2016 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Instruments and Hedging Activities | Note 8. Derivative Instruments and Hedging Activities Objective and Strategies for Using Derivative Instruments We may 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 relating to the marketing of a portion of our crude oil and natural gas production. The derivative instruments we use may include variable to fixed price commodity swaps, enhanced swaps, two-way and three-way collars, basis swaps and/or put options. The fixed price swap and two-way collar contracts entitle us (floating price payor) to receive settlement from the counterparty (fixed price payor) for each calculation period in amounts, if any, by which the settlement price for the scheduled trading days applicable for each calculation period is less than the fixed strike price or floor price. We would pay the counterparty if the settlement price for the scheduled trading days applicable for each calculation period is more than the fixed strike price or ceiling price. The amount payable by us, if the floating price is above the fixed or ceiling price, is the product of the notional quantity per calculation period and the excess of the floating price over the fixed or ceiling price in respect of each calculation period. The amount payable by the counterparty, if the floating price is below the fixed or floor price, is the product of the notional quantity per calculation period and the excess of the fixed or floor price over the floating price in respect of each calculation period. A three-way collar consists of a two-way collar contract combined with a put option contract sold by us with a strike price below the floor price of the two-way collar. We receive price protection at the purchased put option floor price of the two-way collar if commodity prices are above the sold put option strike price. If commodity prices fall below the sold put option strike price, we receive the cash market price plus the delta between the two put option strike prices. This type of instrument allows us to capture more value in a rising commodity price environment, but limits our benefits in a downward commodity price environment. For put options, we typically pay a premium to the counterparty in exchange for the sale of the instrument. If the index price is below the floor price of the put option, we receive the difference between the floor price and the index price multiplied by the contract volumes less the option premium at the time of settlement. If the index price settles at or above the floor price of the put option, we pay only the put option premium at the time of settlement. We had no outstanding put options as of December 31, 2016 . While these instruments mitigate the cash flow risk of future reductions in commodity prices, they may also curtail benefits during periods of increasing commodity prices. 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. Counterparty Credit Risk Derivative instruments expose us to counterparty credit risk. Our commodity derivative instruments are currently with a diversified group of major banks or market participants, and we monitor and manage our level of financial exposure. Our commodity derivative contracts are executed under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net settled at the time of election. We monitor the creditworthiness of our commodity derivatives counterparties. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices and could incur a loss. Unsettled Derivative Instruments As of December 31, 2016 , we had entered into the following crude oil derivative instruments: Swaps Collars Settlement Period Type of Contract Index Bbls Per Day Weighted Average Fixed Price Weighted Average Short Put Price Weighted Average Floor Price Weighted Average Ceiling Price 1H17 (1) Swaps NYMEX WTI 6,000 $ 55.08 $ — $ — $ — 1H17 (1) Two-Way Collars NYMEX WTI 2,000 — — 40.00 50.44 1H17 (1) Swaps Dated Brent 3,000 62.80 — — — 2H17 (1) Call Option (2) NYMEX WTI 3,000 — — — 60.12 2H17 (1) Swaptions (3) NYMEX WTI 3,000 50.05 — — — 2H17 (1) Swaptions (3) Dated Brent 3,000 62.80 — — — 2017 Three-Way Collars NYMEX WTI 24,000 — 39.08 47.71 61.20 2017 Two-Way Collars NYMEX WTI 7,000 — — 40.00 53.29 2017 Swaps NYMEX WTI 4,000 50.90 — — — 2017 Call Option (2) NYMEX WTI 3,000 — — — 57.00 2017 Three-Way Collars ICE Brent 2,000 — 43.00 50.00 63.15 2017 Three-Way Collars Dated Brent 2,000 — 35.00 45.00 66.33 2018 Three-Way Collars NYMEX WTI 5,000 — 43.00 50.00 68.50 2018 Swaps NYMEX WTI 5,000 54.03 — — — 2018 Swaptions (3) NYMEX WTI 3,000 56.10 — — — 2018 Three-Way Collars Dated Brent 3,000 — 40.00 50.00 70.41 (1) We traditionally enter into a hedge contract term of one year. For 2017 we have entered into various derivative hedging arrangements with a contract term of six months resulting in non-uniform annual volumes and weighted average prices. (2) We have entered into crude oil derivative enhanced swaps with strike prices that are above the market value as of trade commencement. To effect the enhanced non-cash swap structure, we sold call options to the applicable counterparty to receive the above market terms. (3) We have entered into certain derivative contracts (swaptions), which give counterparties the option to extend with similar terms for an additional 6-month or 12-month period. As of December 31, 2016 , we had entered into the following natural gas derivative instruments: Swaps Collars Settlement Period Type of Contract Index MMBtu Per Day Weighted Average Fixed Price Weighted Average Short Put Price Weighted Average Floor Price Weighted Average Ceiling Price 1H17 (1) Swaps NYMEX HH 30,000 $ 2.92 $ — $ — $ — 2H17 (1) Swaps NYMEX HH 30,000 3.45 — — — 2H17 (1) Swaptions (2) NYMEX HH 30,000 2.92 — — — 2017 Three-Way Collars NYMEX HH 210,000 — 2.54 2.96 3.62 2017 Swaps NYMEX HH 110,000 3.16 — — — 2017 Two-Way Collars NYMEX HH 70,000 — — 2.93 3.32 2018 Three-Way Collars NYMEX HH 70,000 — 2.50 2.80 3.76 (1) We traditionally enter into a hedge contract term of one year. For 2017 we have entered into various derivative hedging arrangements with a contract term of six months resulting in non-uniform annual volumes and weighted average prices. (2) We have entered into certain derivative contracts (swaptions), which give counterparties the option to extend with similar terms for an additional 6-month or 12-month period. Fair Value Amounts and Gains and Losses on Derivative Instruments The fair values of derivative instruments in our consolidated balance sheets were as follows: Fair Value of Derivative Instruments Asset Derivative Instruments Liability Derivative Instruments December 31, December 31, December 31, December 31, Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value (millions) Commodity Derivative Instruments Current Assets $ — Current Assets $ 582 Current Liabilities $ 102 Current Liabilities $ — Noncurrent Assets — Noncurrent Assets 10 Noncurrent Liabilities 14 Noncurrent Liabilities — Total $ — $ 592 $ 116 $ — The effect of derivative instruments on our consolidated statements of operations was as follows: Year Ended December 31, (millions) 2016 2015 2014 Cash (Received) Paid in Settlement of Commodity Derivative Instruments Crude Oil $ (499 ) $ (844 ) $ (34 ) Natural Gas (70 ) (147 ) 5 NGLs (1) — (18 ) — Total Cash Received in Settlement of Commodity Derivative Instruments (569 ) (1,009 ) (29 ) Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments Crude Oil 582 423 (863 ) Natural Gas 126 65 (84 ) NGLs (1) — 20 — Total Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments 708 508 (947 ) Loss (Gain) on Commodity Derivative Instruments Crude Oil 83 (421 ) (897 ) Natural Gas 56 (82 ) (79 ) NGLs (1) — 2 — Total Loss (Gain) on Commodity Derivative Instruments $ 139 $ (501 ) $ (976 ) (1) Amounts for NGLs relate to commodity derivative instruments, acquired in the Rosetta Merger, which expired as of December 31, 2015. |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2016 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | Note 9. Asset Retirement Obligations Asset retirement obligations consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. Changes in asset retirement obligations were as follows: Year Ended December 31, (millions) 2016 2015 Asset Retirement Obligations, Beginning Balance $ 989 $ 751 Liabilities Incurred 21 67 Liabilities Settled (120 ) (38 ) Revision of Estimate (3 ) 166 Accretion Expense 48 43 Asset Retirement Obligations, Ending Balance $ 935 $ 989 Year Ended December 31, 2016 Liabilities incurred were due to new wells and facilities placed into service for onshore US, deepwater Gulf of Mexico, and offshore Israel. Liabilities settled were related to wells and facilities permanently abandoned at the end of their useful lives and to assets sold. Settlements included $ 65 million related to abandonment of deepwater Gulf of Mexico properties, $ 49 million related to onshore US properties abandoned or sold, $5 million related to offshore Israel properties and $1 million related to the North Sea. Year Ended December 31, 2015 Liabilities incurred were due to new wells and facilities and included $22 million for onshore US, $16 million for deepwater Gulf of Mexico and $29 million for properties acquired in the Rosetta Merger. We settled liabilities of $23 million for the DJ Basin, $2 million for deepwater Gulf of Mexico and $13 million for the North Sea. Revisions were primarily due to changes in estimated costs for future abandonment activities and acceleration of timing of abandonment and included $96 million for the DJ Basin, $48 million for Eastern Mediterranean, $35 million for deepwater Gulf of Mexico, and decreases of $10 million for Equatorial Guinea and $3 million for other onshore US developments. |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2016 | |
Debt Disclosure [Abstract] | |
Long-term Debt | Note 10. Long-Term Debt Our debt consists of the following: December 31, December 31, (millions, except percentages) Debt Interest Rate Debt Interest Rate Revolving Credit Facility, due August 27, 2020 $ — — $ — — Noble Midstream Revolving Credit Facility, due September 20, 2021 — — — — Capital Lease and Other Obligations 375 — 403 — Term Loan Facility, due January 6, 2019 550 2.01 % — — 8.25% Senior Notes, due March 1, 2019 1,000 8.25 % 1,000 8.25 % 5.625% Senior Notes, due May 1, 2021 (1) 379 5.63 % 693 5.63 % 4.15% Senior Notes, due December 15, 2021 1,000 4.15 % 1,000 4.15 % 5.875% Senior Notes, due June 1, 2022 (1) 18 5.88 % 597 5.88 % 7.25% Senior Notes, due October 15, 2023 100 7.25 % 100 7.25 % 5.875% Senior Notes, due June 1, 2024 (1) 8 5.88 % 499 5.88 % 3.90% Senior Notes, due November 15, 2024 650 3.90 % 650 3.90 % 8.00% Senior Notes, due April 1, 2027 250 8.00 % 250 8.00 % 6.00% Senior Notes, due March 1, 2041 850 6.00 % 850 6.00 % 5.25% Senior Notes, due November 15, 2043 1,000 5.25 % 1,000 5.25 % 5.05% Senior Notes, due November 15, 2044 850 5.05 % 850 5.05 % 7.25% Senior Debentures, due August 1, 2097 84 7.25 % 84 7.25 % Total $ 7,114 $ 7,976 Unamortized Discount (23 ) (24 ) Unamortized Premium (2) 17 113 Unamortized Debt Issuance Costs (34 ) (36 ) Total Debt, Net of Discount $ 7,074 $ 8,029 Less Amounts Due Within One Year Capital Lease and Other Obligations (63 ) (53 ) Long-Term Debt Due After One Year $ 7,011 $ 7,976 (1) Represents senior notes assumed in the Rosetta Merger. See Note 3. Acquisitions, Divestitures and Merger . (2) Debt premium is attributable to senior notes assumed in the Rosetta Merger. All of our long-term debt is senior unsecured debt and is, therefore, pari passu with respect to the payment of both principal and interest. The indenture documents of each of our notes provide that we may prepay the instruments by creating a defeasance trust. The defeasance provisions require that the trust be funded with securities sufficient, in the opinion of a nationally recognized accounting firm, to pay all scheduled principal and interest due under the respective agreements. Interest on each of these issues is payable semi-annually. Revolving Credit Facility On August 27, 2015 , we amended our $4.0 billion Revolving Credit Facility to extend the maturity date to August 27, 2020. We periodically borrow amounts for working capital purposes. Our Revolving Credit Facility (i) provides for facility fee rates that range from 10 basis points to 25 basis points per year depending upon our credit rating, (ii) includes sub-facilities for short-term loans and letters of credit up to an aggregate amount of $500 million under each sub-facility and (iii) provides for interest rates that are based upon the Eurodollar rate plus a margin that ranges from 90 basis points to 150 basis points depending upon our credit rating. The Credit Agreement requires that our total debt to capitalization ratio (as defined in the Credit Agreement), expressed as a percentage, not exceed 65% at any time. A violation of this covenant could result in a default under the Credit Agreement, which would permit the participating banks to restrict our ability to access the Revolving Credit Facility and require the immediate repayment of any outstanding advances under the Revolving Credit Facility. As of December 31, 2016 , we were in compliance with our debt covenants. The Revolving Credit Facility is available for general corporate purposes. Certain lenders that are a party to the Credit Agreement have in the past performed, and may in the future from time to time perform, investment banking, financial advisory, lending or commercial banking services for us for which they have received, and may in the future receive, customary compensation and reimbursement of expenses. Noble Midstream Services Revolving Credit Facility On September 20, 2016, Noble Midstream Services LLC, a subsidiary of Noble Midstream Partners, entered into a credit agreement for a $350 million revolving credit facility (Noble Midstream Revolving Credit Facility). The Noble Midstream Revolving Credit Facility has a five year maturity and includes a letter of credit sublimit of up to $100 million for issuances of letters of credit. The borrowing capacity on the Noble Midstream Revolving Credit Facility may be increased by an additional $350 million subject to certain conditions and is available to fund working capital and to finance acquisitions and other capital expenditures of Noble Midstream Partners. Borrowings by Noble Midstream Services under the Noble Midstream Revolving Credit Facility bear interest at a rate equal to an applicable margin plus, at Noble Midstream Service's option, either: • in the case of base rate borrowings, a rate equal to the highest of (1) the prime rate, (2) the greater of the federal funds rate or the overnight bank funding rate, plus 0.5% and (3) the LIBOR for an interest period of one month plus 1.00% ; or • in the case of London interbank offered rate (LIBOR) borrowings, the offered rate per annum for deposits of dollars for the applicable interest period. The Noble Midstream Revolving Credit Facility includes certain financial covenants as of the end of each fiscal quarter, including a (1) consolidated leverage ratio to consolidated adjusted earnings before interest expense, income taxes, depreciation, depletion, and amortization (EBITDA) and (2) consolidated interest coverage ratio (each covenant as described in the Noble Midstream Revolving Credit Facility). All obligations of Noble Midstream Services, as the borrower under the Noble Midstream Revolving Credit Facility, are guaranteed by Noble Midstream Partners and all wholly-owned material subsidiaries of Noble Midstream Partners. Debt issuance costs associated with this facility were de minimis. Term Loan Agreement and Completed Tender Offers On January 6, 2016, we entered into a term loan agreement (Term Loan Facility) with Citibank, N.A., as administrative agent, Mizuho Bank, Ltd., as syndication agent, and certain other financial institutions party thereto, which provides for a three -year term loan facility for a principal amount of $1.4 billion . Provisions of the Term Loan Facility are consistent with those in the Revolving Credit Facility. Borrowings under the Term Loan Facility may be prepaid prior to maturity without premium. The Term Loan Facility accrues interest, at our option, at either (a) a base rate equal to the highest of (i) the rate announced by Citibank, N.A., as its prime rate, (ii) the Federal Funds Rate plus 0.5% , and (iii) a LIBOR plus 1.0% , plus a margin that ranges from 10 basis points to 75 basis points depending upon our credit rating, or (b) a LIBOR, plus a margin that ranges from 100 basis points to 175 basis points depending upon our credit rating. The interest rate for our Term Loan Facility is 2.01% as of December 31, 2016 . In connection with the Term Loan Facility, we launched cash tender offers for the 5.875% Senior Notes due June 1, 2024, 5.875% Senior Notes due June 1, 2022 and 5.625% Senior Notes due May 1, 2021, all of which were assumed in the Rosetta Merger. The borrowings under the Term Loan Facility were used solely to fund the tender offers. Approximately $1.4 billion of notes were validly tendered and accepted by us, with a corresponding amount borrowed under the new Term Loan Facility. As a result, we recognized a gain of $80 million which is reflected in other operating (income) expense, net in our consolidated statements of operations. In fourth quarter 2016, we prepaid $850 million of borrowings under our Term Loan Facility from cash on hand. See Note 13. Fair Value Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of debt. Debt Exchange On July 29, 2015, we completed our debt exchange offers to exchange all validly tendered and accepted senior notes assumed in the Rosetta Merger. We were able to exchange 99.4% of the outstanding Rosetta senior notes, whereby we issued (i) $693 million senior unsecured 5.625% notes due May 1, 2021 , (ii) $597 million senior unsecured 5.875% notes due June 1, 2022 and (iii) $499 million senior unsecured 5.875% notes due June 1, 2024 . We incurred financing costs of $12 million related to the debt exchange. We also repaid the balance outstanding under, and terminated, Rosetta's credit facility of $70 million . Capital Lease and Other Obligations The amounts of the capital lease obligations are based on the discounted present value of future minimum lease payments, and therefore do not reflect future cash lease payments. Amounts due within one year equal the amount by which the capital lease obligations are expected to be reduced during the next 12 months. See Note 18. Commitments and Contingencies for future capital lease payments. Annual Debt Maturities Annual maturities of outstanding debt, excluding capital lease payments, are as follows: (millions) Debt Principal Payments December 31, 2016 2017 $ — 2018 — 2019 1,550 2020 — 2021 1,379 Thereafter 3,810 Total $ 6,739 |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Note 11. Income Taxes Components of income (loss) from operations before income taxes are as follows: Year Ended December 31, (millions) 2016 2015 2014 Domestic $ (1,859 ) $ (2,338 ) $ 282 Foreign 87 119 1,428 Total $ (1,772 ) $ (2,219 ) $ 1,710 The income tax provision (benefit) consists of the following: Year Ended December 31, (millions) 2016 2015 2014 Current Taxes Federal $ (4 ) $ (1 ) $ 19 State 5 — 1 Foreign 196 107 208 Total Current $ 197 $ 106 $ 228 Deferred Taxes Federal $ (784 ) $ 216 $ 237 State (24 ) (5 ) 13 Foreign (176 ) (95 ) 18 Total Deferred $ (984 ) $ 116 $ 268 Total Income Tax Provision (Benefit) Attributable to Noble Energy $ (787 ) $ 222 $ 496 Effective Tax Rate 44.4 % (10.0 )% 29.0 % A reconciliation of the federal statutory tax rate to the effective tax rate is as follows: Year Ended December 31, (percentages) 2016 2015 2014 Federal Statutory Rate 35.0 % 35.0 % 35.0 % Effect of Earnings of Equity Method Investees 1.0 0.6 (3.3 ) Noncontrolling Interests 0.4 — — Foreign Rate Change 1.6 — — State Taxes, Net of Federal Benefit 1.3 0.3 0.8 Difference Between US and Foreign Rates (0.1 ) 2.6 (14.2 ) Foreign Exploration Loss 0.1 2.7 — Change in Valuation Allowance (2.0 ) — 1.9 Oil Profits Tax - Israel — 0.1 0.2 Tax Contingency 0.2 0.4 0.1 Accumulated Undistributed Foreign Earnings 7.2 (37.7 ) 8.2 Goodwill Impairment — (12.3 ) — Other, Net (0.3 ) (1.7 ) 0.3 Effective Rate 44.4 % (10.0 )% 29.0 % Deferred tax assets and liabilities resulted from the following: December 31, (millions) 2016 2015 Deferred Tax Assets Loss Carryforwards $ 474 $ 468 Employee Compensation and Benefits 150 151 Other 49 81 Total Deferred Tax Assets $ 673 $ 700 Valuation Allowance - Foreign Loss Carryforwards (242 ) (206 ) Net Deferred Tax Assets $ 431 $ 494 Deferred Tax Liabilities Mark to Market of Commodity Derivative Instruments 44 (128 ) Accumulated Undistributed Foreign Earnings (240 ) (368 ) Property, Plant and Equipment, Principally Due to Differences in Depreciation, Amortization, Lease Impairment and Abandonments (2,054 ) (2,824 ) Total Deferred Tax Liability $ (2,250 ) $ (3,320 ) Net Deferred Tax Liability $ (1,819 ) $ (2,826 ) Net deferred tax liabilities were classified in the consolidated balance sheets as follows: December 31, (millions) 2016 2015 Deferred Income Tax Liability - Current $ — $ — Deferred Income Tax Liability - Noncurrent (1,819 ) (2,826 ) Net Deferred Tax Liability $ (1,819 ) $ (2,826 ) Deferred Tax Assets In assessing the realizability of deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income in the appropriate tax jurisdictions during the periods in which those temporary differences become deductible. We consider the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, we believe it is more likely than not that we will realize the benefits of these deductible differences at December 31, 2016 . The amount of the deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced. The valuation allowance on the deferred tax assets associated with foreign loss carryforwards totaled $242 million in 2016 and $206 million in 2015 . The changes to the valuation allowance for the loss carryforwards between periods were attributable to changes in losses on projects in new venture activities which are not yet commercial. During 2015, as a result of cash repatriation, we released a valuation allowance of $60 million on our foreign tax credits. Rosetta Merger On July 20, 2015, we completed the Rosetta Merger. For federal income tax purposes, the merger qualified as a tax free merger and we acquired carryover tax basis in Rosetta’s assets and liabilities. Rosetta had a net deferred tax asset resulting from its federal net operating loss (NOL) estimated at $681 million through the date of acquisition. The merger resulted in a change of control for federal income tax purposes, and the NOL’s usage will be subject to an annual limitation in part based on Rosetta’s value at the date of the merger. We anticipate full utilization of the total NOL prior to its expiration. Accumulated Undistributed Earnings of Foreign Subsidiaries Our foreign subsidiaries’ undistributed earnings of approximately $1.6 billion at December 31, 2016 are no longer considered to be indefinitely reinvested outside the US and, during 2016, we recorded a $128 million deferred tax benefit to reduce the deferred tax liability recorded at the end of 2015, net of estimated foreign tax credits. In 2015, we changed our indefinite reinvestment assertion (APB 23 assertion) based on the continued and prolonged decline in global commodity prices and an evaluation of our operations’ anticipated capital requirements and projected foreign cash positions given the adoption of the Israel Natural Gas Framework in December 2015. The actual tax impact upon distribution would depend on our tax positions at the time of repatriation and could be significantly different from this estimate. Effective Tax Rate Our effective tax rate increased in 2016 as compared with 2015 primarily due to adjustments to deferred taxes for removal of the APB 23 assertion, as noted above, decreased earnings in foreign jurisdictions with rates that vary from the US statutory rate, a decrease in the Israeli income tax rate, as well as the 2015 impact of foreign dividend repatriation and goodwill impairment. Our effective tax rate decreased in 2015 as compared with 2014 primarily due to a shift from pre-tax earnings in 2014 to a pre-tax loss in 2015 and the removal of our permanent reinvestment assertion discussed above. In the case of a pre-tax loss, our favorable permanent differences, such as income from equity method investees, have the effect of increasing the tax benefit which, in turn, increases the effective tax rate. Unfavorable permanent differences, such as non-deductible goodwill impairment expense, have the effect of decreasing the tax benefit which, in turn, decreases the effective tax rate. The decrease in the effective tax rate was partially offset by a release of the valuation allowance on foreign tax credits due to usage and losses from funding foreign exploration projects. Changes in Israeli Tax Law Effective January 2016 , the Israeli government decreased the corporate income tax rate from 26.5% to 25% , and in December 2016 announced a further rate decrease to 24% effective January 2017. The change decreased the deferred tax expense for 2016 by $30 million . Unrecognized Tax Benefits We file a consolidated income tax return in the US federal jurisdiction, and we file income tax returns in various states and foreign jurisdictions. Our income tax returns are routinely audited by the applicable revenue authorities, and provisions are made in the financial statements for differences between positions taken in tax returns and amounts recognized in the financial statements in anticipation of audit results. In our major tax jurisdictions, the earliest years remaining open to examination are: US - 2013 , Equatorial Guinea - 2011 and Israel - 2015 . Our policy is to recognize any interest and penalties related to unrecognized tax benefits in income tax expense. A reconciliation of our beginning and ending amounts of unrecognized tax benefits follows: (millions) Twelve Months Ended December 31, 2016 Unrecognized Tax Benefits, Beginning Balance $ 8 Additions for Tax Positions Related to Current Year — Additions for Tax Positions of Prior Years — Reductions for Tax Positions of Prior Years (3 ) Settlements (2 ) Unrecognized Tax Benefits, Ending Balance $ 3 Unrecognized tax benefits which would impact our effective tax rate if recognized were approximately $ 3 million as of December 31, 2016 . The changes to our unrecognized tax benefits during 2016 primarily resulted from changes in various foreign tax return filings, positions and audit settlements. The adjustments to our reserves for uncertain tax positions had a de minimis impact on our net income. During 2016 , we recognized and accrued a de minimis amount of interest and no penalties. We expect that our unrecognized tax benefits will continue to change due to the settlement of audits and the expiration of statutes of limitation during the next twelve months; however, we do not anticipate any such change to have a significant impact on our results of operations, financial position or cash flows. |
Stock-Based and Other Compensat
Stock-Based and Other Compensation Plans | 12 Months Ended |
Dec. 31, 2016 | |
Share-based Compensation [Abstract] | |
Stock-Based and Other Compensation Plans | Note 12. Stock-Based and Other Compensation Plans We recognized total stock-based compensation expense as follows: Year Ended December 31, (millions) 2016 2015 2014 Stock-Based Compensation Expense Included in General and Administrative Expense $ 62 $ 50 $ 63 Exploration Expense and Other 15 36 24 Total Stock-Based Compensation Expense $ 77 $ 86 $ 87 Tax Benefit Recognized $ (27 ) $ (30 ) $ (31 ) Stock Option and Restricted Stock Plans Our stock option and restricted stock plans are described below. 1992 Stock Option and Restricted Stock Plan Under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan, as amended (the 1992 Plan), the Compensation, Benefits and Stock Option Committee of the Board of Directors (the Committee) may grant stock options and stock appreciation rights and award restricted stock and cash awards to our officers or other employees and those of our subsidiaries. The maximum number of shares that may be granted under the 1992 Plan is 77,400,000 shares of common stock. At December 31, 2016 , 27,581,280 shares of our common stock were reserved for issuance, including 13,059,725 shares available for future grants and awards, under the 1992 Plan. Stock options are issued with an exercise price equal to the fair market value of our common stock on the date of grant, and are subject to such other terms and conditions as may be determined by the Committee. Unless granted by the Committee for a shorter term, the options expire 10 years from the grant date. Option grants generally vest ratably over a three -year period. Restricted stock awards made under the 1992 Plan are subject to such restrictions, terms and conditions, including forfeitures, if any, as may be determined by the Committee. During the period in which such restrictions apply, unless specifically provided otherwise in accordance with the terms of the 1992 Plan, the recipient of restricted stock would be the record owner of the shares and have all the rights of a stockholder with respect to the shares, including the right to vote and the right to receive dividends or other distributions made or paid with respect to the shares. The dividends or other distributions pertaining to the restricted shares will be held by the Company until the restriction period ends and the shares vest or forfeit. If the restricted shares forfeit, then the recipient shall not be entitled to receive the dividend or distribution which will transfer to the Company. Restricted stock awards with a time-vested restriction vest over a two or three year period. Restricted stock awards with a performance-vested restriction cliff vest after a three year period if the Company achieves certain levels of total shareholder return relative to a pre-determined industry peer group. 2015 Stock Plan for Non-Employee Directors The 2015 Stock Plan for Non-Employee Directors of Noble Energy, Inc., as amended (the 2015 Plan) provides for grants of stock options and awards of restricted stock to our non-employee directors. The 2015 Plan superseded and replaced the 2005 Stock Plan for Non-Employee Directors of Noble Energy, Inc. The total number of shares of our common stock that may be issued under the 2015 Plan is 708,996 . At December 31, 2016 , 705,615 shares of our common stock were reserved for issuance including 563,075 shares available for future grants and awards, under the 2015 Plan. 2005 Stock Plan for Non-Employee Directors The 2005 Stock Plan for Non-Employee Directors of Noble Energy, Inc., as amended (the 2005 Plan) provides for grants of stock options and awards of restricted stock to our non-employee directors. At December 31, 2016 , 404,865 shares of our common stock were reserved for issuance in accordance with the 2005 Plan; however, the 2005 Plan was terminated in 2015, and no additional options can be granted thereunder. Options were issued with an exercise price equal to the market price of our common stock on the date of grant and may be exercised one year after the date of grant. Unless granted by the Board of Directors for a shorter term, the options expire 10 years from the date of grant. Stock Option Grants The fair value of each stock option granted is estimated on the date of grant using a Black-Scholes-Merton option valuation model that used the assumptions described below: • Expected term The expected term represents the period of time that options granted are expected to be outstanding, which is the grant date to the date of expected exercise or other expected settlement for options granted. The hypothetical midpoint scenario we use considers our actual exercise and post-vesting cancellation history and expectations for future periods, which assumes that all vested, outstanding options are settled halfway between the current date and their expiration date. • Expected volatility The expected volatility represents the extent to which our stock price is expected to fluctuate between the grant date and the expected term of the award. We use the historical volatility of our common stock for a period equal to the expected term of the option prior to the date of grant. We believe that historical volatility produces an estimate that is representative of our expectations about the future volatility of our common stock over the expected term. • Risk-free rate The risk-free rate is the implied yield available on US Treasury securities with a remaining term equal to the expected term of the option. We base our risk-free rate on a weighting of five and seven year US Treasury securities as of the date of grant. • Dividend yield The dividend yield represents the value of our stock’s annualized dividend as compared to our stock’s average price for the three -year period ended prior to the date of grant. It is calculated by dividing one full year of our expected dividends by our average stock price over the three -year period ended prior to the date of grant. The assumptions used in valuing stock options granted were as follows: Year Ended December 31, (weighted averages) 2016 2015 2014 Expected Term (in Years) 6.3 6.0 5.9 Expected Volatility 32.4 % 32.6 % 35.1 % Risk-Free Rate 1.6 % 1.4 % 1.8 % Expected Dividend Yield 0.7 % 1.2 % 1.1 % Weighted Average Grant-Date Fair Value $ 10.10 $ 13.93 $ 20.31 Stock option activity was as follows: Options Weighted Average Exercise Price Weighted Average Remaining Contractual Term Aggregate Intrinsic Value (per share) (in years) (in millions) Outstanding at December 31, 2015 14,571,012 $ 44.59 Granted 2,441,042 31.66 Exercised (954,898 ) 25.96 Forfeited (968,294 ) 47.27 Outstanding at December 31, 2016 15,088,862 $ 43.49 5.4 $ 40 Exercisable at December 31, 2016 10,999,318 $ 44.54 4.3 $ 26 The total intrinsic value of options exercised was $10 million in 2016, $7 million in 2015, and $58 million in 2014. As of December 31, 2016 , $26 million of compensation cost related to unvested stock options granted under the Plans remained to be recognized. The cost is expected to be recognized over a weighted-average period of 1.3 years. We issue new shares of our common stock to settle option exercises. Dividends are not paid on unexercised options. Restricted Stock Awards Awards of time-vested restricted stock (shares subject to service conditions) are valued at the price of our common stock at the date of award. The fair value of the market based restricted stock awards was estimated on the date of award using a Monte Carlo valuation model that uses the assumptions in the following table. The Monte Carlo valuation model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility represents the extent to which our stock price is expected to fluctuate between now and the award’s anticipated term. We use the historical volatility of Noble Energy common stock for the three -year period ended prior to the date of award. The risk-free rate is based on a three-year period for U.S. Treasury securities as of the year ended prior to the date of award. The assumptions used in valuing market based restricted stock awards granted were as follows: Year Ended December 31, 2016 2015 Number of Simulations 500,000 500,000 Expected Volatility 38 % 30 % Risk-Free Rate 1.0 % 0.8 % Restricted stock activity was as follows: Subject to Time Vesting Subject to Market Conditions Number of Shares Weighted Average Award Date Fair Value Number of Shares Weighted Average Award Date Fair Value (per share) (per share) Outstanding at December 31, 2015 1,019,470 $ 45.55 1,929,922 $ 28.50 Awarded 898,916 31.67 363,256 24.80 Vested (421,227 ) 52.50 (340,410 ) 42.71 Forfeited (125,379 ) 35.54 (449,776 ) 37.86 Outstanding at December 31, 2016 1,371,780 $ 36.37 1,502,992 $ 27.43 The total fair value of restricted stock that vested was $24 million in 2016 , $62 million in 2015 , and $50 million in 2014 . The weighted average award-date fair value of restricted stock awarded was $29.99 per share in 2016 , $35.53 per share in 2015 , and $41.22 per share in 2014 . As of December 31, 2016 , $32 million of compensation cost related to all of our unvested restricted stock awarded under the Plans remained to be recognized. The cost is expected to be recognized over a weighted-average period of 1.3 years years. Common stock dividends accrue on restricted stock awards and are paid upon vesting. We issue new shares of our common stock when awarding restricted stock. Cash-Settled Awards On February 1, 2016, we issued cash-settled awards to certain employees under the 1992 Plan in lieu of a portion of restricted stock and stock options. We issued approximately one million awards (so called phantom units, the nomenclature used in accounting literature), a portion of which are subject to the Company's achievement of certain levels of total shareholder return relative to a pre-determined industry peer group. The fair value of the market based phantom unit awards was estimated on the date of award using a Monte Carlo valuation model based on the assumptions below. These phantom units represent a hypothetical interest in the Company, and, once vested, are settled in cash. The phantom unit value at vesting will equal the lesser of the fair market value of a share of common stock of the Company as of the vesting date ( 2 -year cliff vesting for officers and 3 -year cliff vesting for non-officers) or up to four times the fair market value of a share of common stock of the Company, which was $31.65 , as of the grant date. As of December 31, 2016 , we had accrued a liability of $9 million related to the phantom units. The assumptions used in valuing market based phantom units awarded were as follows: Year Ended December 31, 2016 Number of Simulations 500,000 Expected Volatility 38 % Risk-Free Rate 0.9 % Phantom unit activity was as follows: Subject to Time Vesting Subject to Market Conditions Number of Units Weighted Number of Units Weighted Average Award Date Fair Value (per share) (per share) Outstanding at December 31, 2015 — $ — — $ — Awarded 791,000 31.65 218,180 6.82 Vested (2,501 ) 31.65 — — Forfeited (76,410 ) 31.65 (8,676 ) 6.82 Outstanding at December 31, 2016 712,089 $ 31.65 209,504 $ 6.82 As of December 31, 2016 , $ 18 million of compensation cost related to phantom units remained to be recognized. The cost is expected to be recognized over a weighted-average period of 2.0 years . The total fair value of phantom units that vested in 2016 was de minimis. Common stock dividends accrue on phantom units and will be paid upon vesting. Other Compensation Plans 401(k) Plan We sponsor a 401(k) savings plan. All regular employees are eligible to participate. We make contributions to match employee contributions up to the first 6% of compensation deferred into the plan, and certain profit sharing contributions for employees hired on or after May 1, 2006, based upon their ages and salaries. We made cash contributions of $32 million in 2016 , $35 million in 2015 , and $26 million in 2014 . As a result of the termination of the pension plan, employees who were hired prior to May 1, 2006 became eligible to receive profit sharing contributions effective January 1, 2014. In addition, certain of these employees are eligible to receive transition contributions related to the termination of the plan. Deferred Compensation Plan We have a non-qualified deferred compensation plan for which participant-directed investments are held in a rabbi trust and are available to satisfy the claims of our creditors in the event of bankruptcy or insolvency. Participants in that nonqualified deferred compensation plan may elect to receive distributions in either cash or shares of our common stock. Components of that rabbi trust are as follows: December 31, (millions, except share amounts) 2016 2015 Rabbi Trust Assets Mutual Fund Investments $ 62 $ 63 Noble Energy Common Stock (at Fair Value) 26 35 Total Rabbi Trust Assets $ 88 $ 98 Liability Under Related Deferred Compensation Plan $ 88 $ 98 Number of Shares of Noble Energy Common Stock Held by Rabbi Trust 671,269 872,277 Assets of that rabbi trust, other than our common stock, are invested in certain mutual funds that cover an investment spectrum ranging from equities to money market instruments. These mutual funds have published market prices and are reported at fair value. See Note 13. Fair Value Measurements and Disclosures . The mutual funds are included in the mutual fund investments account in other noncurrent assets in the consolidated balance sheets. Shares of our common stock held by the rabbi trust holding common stock are accounted for as treasury stock (recorded at cost, $16.72 per share) in the shareholders’ equity section of the consolidated balance sheets. Amounts payable to plan participants are included in other noncurrent liabilities in the consolidated balance sheets and include the market value of the shares of our common stock. Approximately 600,000 shares, or 89% , of our common stock held in respect of one nonqualified deferred compensation plan at December 31, 2016 were attributable to a member of our Board of Directors. The shares are being distributed in equal installments over the next three years. Distributions of 200,000 shares were made in 2016 , 200,000 shares in 2015 and 200,000 shares in 2014 . In addition, plan participants sold 1,009 shares of our common stock in 2016 , 1,009 shares in 2015 , and 19,049 shares in 2014 . Proceeds were invested in mutual funds and/or distributed to plan participants. Distributions to plan participants were valued at $22 million in 2016 , $18 million in 2015 and $22 million in 2014 . All fluctuations in market value of the deferred compensation liability have been reflected in other non-operating (income) expense, net in the consolidated statements of operations. We recognized deferred compensation expense (income) of $11 million in 2016 , $(12) million in 2015 and $(25) million in 2014 . We also maintain other nonqualified deferred compensation plans for the benefit of certain of our employees. Deferred compensation liabilities of $121 million and $119 million were outstanding at December 31, 2016 and 2015 , respectively, under those other plans. |
Fair Value Measurements and Dis
Fair Value Measurements and Disclosures | 12 Months Ended |
Dec. 31, 2016 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Note 13. Fair Value Measurements and Disclosures Assets and Liabilities Measured at Fair Value on a Recurring Basis Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheet. The following methods and assumptions were used to estimate the fair values: Cash, Cash Equivalents, Accounts Receivable and Accounts Payable The carrying amounts approximate fair value due to the short-term nature or maturity of the instruments. Mutual Fund Investments Our mutual fund investments consist of various publicly-traded mutual funds that include investments ranging from equities to money market instruments. The fair values are based on quoted market prices for identical assets. Commodity Derivative Instruments Our commodity derivative instruments may include variable to fixed price commodity swaps, two-way collars, three-way collars, swaptions and extendable/enhanced swaps. We estimate the fair values of these instruments using published forward commodity price curves as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates. In addition, for collars, we estimate the option values of the put options sold and the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract terms. See Note 8. Derivative Instruments and Hedging Activities . Stock-Based Compensation Liability A portion of the value of the liability associated with our phantom unit plan is dependent upon the fair value of Noble Energy common stock as of the end of each reporting period. See Note 12. Stock-Based and Other Compensation Plans . Deferred Compensation Liability The value is dependent upon the fair values of mutual fund investments and shares of our common stock held in a rabbi trust. See Mutual Fund Investments above . Measurement information for assets and liabilities that are measured at fair value on a recurring basis was as follows: Fair Value Measurements Using (millions) Quoted Prices in Active Markets (Level 1) (1) Significant Other Observable Inputs (Level 2) (1) Significant Unobservable Inputs (Level 3) (1) Adjustment (2) Fair Value Measurement December 31, 2016 Financial Assets Mutual Fund Investments $ 71 $ — $ — $ — $ 71 Commodity Derivative Instruments — 5 — (5 ) — Financial Liabilities Commodity Derivative Instruments — (121 ) — 5 (116 ) Portion of Deferred Compensation Liability Measured at Fair Value (88 ) — — — (88 ) Stock Based Compensation Liability Measured at Fair Value (9 ) — — — — (9 ) December 31, 2015 Financial Assets Mutual Fund Investments $ 90 $ — $ — $ — $ 90 Commodity Derivative Instruments — 600 (8 ) 592 Financial Liabilities Commodity Derivative Instruments — (8 ) — 8 — Portion of Deferred Compensation Liability Measured at Fair Value (98 ) — — — (98 ) (1) See Note 1. Summary of Significant Accounting Policies - Fair Value Measurements for a description of the fair value hierarchy. (2) Amount represents the impact of netting clauses within our master agreements that allow us to net cash settle asset and liability positions with the same counterparty. Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Certain assets and liabilities are measured at fair value on a nonrecurring basis in our consolidated balance sheets. The following methods and assumptions were used to estimate the fair values: Asset Impairments In 2016, 2015 and 2014, we determined that the carrying amounts of certain oil and gas assets were not recoverable from future cash flows and, therefore, were impaired. The assets were reduced to their estimated fair values as noted below. Inventory Impairment In 2016 and 2015, we determined that the carrying amount of certain of our materials and supplies inventory was greater than its net realizable value or not recoverable from future cash flows. These assets were, therefore, adjusted as noted below. Information about the impaired assets is as follows: Fair Value Measurements Using Description Quoted Prices in Active Markets (Level 1) (1) Significant Other Observable Inputs (Level 2) (1) Significant Unobservable Inputs (Level 3) (1) Net Book Value (2) Total Pre-tax (Non-cash) Impairment Loss (millions) Year Ended December 31, 2016 Impaired Oil and Gas Properties $ — $ — $ — $ 92 $ 92 Impaired Materials and Supplies Inventory — — 91 105 14 Year Ended December 31, 2015 Impaired Oil and Gas Properties — — 752 1,285 533 Impaired Materials and Supplies Inventory — — 61 81 20 Year Ended December 31, 2014 Impaired Oil and Gas Properties — — 100 600 500 (1) See Note 1. Summary of Significant Accounting Policies - Fair Value Measurements for a description of the fair value hierarchy. (2) Amount represents net book value at the date of assessment. The fair values of the properties held and used were determined as of the date of the assessment using discounted cash flow models. The discounted cash flows were based on management’s expectations for the future. Inputs included estimates of future crude oil and natural gas production, commodity prices based on sales contract terms or commodity price curves as of the date of the estimate, estimated operating and development costs, and a risk-adjusted discount rate of 10% . The fair values of assets held for sale were based on anticipated sales proceeds less costs to sell. See Note 5. Asset Impairments . Additional Fair Value Disclosures Debt The fair value of fixed-rate, public debt is estimated based on the published market prices for the same or similar issues. As such, we consider the fair value of our public fixed rate debt to be a Level 1 measurement on the fair value hierarchy. Our Term Loan Facility is variable-rate, non-public debt. The carrying amount of floating-rate debt approximates fair value as the interest rates are variable and reflective of market rates. See Note 10. Long-Term Debt . Fair value information regarding our debt is as follows: December 31, December 31, (millions) Carrying Amount Fair Value Carrying Amount Fair Value Long-Term Debt, Net (1) $ 6,699 $ 7,112 $ 7,626 $ 7,105 (1) Net of unamortized discount, premium and debt issuance costs and excludes capital lease and other obligations. |
Earnings (Loss) Per Share
Earnings (Loss) Per Share | 12 Months Ended |
Dec. 31, 2016 | |
Earnings Per Share [Abstract] | |
Earnings (Loss) Per Share | Note 14. Earnings (Loss) Per Share Attributable to Noble Energy Noble Energy's basic earnings (loss) per share of common stock is computed by using net income (loss) attributable to Noble Energy divided by the weighted average number of shares of Noble Energy common stock outstanding during each period. The diluted earnings (loss) per share of common stock includes the effect of outstanding stock options, shares of restricted stock, or shares of our common stock held in a rabbi trust (when dilutive). The following table summarizes the calculation of basic and diluted earnings (loss) per share: Year Ended December 31, (millions, except per share amounts) 2016 2015 2014 Net Income (Loss) Attributable to Noble Energy $ (998 ) $ (2,441 ) $ 1,214 Earnings Adjustment from Assumed Conversion of Dilutive Shares of Common Stock in Rabbi Trust (1) — — (17 ) Net Income (Loss) Used for Diluted Earnings (Loss) Per Share Calculation $ (998 ) $ (2,441 ) $ 1,197 Weighted Average Number of Shares Outstanding, Basic (2) 430 402 361 Incremental Shares From Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust (1) — — 6 Weighted Average Number of Shares Outstanding, Diluted 430 402 367 Earnings (Loss) Attributable to Noble Energy Per Share, Basic $ (2.32 ) $ (6.07 ) $ 3.36 Earnings (Loss) Attributable to Noble Energy Per Share, Diluted (2.32 ) (6.07 ) 3.27 Additional Information Number of antidilutive stock options, shares of restricted stock and shares of common stock in rabbi trust excluded from calculation above 14 10 3 Weighted average option exercise price per share $ 45.69 $ 52.39 $ 60.30 (1) For the years ended December 31, 2016 and 2015, all outstanding options and non-vested restricted shares have been excluded from the calculation of diluted earnings (loss) per share as Noble Energy incurred a loss. Therefore, inclusion of outstanding options and non-vested restricted shares in the calculation of diluted earnings (loss) per share would be anti-dilutive. Consistent with GAAP, when dilutive, deferred compensation gains or losses, net of tax, are excluded from net income while our common shares held in the rabbi trust are included in the diluted share count. For this reason, the diluted earnings (loss) per share calculation for the year ended December 31, 2014 excludes deferred compensation gains, net of tax. (2) The weighted average number of shares outstanding for the year ended December 31, 2015 includes the weighted average shares of common stock issued in connection with the underwritten public offering of 24.15 million shares of Noble Energy common stock in first quarter 2015 and issued in connection with the exchange of approximately 41 million shares for all outstanding shares of Rosetta common stock on July 20, 2015. |
Segment Information
Segment Information | 12 Months Ended |
Dec. 31, 2016 | |
Segment Reporting [Abstract] | |
Segment Information | Note 15. Segment Information We have operations throughout the world and manage our operations by region. The following information is grouped into four components that are all primarily in the business of crude oil, natural gas and NGL exploration, development, production and acquisition: the United States (which includes consolidated accounts of Noble Midstream Partners); West Africa (Equatorial Guinea, Cameroon, Gabon and Sierra Leone (which we exited in second quarter 2015)); Eastern Mediterranean (Israel and Cyprus); and Other International and Corporate. Other International includes the Falkland Islands, Suriname, the North Sea, China (through June 2014), Nicaragua (which we exited first quarter 2015) and new ventures. Net income (loss) before income taxes for the US and West Africa includes gains and losses on commodity derivative instruments. Consolidated United States Eastern Mediter-ranean West Africa Other Int'l & Corporate Year Ended December 31, 2016 Revenues from Third Parties (1) $ 3,389 $ 2,416 $ 540 $ 433 $ — Income from Equity Method Investees 102 52 — 50 — Total Revenues 3,491 2,468 540 483 — Exploration Expense 925 245 34 483 163 DD&A 2,454 2,122 81 205 46 Asset Impairments 92 — 88 — 4 Loss on Commodity Derivative Instruments 139 126 — 13 — Income (Loss) Before Income Taxes (1,772 ) (1,052 ) 543 (338 ) (925 ) Equity Method Investments 400 183 — 217 — Additions to Long-Lived Assets 1,526 1,359 88 54 25 Total Assets at End of Year (2) 21,011 17,029 2,233 1,479 270 Year Ended December 31, 2015 Revenues from Third Parties (1) $ 3,093 $ 2,011 $ 497 $ 580 $ 5 Income from Equity Method Investees 90 51 — 39 — Total Revenues 3,183 2,062 497 619 5 Exploration Expense 488 203 12 46 227 DD&A 2,131 1,692 70 326 43 Asset Impairments 533 158 36 339 — Goodwill Impairment 779 779 — — — Gain on Commodity Derivative Instruments (501 ) (347 ) — (154 ) — Income (Loss) Before Income Taxes (2,219 ) (1,553 ) 306 (77 ) (895 ) Equity Method Investments 453 226 — 227 — Additions to Long-Lived Assets 3,062 2,534 147 124 257 Goodwill at End of Year (3) — — — — — Total Assets at End of Year (2) 24,196 18,831 2,677 2,299 389 Year Ended December 31, 2014 Revenues from Third Parties (1) $ 4,945 $ 3,189 $ 479 $ 1,177 $ 100 Income from Equity Method Investees 170 9 — 161 — Total Revenues 5,115 3,198 479 1,338 100 Exploration Expense 498 268 17 26 187 DD&A 1,759 1,318 63 299 79 Asset Impairments 500 392 14 — 94 Gain on Divestitures (73 ) (34 ) — — (39 ) Loss on Commodity Derivative Instruments (976 ) (604 ) — (372 ) — Income (Loss) Before Income Taxes 1,710 1,150 284 1,222 (946 ) Equity Method Investments 325 82 — 223 20 Additions to Long-Lived Assets 5,152 4,389 201 261 301 Goodwill at End of Year (3) 620 620 — — — Total Assets at End of Year (2) 22,518 16,365 2,806 2,763 584 (1) Revenues from third parties for all foreign countries, in total, were $973 million in 2016 , $1.1 billion in 2015 and $1.8 billion 2014 . (2) Long-lived assets located in all foreign countries, in total, were $3.0 billion , $3.9 billion , and $4.4 billion at December 31, 2016 , 2015 , and 2014 , respectively. (3) As of December 31, 2015, our goodwill was fully impaired. See Note 1. Summary of Significant Accounting Policies . |
Concentration of Risk
Concentration of Risk | 12 Months Ended |
Dec. 31, 2016 | |
Concentration of Risk [Abstract] | |
Concentration of Risk | Note 16. Concentration of Risk Concentration of Market Risk The largest single non-affiliated purchasers of our production were as follows: Percentage of Crude Oil Sales Percentage of Total Oil, Gas & NGL Sales Year Ended December 31, 2016 Glencore Energy UK Ltd 22 % 12 % Shell (1) 24 % 13 % Year Ended December 31, 2015 Glencore Energy UK Ltd 30 % 18 % Shell (1) 18 % 11 % Year Ended December 31, 2014 Glencore Energy UK Ltd 32 % 22 % Shell (1) 15 % 10 % (1) Includes sales to Shell Trading (US) Company and/or Shell International Trading and Shipping Limited. We believe the loss of any one purchaser would not have a material effect on our financial position or results of operations since there are numerous potential purchasers of our production. Concentration of Credit Risk Certain of our financial instruments, including cash equivalents, trade and joint interest receivables and derivative instruments, may expose us to credit risk. A significant portion of our cash is located in our foreign subsidiaries. The cash is denominated in US dollars and invested in highly liquid money market funds and short term deposits with original maturities of three months or less at the time of purchase. Although our cash and cash equivalents are deposited with major international banks and financial institutions, concentrations of cash in certain foreign locations may increase credit risk. We monitor the creditworthiness of the banks and financial institutions with which we invest and review the securities underlying our investment accounts. We believe that losses from nonperformance are unlikely to occur; however, we are not able to predict sudden changes in creditworthiness. Our accounts receivable result from sales of crude oil, natural gas and NGL production, and joint interest billings to our partners for their share of expenses on joint venture projects for which we are the operator. Joint venture projects, especially in deepwater, can be very capital cost intensive. Thus the receivables from our joint venture partners can become significant. Our accounts receivable reflect a broad national and international customer base, which limits our exposure to concentrations of credit risk. The majority of these receivables have payment terms of 30 days or less . We continually monitor the creditworthiness of the counterparties, some of which are not as creditworthy as we are and may experience liquidity problems. We have obtained credit enhancements from some parties, including one of our significant crude oil purchasers, in the way of parental guarantees or letters of credit. However, we do not have all of our trade credit or joint interest receivables protected through guarantees or credit support. Nonperformance by a trade creditor or joint venture partner could result in losses. Our hedging activity may increase our counterparty credit risk, especially during periods of falling commodity prices. We conduct our hedging activities with a diverse group of investment grade major banks and market participants. We monitor the creditworthiness of our hedge counterparties, and our internal hedge policies provide for mark-to-market exposure limits. We use master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be “net settled” at the time of election. |
Additional Shareholders' Equity
Additional Shareholders' Equity Information | 12 Months Ended |
Dec. 31, 2016 | |
Additional Shareholders' Equity Information [Abstract] | |
Additional Shareholders' Equity Information | Note 17. Additional Shareholders’ Equity Information Activity in shares of our common stock and treasury stock was as follows: Year Ended December 31, 2016 2015 Common Stock Shares Issued Shares, Beginning of Period 469,718,512 402,329,325 Exercise of Common Stock Options 954,898 343,145 Restricted Stock Awards, Net of Forfeitures 687,017 1,847,802 Public Equity Offering — 24,150,000 Shares Exchanged in Rosetta Merger — 41,048,240 Shares, End of Period 471,360,427 469,718,512 Treasury Stock Shares, Beginning of Period 37,925,625 37,635,890 Shares Received From Employees in Payment of Withholding Taxes Due on Vesting of Shares of Restricted Stock 236,700 490,744 Rabbi Trust Shares Distributed and/or Sold (201,009 ) (201,009 ) Shares, End of Period 37,961,316 37,925,625 Equity Offering On March 3, 2015, we closed an underwritten public offering of 21 million shares of common stock, par value $0.01 per share, at a price of $47.50 per share. In addition, on March 25, 2015, we completed the issuance of an additional 3.15 million shares of common stock, par value $0.01 per share, in connection with the exercise of the option of the underwriters to purchase additional shares of common stock. The aggregate net proceeds of the offerings were approximately $1.1 billion (after deducting underwriting discounts and commissions and offering expenses). We used approximately $150 million of the net proceeds to repay outstanding indebtedness under our Revolving Credit Facility, which had been drawn for short-term purposes on February 27, 2015. The remainder of the net proceeds was used for general corporate purposes, including the funding of our capital investment program. In accordance with our accounting policy, we excluded the intra-quarter Revolving Credit Facility activity from gross presentation in our consolidated statements of cash flows. We use net presentation when such activity includes short maturities (i.e., less than 90 days) with quick turnover. Accumulated Other Comprehensive Loss Accumulated other comprehensive loss in the shareholders’ equity section of the balance sheet included: Accumulated Other Comprehensive Loss (millions) Interest Rate Cash Flow Hedges Pension- Related and Other Total December 31, 2013 $ (24 ) $ (93 ) $ (117 ) Realized Amounts Reclassified Into Earnings 1 11 12 Unrealized Change in Fair Value — 15 15 December 31, 2014 (23 ) (67 ) (90 ) Realized Amounts Reclassified Into Earnings 1 62 63 Unrealized Change in Fair Value — (6 ) (6 ) December 31, 2015 (22 ) (11 ) (33 ) Realized Amounts Reclassified Into Earnings 1 4 5 Unrealized Change in Fair Value — (3 ) (3 ) December 31, 2016 $ (21 ) $ (10 ) $ (31 ) All amounts in the table above are reported net of tax, using an effective income tax rate of 35% . AOCL at December 31, 2016 included deferred losses of $21 million , net of tax, related to interest rate derivative instruments. This amount is being reclassified to earnings as an adjustment to interest expense over the term of our senior notes due March 2041. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2016 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Note 18. Commitments and Contingencies Legal Proceedings We are involved in various legal proceedings in the ordinary course of business. These proceedings are subject to the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters and we believe that the ultimate disposition of such proceedings will not have a material adverse effect on our financial position, results of operations or cash flows. Colorado Air Matter In April 2015, we entered into a joint consent decree (Consent Decree) with the US Environmental Protection Agency, US Department of Justice, and State of Colorado to improve emission control systems at a number of our condensate storage tanks that are part of our upstream oil and natural gas operations within the Non-Attainment Area of the DJ Basin. The Consent Decree was entered by the US District Court of Colorado on June 2, 2015. The Consent Decree, which alleges violations of the Colorado Air Pollution Prevention and Control Act and Colorado’s federal approved State Implementation Plan, specifically Colorado Air Quality Control Commission Regulation Number 7, requires us to perform certain injunctive relief activities to complete mitigation projects and supplemental environmental projects (SEP), and pay a civil penalty. Costs associated with the settlement consist of $4.95 million in civil penalties which were paid in 2015. Mitigation costs of $4.5 million and SEP costs of $4 million are being expended in accordance with schedules established in the Consent Decree. Costs associated with the injunctive relief are also being expended in accordance with schedules established in the Consent Decree. During 2015 and 2016, we spent approximately $54.7 million to undertake injunctive relief at certain tank systems following the outcome of adequacy of design evaluations and certain operation and maintenance activities to handle potential peak instantaneous vapor flow rates. Future costs associated with injunctive relief are not yet precisely quantifiable as we are continually evaluating various approaches to meet the ongoing obligations of the Consent Decree. Overall compliance with the Consent Decree has resulted in the temporary shut-in and permanent plugging and abandonment of certain wells and associated tank batteries. Consent Decree compliance could result in additional temporary shut-ins and permanent plugging and abandonment of certain wells and associated tank batteries. The Consent Decree sets forth a detailed compliance schedule with deadlines for achievement of milestones through early 2019 that may be extended depending on certain situations. The Consent Decree contains additional obligations for ongoing inspection and monitoring beyond that which is required under existing Colorado regulations. We have concluded that the penalties, injunctive relief, and mitigation expenditures that resulted from this settlement did not have, and based on currently available information will not have, a material adverse effect on our financial position, results of operations or cash flows. Colorado Air Compliance Order on Consent In December 2015, we received a proposed Compliance Order on Consent from the Colorado Department of Public Health and Environment's Air Pollution Control Division (APCD) to resolve allegations of noncompliance associated with certain engines subject to various General Permit 02 conditions and/or individual permit conditions as well as certain emission control devices subject to various individual permit conditions that applied to assets currently owned and operated by both Noble Energy and Noble Midstream Services, LLC. In May 2016, Noble Energy on behalf of itself and its wholly owned subsidiary Noble Midstream Services, LLC, on behalf of itself and its wholly owned subsidiary Colorado River DevCo LP, reached a final resolution with the APCD, which requires completion of compliance testing, modification of certain permits, payment of a civil penalty of $44,695 , and an expenditure of no less than $178,780 on an approved SEP. This resolution is not believed to have a material adverse effect on our financial position, results of operations or cash flows. Transportation and Gathering Obligations We have transportation and gathering obligations to flow Marcellus Shale natural gas production to various markets inside and outside of the Marcellus Basin. Our financial commitment for these agreements, which have remaining terms of one to 32 years, is approximately $2.1 billion, undiscounted. The agreements for firm transportation relate to services on new pipeline projects to be constructed by, and connecting to, existing and new interstate pipeline systems. The pipeline projects are expected to be complete and operational in 2017 and 2018. The commitment is included in the table below. We also have transportation and gathering obligations to flow DJ Basin, Eagle Ford Shale, and Gulf of Mexico production to various markets. Our financial commitment for these agreements, which have remaining terms of one to 12 years, is approximately $850 million , undiscounted. The commitment is included in the table below. Non-Cancelable Leases and Other Commitments We hold leases and other commitments for drilling rigs, buildings, equipment and other property. Rental expense for office buildings and oil and gas operations equipment was $76 million in 2016 , $84 million in 2015 , and $69 million in 2014 . Minimum commitments as of December 31, 2016 consist of the following: (millions) Drilling, Equipment, and Purchase Obligations Transportation and Gathering Obligations Operating Lease Obligations Capital Lease and Other Obligations (1) Total 2017 $ 255 $ 250 $ 30 $ 77 $ 612 2018 96 312 42 79 529 2019 52 314 30 52 448 2020 27 275 28 52 382 2021 9 237 28 38 312 2022 and Thereafter 30 1,566 188 163 1,947 Total $ 469 $ 2,954 $ 346 $ 461 $ 4,230 (1) Annual lease payments, net to our interest, exclude regular maintenance and operational costs. See Note 10. Long-Term Debt . |
Summary of Significant Accoun27
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Policies [Abstract] | |
Basis of Presentation and Consolidation | Basis of Presentation and Consolidation Accounting policies used by us and our subsidiaries conform to US GAAP. Significant policies are discussed below. Our consolidated accounts include our accounts and the accounts of our wholly-owned subsidiaries. All significant intercompany balances and transactions have been eliminated upon consolidation. Equity Method of Accounting We use the equity method of accounting for investments in entities that we do not control but over which we exert significant influence. Our equity investees own and operate various midstream assets which we consider an essential component of our business and a necessary and integral element to our value chain involving the monetization of natural gas in our Marcellus Shale and West Africa operating areas. With our partners, we engage in joint strategic operational and financial decision making for these entities. In order to reflect the economics associated with our integrated upstream value chain described above, we include income from equity method investees as a component of revenue in our consolidated statements of operations. We carry equity method investments at our share of net assets of the equity investees plus our loans and advances. Differences in the basis of the investment and the separate net asset value of the investee, if any, are amortized into income over the remaining useful life of the underlying assets. See Note 7. Equity Method Investments . |
Use of Estimates | Use of Estimates The preparation of consolidated financial statements in conformity with US GAAP requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Estimated quantities of crude oil, natural gas and NGL reserves are the most significant of our estimates. All the reserves data included in this Form 10-K are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil, natural gas and NGLs. There are numerous uncertainties inherent in estimating quantities of proved crude oil, natural gas and NGL reserves. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserves estimates may be different from the quantities of crude oil, natural gas and NGLs that are ultimately recovered. Qualified petroleum engineers in our Houston and Denver offices prepare all reserves estimates for our different geographical regions. These reserves estimates are reviewed and approved by senior engineering staff and division management with final approval by the Senior Vice President – Corporate Development and certain members of senior management. See Supplemental Oil and Gas Information (Unaudited) . Other items subject to estimates and assumptions include the carrying amounts of inventory, property, plant and equipment, goodwill and asset retirement obligations, valuation allowances for receivables and deferred income tax assets, and valuation of derivative instruments, among others. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. Further declines in commodity prices could result in a reduction in our fair value estimates and cause us to perform analyses to determine if our oil and gas properties are impaired. As future commodity prices cannot be determined accurately, actual results could differ significantly from our estimates. See Supplemental Oil and Gas Information (Unaudited) . |
Reclassification | Reclassification Certain reclassifications have been made to the 2015 and 2014 consolidated financial statements to conform to the 2016 presentation. These reclassifications were not material to the financial statements. |
Fair Value Measurements | Fair Value Measurements Fair value measurements are based on a hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three levels. The fair value hierarchy is as follows: • Level 1 measurements are fair value measurements which use quoted market prices (unadjusted) in active markets for identical assets or liabilities. • Level 2 measurements are fair value measurements which use inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly. • Level 3 measurements are fair value measurements which use unobservable inputs. The fair value hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. We use Level 1 inputs when available as Level 1 inputs generally provide the most reliable evidence of fair value. See Note 13. Fair Value Measurements and Disclosures . |
Cash and Cash Equivalents | Cash and Cash Equivalents For purposes of reporting cash flows, cash and cash equivalents include unrestricted cash on hand and investments with original maturities of three months or less at the time of purchase. |
Allowance for Doubtful Accounts | Allowance for Doubtful Accounts We routinely assess the recoverability of all material trade and other receivables to determine their collectibility. We accrue a reserve on a receivable when, based on management’s judgment, it is probable that a receivable will not be collected and the amount of such reserve may be reasonably estimated. |
Inventories | Inventories Inventories consist primarily of tubular goods and production equipment used in our oil and gas operations, and crude oil produced but not yet sold. Materials and supplies inventories are stated at the lower of cost or net realizable value. The cost of crude oil inventory includes production costs and DD&A of oil and gas properties. |
Property, Plant and Equipment | Property, Plant and Equipment Significant accounting policies for our property, plant and equipment are as follows: Successful Efforts Method We account for crude oil and natural gas properties under the successful efforts method of accounting. Under this method, costs to acquire mineral interests in crude oil and natural gas properties, drill and equip exploratory wells that find proved reserves, and drill and equip development wells are capitalized. Capitalized costs of producing crude oil and natural gas properties, along with support equipment and facilities, are amortized to expense by the unit-of-production method based on proved crude oil, natural gas and NGL reserves on a field-by-field basis, as estimated by our qualified petroleum engineers. Our policy is to use quarter-end reserves and add back current period production to compute quarterly DD&A expense. Costs of certain gathering facilities or processing plants serving a number of properties or used for third-party processing are depreciated using the straight-line method over the useful lives of the assets ranging from three to thirty years. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized. Repairs and maintenance are expensed as incurred. Property Impairment For our proved properties, we routinely assess whether impairment indicators arise during any given quarter and have processes in place to ensure that we become aware of such indicators. Impairment indicators include, but are not limited to, sustained decreases in commodity prices, negative revisions of proved reserves, and increases in development or operating costs. In the event that impairment indicators exist, we conduct an impairment test. To that end, we estimate future net cash flows expected in connection with the property and compare such future net cash flows to the carrying amount of the property to determine if the carrying amount is recoverable. When the carrying amount of a property exceeds its estimated undiscounted future net cash flows, the carrying amount is reduced to estimated fair value. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future crude oil and natural gas production, commodity prices based on published forward commodity price curves or contract prices as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate. Other long-lived assets, such as our midstream assets, are evaluated for potential impairment whenever events or changes in circumstances indicate that their carrying value may be greater than the undiscounted future net cash flows. Impairment, if any, is measured as the excess of an asset’s carrying amount over its estimated fair value, which is estimated as described above. We recorded property impairment charges in 2016 , 2015 and 2014 and it is possible that other proved oil and gas properties could become impaired in the future due to commodity price declines and/or field performance. See Note 5. Asset Impairments . Unproved Property Impairment Our unproved properties consist of leasehold costs and allocated value to probable and possible reserves from acquisitions. We assess individually significant unproved properties for impairment on a quarterly basis and recognize a loss at the time of impairment by providing an impairment allowance. In determining whether a significant unproved property is impaired we consider numerous factors including, but not limited to, current exploration plans, favorable or unfavorable exploration activity on the property being evaluated and/or adjacent properties, our geologists' evaluation of the property, and the remaining months in the lease term for the property. When we have allocated fair value to an unproved property as the result of a transaction accounted for as a business combination, we use a future cash flow analysis to assess the unproved property for impairment. Cash flows used in the impairment analysis are determined based on management’s estimates of crude oil, natural gas and NGL reserves, future commodity prices and future costs to produce the reserves. Cash flow estimates related to probable and possible reserves are reduced by additional risk-weighting factors. Other individually insignificant unproved properties are amortized on a composite method over an average holding period. We recorded an unproved property impairment charge in 2016 . It is possible that unproved oil and gas properties could become impaired in the future if commodity prices decline. See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs . Properties Acquired in Business Combinations When sufficient market data is not available, we determine the fair values of proved and unproved properties acquired in transactions accounted for as business combinations by preparing our own estimates of cash flows from the production of crude oil, natural gas and NGL reserves. We estimate future prices to apply to the estimated reserves quantities acquired, and estimate future operating and development costs, to arrive at estimates of future net cash flows. For the fair value assigned to proved reserves, future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the business combination. To compensate for the inherent risk of estimating and valuing unproved reserves, discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors. Assets Held for Sale We occasionally market for sale oil and gas properties. At the end of each reporting period, we evaluate our properties being marketed to determine whether any should be reclassified as held for sale. The held for sale criteria include a commitment to a plan to sell; the asset is available for immediate sale; an active program to locate a buyer exists; the sale of the asset is probable and expected to be completed within one year; the asset is being actively marketed for sale; and it is unlikely that significant changes to the plan will be made. If each of these criteria is met, the property is reclassified as held for sale in our consolidated balance sheets and will be valued at the lower of net book value or anticipated sales proceeds less costs to sell. Impairment expense would be recorded for any excess of net book value over anticipated sales proceeds less costs to sell. See Note 3. Acquisitions, Divestitures and Merger . Exploration Costs Geological and geophysical costs, delay rentals, amortization of unproved leasehold costs, and costs to drill exploratory wells that do not find proved reserves are expensed as oil and gas exploration. We carry the costs of an exploratory well as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as we are making sufficient progress assessing the reserves and the economic and operating viability of the project. For certain capital-intensive deepwater Gulf of Mexico or international projects, it may take us more than one year to evaluate the future potential of the exploratory well and make a determination of its economic viability. Our ability to move forward on a project may be dependent on gaining access to transportation or processing facilities or obtaining permits and government or partner approval, the timing of which is beyond our control. In such cases, exploratory well costs remain suspended as long as we are actively pursuing access to necessary facilities and access to such permits and approvals and believe they will be obtained. We assess the status of suspended exploratory well costs on a quarterly basis. See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs . Other Property Other property includes automobiles, trucks, airplanes, office furniture, computer equipment and other fixed assets such as buildings and leasehold improvements. These items are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets or group of assets, which range from 3 to 30 years . Other property also includes linefill which is recorded at cost to produce into the production line. Linefill is not subject to depreciation but is reviewed for impairment. Capitalization of Interest We capitalize interest costs associated with the development and construction of significant properties or projects to bring them to a condition and location necessary for their intended use, which for crude oil and natural gas assets is at first production from the field. Interest is capitalized using an interest rate equivalent to the weighted average rate we pay on long-term debt, including our unsecured revolving credit facility (Revolving Credit Facility) and bonds. Capitalized interest is included in the cost of oil and gas assets and amortized with other costs on a unit-of-production basis. Capitalized interest totaled $84 million in 2016 , $144 million in 2015 , and $116 million in 2014 . Asset Retirement Obligations Asset retirement obligations consist of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. We recognize the fair value of a liability for an ARO in the period in which it is incurred when we have an existing legal obligation associated with the retirement of our oil and gas properties that can reasonably be estimated, with the associated asset retirement cost capitalized as part of the carrying cost of the oil and gas asset. The asset retirement cost is recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at our credit-adjusted risk-free rate. After initial recording, the liability is increased for the passage of time, with the increase being reflected as accretion expense and included in our DD&A expense in the statement of operations. Subsequent adjustments in the cost estimate are reflected in the liability and the amounts continue to be amortized over the useful life of the related long-lived asset. |
Goodwill | Goodwill Goodwill represents the excess of the cost of an acquired entity over the net amounts assigned to assets acquired and liabilities assumed. Goodwill is subject to annual impairment testing in December (or more frequently as circumstances dictate). |
Derivative Instruments and Hedging Activities | Derivative Instruments and Hedging Activities All derivative instruments (including certain derivative instruments embedded in other contracts) are recorded in our consolidated balance sheets as either an asset or liability and measured at fair value. We account for our commodity derivative instruments using mark-to-market accounting and recognize all gains and losses in earnings during the period in which they occur. Our consolidated statements of cash flows includes the non-cash portion of gain and loss on commodity derivative instruments, which represented the difference between the total gain and loss on commodity derivative instruments and the cash received or paid on settlements of commodity derivative instruments during the period. We offset the fair value amounts recognized for derivative instruments and the fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral. The cash collateral (commonly referred to as a “margin”) must arise from derivative instruments recognized at fair value that are executed with the same counterparty under a master arrangement with netting clauses. |
Share-Based Compensation | Stock-Based Compensation Restricted stock and stock options issued to employees and directors are recorded at grant-date fair value. Expense is recognized on a straight-line basis over the employee’s and director’s requisite service period (generally the vesting period of the award) in the consolidated statements of operations. |
Pension and Other Postretirement Benefit Plans | Pension and Other Postretirement Benefit Plans We recognize the funded status (the difference between the fair value of plan assets and the projected benefit obligation) of defined benefit pension, restoration and other postretirement benefit plans in the consolidated balance sheets, with a corresponding adjustment to AOCL, net of tax. The amount remaining in AOCL at December 31, 2016 represents unrecognized net actuarial loss and unrecognized prior service cost related to our restoration plan. These amounts are currently being recognized as net periodic benefit cost pursuant to our historical accounting policy for amortizing such amounts. Any actuarial gains and losses that arise during the plan year, but which are not required to be recognized as net periodic benefit cost in the same period, are recognized as a component of AOCL. In third quarter 2015, we completed the process of terminating our noncontributory, tax-qualified defined benefit pension plan through the purchase of annuities for the remaining participants. As a result, we reclassified all remaining unamortized prior service cost and actuarial losses relating to the pension plan from AOCL to earnings. |
Income Taxes | Income Taxes Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized when items of income and expense are recognized in the financial statements in different periods than when recognized in the applicable tax return. Deferred tax assets arise when expenses are recognized in the financial statements before the tax return or when income items are recognized in the tax return prior to the financial statements. Deferred tax assets also arise when operating losses or tax credits are available to offset tax payments due in future years. Deferred tax liabilities arise when income items are recognized in the financial statements before the tax returns or when expenses are recognized in the tax return prior to the financial statements. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the date when the change in the tax rate was enacted. In addition, we provide a deferred tax liability for the US and foreign tax rate differences for the future additional US tax liability on accumulated undistributed foreign earnings of our foreign subsidiaries, net of estimated foreign tax credits. |
Treasury Stock | Treasury Stock We record treasury stock purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as reductions in shareholders’ equity in the consolidated balance sheets. |
Revenue Recognition and Imbalances | Revenue Recognition and Imbalances We record revenues from the sales of crude oil, natural gas and NGLs when the product is delivered at a fixed or determinable price, title has transferred and collectibility is reasonably assured. Historically, we had certain immaterial domestic natural gas sales agreements for which we previously used the entitlement method to account for imbalances. In 2016, we divested assets which were subject to this accounting and therefore, we no longer have contracts that are accounted for under the entitlement method. |
Basic and Diluted Earnings (Loss) Per Share | Basic and Diluted Earnings (Loss) Per Share Attributable to Noble Energy Basic earnings (loss) per share (EPS) of our common stock is computed on the basis of the weighted average number of shares outstanding during each period. The diluted EPS of our common stock includes the effect of outstanding common stock equivalents such as stock options, shares of restricted stock, and/or shares of our stock held in a rabbi trust, except in periods in which there is a net loss. |
Contingencies | Contingencies We are subject to legal proceedings, claims and liabilities that arise in the ordinary course of business. We accrue for losses associated with legal claims when such losses are considered probable and the amounts can be reasonably estimated. See Note 18. Commitments and Contingencies . We self-insure the medical and dental coverage provided to certain employees, and the deductibles for workers’ compensation, automobile liability and general liability coverage. Liabilities are accrued for self-insured claims, or when estimated losses exceed coverage limits, and when sufficient information is available to reasonably estimate the amount of the loss. |
Foreign Currency | Foreign Currency The US dollar is considered the functional currency for each of our international operations. Transactions that are completed in foreign currencies are remeasured into US dollars and recorded in the financial statements at prevailing foreign exchange rates. Transaction gains or losses are included in other non-operating (income) expense, net in the consolidated statements of operations. |
Segment Information | Segment Information Accounting policies for geographical segments are the same as those described above. Transfers between segments are accounted for at market value. We do not consider interest income and expense or income tax benefit or expense in our evaluation of the performance of geographical segments. |
Changes in Shareholders' Equity | Changes in Shareholders’ Equity On April 28, 2015, our shareholders voted to approve an amendment to the Company’s Certificate of Incorporation to increase the number of authorized shares of our common stock from 500 million to 1 billion shares. |
Recently Issued Accounting Standards | Recently Issued Accounting Standards Consolidation - Interests Held through Related Parties That Are under Common Control In October 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2016-17 (ASU 2016-17): Consolidation - Interests Held through Related Parties That Are under Common Control. The update changes the process through which a reporting entity determines whether it is the primary beneficiary of a variable interest entity (VIE). As a result, the single decision maker of a VIE uses economic exposure to determine its classification as the primary beneficiary as opposed to evaluating which party is most closely associated with the VIE. In February 2015, the FASB issued ASU 2015-02, which changed the guidance as to whether an entity is a variable interest entity (VIE) or a voting interest entity and how related parties are considered in the VIE model. During third quarter 2016, Noble Midstream Partners closed on its initial public offering of common units. Under the provisions of both Accounting Standards Updates, Noble Midstream Partners is considered a VIE, and Noble Energy is considered the primary beneficiary of that VIE. We have adopted these provisions, which did not have a material effect on our consolidated financial statements or related disclosures. Leases In February 2016, the FASB issued Accounting Standards Update No. 2016-02 (ASU 2016-02): Leases. The guidance requires lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created by leases with terms of more than 12 months. This ASU also requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. The standard will be effective for annual and interim periods beginning after December 15, 2018, with earlier application permitted. In the normal course of business, we enter into capital and operating lease agreements to support our exploration and development operations and lease assets such as drilling rigs, platforms, storage facilities, field services and well equipment, pipeline capacity, office space and other assets. We believe the adoption and implementation of this ASU will likely have a material impact on our balance sheet resulting from an increase in both assets and liabilities relating to our leasing activities. As part of our assessment to date, we have formed an implementation work team, prepared educational and training materials pertinent to this ASU and have begun contract review and documentation. Compensation - Stock Compensation In March 2016, the FASB issued Accounting Standards Update No. 2016-09 (ASU 2016-09): Compensation - Stock Compensation , to reduce complexity and enhance several aspects of accounting and disclosure for share-based payment transactions, including the accounting for income taxes, award forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. The ASU will be effective for annual and interim periods beginning after December 15, 2016, with earlier application permitted. Certain aspects of this guidance will require retrospective application while other aspects are to be applied prospectively. Based upon our evaluation, the adoption of this ASU will not have a material effect on our consolidated financial statements or related disclosures. Financial Instruments - Credit Losses In June 2016, the FASB issued Accounting Standards Update No. 2016-13 (ASU 2016-13): Financial Instruments - Credit Losses , which replaces the incurred loss impairment methodology in current US GAAP with a methodology that reflects expected credit losses. The update is intended to provide financial statement users with more useful information about expected credit losses. The amended guidance is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. We are currently evaluating the effect, if any, that the guidance will have on our consolidated financial statements and related disclosures. Inventory In July 2015, the FASB issued Accounting Standards Update No. 2015-11 (ASU 2015-11): Simplifying the Measurement of Inventory , effective for annual and interim periods beginning after December 15, 2016. ASU 2015-11 changes the inventory measurement principle for entities using the first-in, first out (FIFO) or average cost methods. For entities utilizing one of these methods, the inventory measurement principle will change from lower of cost or market to the lower of cost and net realizable value. We elected to early adopt this ASU as of December 31, 2016 and have applied the new measurement principle to our inventory balance. Adoption of this ASU did not have a material impact on our consolidated financial statements or related disclosures. Revenue Recognition In May 2014, the FASB issued Accounting Standards Update No. 2014-09 (ASU 2014-09), which creates Topic 606, Revenue from Contracts with Customers . In summary, revenue recognition would occur upon the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Additionally, ASU 2014-09 requires enhanced financial statement disclosures over revenue recognition as part of the new accounting guidance. The standard will be effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. In March 2016, the FASB released certain implementation guidance through ASU 2016-08 to clarify principal versus agent considerations. Currently, we do not have any contracts that would require a change from the entitlements method, historically used for certain domestic natural gas sales, to the sales method of accounting. We are continuing to evaluate the provisions of this ASU as pertinent to certain sales contracts and in particular as it relates to disclosure requirements. Investments - Equity Method and Joint Ventures In March 2016, the FASB issued Accounting Standards Update No. 2016-07 (ASU 2016-07): Investments - Equity Method and Joint Ventures , to eliminate retroactive application of equity method accounting when an investment becomes qualified for equity method accounting as a result of an increase in the level of ownership interest or degree of influence. The ASU will be effective for annual and interim periods beginning after December 15, 2016, with earlier application permitted. Based upon our evaluation, the adoption of this ASU will not have a material effect on our consolidated financial statements or related disclosures as all material investments are accounted for under the equity method of accounting. Statement of Cash Flows - Restricted Cash In November 2016, the FASB issued Accounting Standards Update No. 2016-18 (ASU 2016-18): Statement of Cash Flows - Restricted Cash , which requires amounts generally described as restricted cash and restricted cash equivalents be included with cash and cash equivalents when reconciling the total beginning and ending amounts for the periods shown on the statement of cash flows. This ASU will be effective for annual and interim periods beginning after December 15, 2017, with earlier application permitted. We do not believe adoption of ASU 2016-18 will have a material impact on our statement of cash flows and related disclosures. Statement of Cash Flows - Classification of Certain Cash Receipts and Cash Payments In August 2016, the FASB issued Accounting Standards Update No. 2016-15 (ASU 2016-15): Statement of Cash Flows - Classification of Certain Cash Receipts and Cash Payments , to clarify how certain cash receipts and cash payments should be presented in the statement of cash flows. Specifically, ASU 2016-15 provides additional guidance for certain cash flow items which may impact our presentation and classification within our statement of cash flows, including debt prepayments or debt extinguishment costs and distributions received from equity method investees. ASU 2016-15 will be effective for annual and interim periods beginning after December 15, 2017, with earlier application permitted. We do not believe adoption of ASU 2016-15 will have a material impact on our statement of cash flows and related disclosures as this update pertains to classification of items and is not a change in accounting principle. |
Additional Financial Statemen28
Additional Financial Statement Information (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Additional Financial Statement Information [Abstract] | |
Statement of Operations Information | Additional statements of operations information is as follows: Year Ended December 31, (millions) 2016 2015 2014 Production Expense Lease Operating Expense $ 542 $ 563 $ 593 Production and Ad Valorem Taxes 78 127 184 Transportation and Gathering Expense (1) 463 289 168 Total $ 1,083 $ 979 $ 945 Exploration Expense Leasehold Impairment and Amortization (2) 148 113 43 Dry Hole Cost (2) 579 266 226 Seismic, Geological and Geophysical 76 34 86 Staff Expense 77 43 72 Other 45 32 71 Total 925 488 498 Other Operating (Income) Expense, Net Marketing Expense (3) 58 33 16 Loss on Terminated Contract (4) 41 — — Gain on Divestitures, Net (5) (238 ) — (73 ) Corporate Restructuring Expense (6) 8 51 — Gain on Debt Extinguishment (7) (80 ) — — Pension Plan Expense (8) — 88 — Impact of Rosetta Merger (9) (25 ) 81 — Other, Net 70 96 49 Total $ (166 ) $ 349 $ (8 ) Other Non-Operating (Income) Expense, Net Deferred Compensation Expense (Income) (10) $ 11 $ (12 ) $ (25 ) Other (Income) Expense, Net (2 ) (3 ) (1 ) Total $ 9 $ (15 ) $ (26 ) (1) Certain of our revenue received from purchasers was historically presented with deductions for transportation, gathering, fractionation or processing costs. Beginning in 2016, we have changed our presentation of revenue to no longer include these expenses as deductions from revenue. These costs are now included within production expense. Prior year amounts of $50 million and $14 million for the years ended December 31, 2015 and 2014, respectively, have been reclassified to transportation and gathering expense to conform to the current presentation. (2) See Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs . (3) Amounts represent expense for unutilized firm transportation and shortfalls in delivering or transporting minimum volumes under certain commitments. Prior year amounts of $33 million and $16 million for the years ended December 31, 2015 and 2014, respectively, were previously presented within transportation and gathering expense. These amounts have been reclassified to conform to the current presentation. See Note 18. Commitments and Contingencies . (4) Amount relates to the termination of a rig contract offshore Falkland Islands as a result of a supplier's non-performance. (5) Includes gain related to the sale of 3.5% working interest in the Tamar field, offshore Israel. See Note 3. Acquisitions, Divestitures and Merger . (6) Amount represents expenses associated with organizational activities. (7) Amount relates to the tendering of senior notes assumed in the Rosetta Merger. See Note 10. Long-Term Debt . (8) Amount includes reclassification of the actuarial loss from AOCL related to the re-measurement and termination of our defined benefit pension plan to net income (loss). (9) Amounts represent a purchase price allocation adjustment in 2016 and merger expenses in 2015. See Note 3. Acquisitions, Divestitures and Merger . (10) Amounts represent increases (decreases) in the fair values of shares of our common stock held in a rabbi trust and mutual funds. |
Balance Sheet Information Table | Additional balance sheet information is as follows: December 31, (millions) 2016 2015 Accounts Receivable, Net Commodity Sales $ 403 $ 298 Joint Interest Billings 106 20 Proceeds Receivable (1) 40 — Other 86 151 Allowance for Doubtful Accounts (20 ) (19 ) Total $ 615 $ 450 Other Current Assets Inventories, Materials and Supplies $ 71 $ 92 Inventories, Crude Oil 18 23 Assets Held for Sale (2) 18 67 Restricted Cash (3) 30 — Prepaid Expenses and Other Assets, Current 23 34 Total $ 160 $ 216 Other Noncurrent Assets Equity Method Investments $ 400 $ 453 Mutual Fund Investments 71 90 Other Assets, Noncurrent 37 77 Total $ 508 $ 620 Other Current Liabilities Production and Ad Valorem Taxes $ 115 $ 166 Commodity Derivative Liabilities, Current 102 — Income Taxes Payable 53 86 Asset Retirement Obligations, Current 160 128 Interest Payable 76 83 Current Portion of Capital Lease and Other Obligations 63 53 Other Liabilities, Current 173 161 Total $ 742 $ 677 Other Noncurrent Liabilities Deferred Compensation Liabilities, Noncurrent $ 218 $ 217 Asset Retirement Obligations, Noncurrent 775 861 Production and Ad Valorem Taxes 47 68 Other Liabilities, Noncurrent 63 73 Total $ 1,103 $ 1,219 (1) Proceeds relate to our farm-out of a 35% interest in Block 12 offshore Cyprus and were received in January 2017. See Note 3. Acquisitions, Divestitures and Merger . (2) Assets held for sale at December 31, 2016 included assets in the Greeley Crescent area of the DJ Basin. Assets held for sale at December 31, 2015 included the Karish and Tanin natural gas discoveries, offshore Israel. See Note 3. Acquisitions, Divestitures and Merger . (3) Represents amount held in escrow at December 31, 2016 for the purchase of certain Permian Basin properties. See Note 3. Acquisitions, Divestitures and Merger . |
Supplemental Cash Flow Disclosure | Supplemental statements of cash flow information is as follows: Year Ended December 31, (millions) 2016 2015 2014 Cash Paid During the Year For Interest, Net of Amount Capitalized $ 327 $ 260 $ 189 Income Taxes Paid, Net 236 202 150 Non-Cash Financing and Investing Activities Increase in Capital Lease and Other Obligations 5 55 110 |
Merger, Acquisitions and Dive29
Merger, Acquisitions and Divestitures (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Summary of Discontinued Operations | Aggregated information regarding assets sold is as follows: Year Ended December 31, (millions) 2016 2015 2014 Sales Proceeds $ 1,241 $ 151 $ 321 Less Net Book Value of Assets Sold (993 ) (156 ) (297 ) Asset Retirement Obligations Associated with Assets Sold 7 8 48 Goodwill Allocated to Assets Sold — (4 ) (7 ) Other Closing Adjustments (17 ) 1 8 Gain on Divestitures, Net $ 238 $ — $ 73 |
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed | The following table sets forth our final purchase price allocation: (in millions, except stock price) Shares of Noble Energy common stock issued to Rosetta shareholders 41 Noble Energy common stock price on July 20, 2015 $ 36.97 Fair value of common stock issued $ 1,518 Plus: fair value of Rosetta's restricted stock awards and performance awards assumed 10 Plus: Rosetta stock options assumed 1 Total purchase price $ 1,529 Plus: liabilities assumed by Noble Energy Accounts Payable 100 Current Liabilities 37 Long-Term Debt 1,992 Other Long Term Liabilities 23 Asset Retirement Obligation 27 Total purchase price plus liabilities assumed $ 3,708 Fair Value of Rosetta Assets Cash and Equivalents $ 61 Other Current Assets 76 Derivative Instruments 209 Oil and Gas Properties: Proved Properties 1,613 Undeveloped Leaseholds 1,355 Gathering and Processing Assets 207 Asset Retirement Obligation 27 Other Property Plant and Equipment 5 Long Term Deferred Tax Asset 17 Implied Goodwill (1) 138 Total Asset Value $ 3,708 (1) As of December 31, 2015 , our preliminary purchase price allocation reflected goodwill of $163 million based on the fair value of assets acquired and liabilities assumed at the Rosetta Merger date. In conducting our goodwill impairment test as of December 31, 2015 , we determined that our goodwill balance was no longer recoverable and fully impaired it, resulting in a goodwill impairment charge in fourth quarter 2015. In second quarter 2016, we finalized the purchase price allocation and recorded a $25 million gain to other operating expense, net driven by adjustments made based on the filing of the final Rosetta federal income tax return for the period ending on the Rosetta Merger date. |
Business Acquisition, Pro Forma Information | The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Rosetta Merger taken place on January 1, 2014; furthermore, the financial information is not intended to be a projection of future results. Year Ended December 31, (in millions, except per share amounts) 2016 (1) 2015 2014 Revenues $ 3,491 $ 3,478 $ 6,126 Net (Loss) Income Attributable to Noble Energy (998 ) (2,393 ) 1,607 Earnings (Loss) Per Share Basic $ (2.32 ) $ (5.64 ) $ 4.01 Diluted (2.32 ) (5.64 ) 3.94 (1) No pro forma adjustments were made for the period as Rosetta's operations are included in our consolidated historical results. |
Schedule of Disposal Groups, Gain on Divestitures - Onshore US | . |
Schedule of Disposal Groups, Gain on Divestitures - China | . |
Asset Impairments (Tables)
Asset Impairments (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Asset Impairment Charges [Abstract] | |
Asset Impairment Charges Pre Tax (non-cash) | Pre-tax (non-cash) asset impairment charges were as follows: Year Ended December 31, (millions) 2016 2015 2014 Onshore US $ — $ — $ 42 Deepwater Gulf of Mexico — 158 350 Israel 88 36 14 Equatorial Guinea — 339 — North Sea — — 94 Other International and Corporate 4 — — Total $ 92 $ 533 $ 500 |
Capitalized Exploratory Well 31
Capitalized Exploratory Well Costs (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Capitalized Exploratory Well Costs [Abstract] | |
Changes in Capitalized Exploratory Well Costs | Changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and subsequently expensed in the same period: Year Ended December 31, (millions) 2016 2015 2014 Capitalized Exploratory Well Costs, Beginning of Period $ 1,353 $ 1,337 $ 1,301 Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves 84 123 316 Divestitures and Other (1) (143 ) — — Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves or to Assets Held for Sale (2) (1 ) (19 ) (196 ) Capitalized Exploratory Well Costs Charged to Expense (3) (525 ) (88 ) (84 ) Capitalized Exploratory Well Costs, End of Period $ 768 $ 1,353 $ 1,337 (1) The 2016 amount relates to our farm-down of a 35% interest in Block 12 offshore Cyprus to a new partner. (2) The 2015 amount relates primarily to onshore US exploration activity. The 2014 amount relates primarily to the Dantzler well (deepwater Gulf of Mexico), for which we sanctioned a development plan, and the Karish and Tanin wells (offshore Israel), which were reclassified to assets held for sale. (3) Capitalized exploratory well costs charged to expense are included within exploration expense in our consolidated statements of operations. The 2016 amount relates primarily to discoveries offshore West Africa. Following review of additional 3D seismic data, we determined these discoveries were impaired in the current forward outlook for crude oil prices. We also incurred expenses associated with our Silvergate exploratory well in the deepwater Gulf of Mexico. The well did not encounter commercial hydrocarbons and has been plugged and abandoned. The 2015 amount relates primarily to northeast Nevada. After assessing its commercial viability in the current commodity price environment, we elected to discontinue our exploration efforts. The 2014 amount relates to non-strategic onshore US exploratory well costs and the Scotia exploratory well (offshore Falkland Islands) which were determined to be non-commercial. |
Aging of Capitalized Well Costs | The following table provides an aging of capitalized exploratory well costs based on the date that drilling commenced, and the number of projects that have been capitalized for a period greater than one year: December 31, (millions) 2016 2015 2014 Exploratory Well Costs Capitalized for a Period of One Year or Less $ 69 $ 95 $ 247 Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling 699 1,258 1,090 Balance at End of Period $ 768 $ 1,353 $ 1,337 Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling 10 14 13 |
Aging of Exploratory Well Costs | The following table provides a further aging of those exploratory well costs that have been capitalized for a period greater than one year since the commencement of drilling as of December 31, 2016 : Suspended Since Country/Project (millions) Total 2014 - 2015 2012 - 2013 2011 & Prior Progress Deepwater Gulf of Mexico Troubadour 52 5 47 — Evaluating development scenarios for this 2013 natural gas discovery including subsea tieback to existing infrastructure. Katmai 98 98 — — Evaluating development scenarios for this 2014 crude oil discovery. In second quarter 2016, drilling operations at the Katmai 2 appraisal well, located in Green Canyon Block 39, were temporarily abandoned as a result of encountering high pressure in the untested fault block. We are assessing plans to progress appraisal and are evaluating tie-back options. Offshore Equatorial Guinea Felicita (Block O) 45 7 — 9 — 29 Evaluating regional development scenarios for this 2008 gas discovery. During 2014, we conducted additional seismic activity over Blocks I and O and in early 2016, we began analyzing, interpreting and evaluating the acquired seismic data. Yolanda (Block I) 22 3 5 14 A data exchange agreement for the 2007 Yolanda condensate and natural gas discovery has been executed between the governments of Equatorial Guinea and Cameroon. Our natural gas development team is working with the governments of Equatorial Guinea and Cameroon to evaluate natural gas monetization options for both Yolanda and YoYo (Cameroon) discoveries. Offshore Cameroon YoYo (YoYo Block) 54 6 13 35 A data exchange agreement for the 2007 YoYo condensate and natural gas discovery has been executed between the governments of Equatorial Guinea and Cameroon. Our natural gas development team is working with the governments of Equatorial Guinea and Cameroon to evaluate natural gas monetization options for both Yolanda (Equatorial Guinea) and YoYo discoveries. Offshore Israel Leviathan 199 18 77 104 Our development plan was approved by the Government of Israel and we are engaged in natural gas marketing activities to meet both Israeli domestic and regional export demands. We anticipate near-term project sanction and commencement of development activities. Leviathan-1 Deep 85 7 51 27 The well did not reach the target interval in 2012. We are developing future drilling plans to test this deep oil concept, which is held by the Leviathan Development and Production Leases. Dalit 31 4 7 20 Our development plan was approved by the Government of Israel to develop this 2009 natural gas discovery with a tie-in to existing infrastructure at Tamar. Offshore Cyprus Cyprus 89 12 54 23 During first quarter 2016, we received proceeds of $131 million from our 35% farm-down of interest with a partner in Block 12. In second quarter 2016, we submitted an updated development plan and continue to work with the Government of Cyprus to obtain approval of the development plan and the subsequent issuance of an Exploitation License. Receiving an Exploitation License will allow us and our partners to perform the necessary engineering and design studies and progress the project to final investment decision. Other Projects less than $20 million 24 23 — 1 Continuing to assess and evaluate wells. Total $ 699 $ 183 $ 263 $ 253 |
Equity Method Investments (Tabl
Equity Method Investments (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Equity method investments | Equity method investments are as follows: December 31, (millions) 2016 2015 Equity Method Investments CONE Investments (1) $ 172 $ 214 AMPCO 120 120 Alba Plant 82 87 Other 26 32 Total Equity Method Investments $ 400 $ 453 (1) CONE Investments include CONE Midstream and CONE Gathering. Other At December 31, 2016 , consolidated retained earnings included $95 million related to the undistributed earnings of equity method investees. The carrying value of our AMPCO investment was $12 million higher than the underlying net assets of the investee at December 31, 2016 . The difference is related to capitalized interest which is being amortized into earnings over the remaining useful life of the plant. Summarized, 100% combined financial information for equity method investees is as follows: December 31, (millions) 2016 2015 Balance Sheet Information Current Assets $ 313 $ 343 Noncurrent Assets 1,390 1,418 Current Liabilities 149 229 Noncurrent Liabilities 256 108 Year Ended December 31, (millions) 2016 2015 2014 Statements of Operations Information Operating Revenues $ 667 $ 645 $ 1,142 Operating Expenses 355 393 405 Operating Income 312 252 737 Other (Income) Net (7 ) (9 ) (9 ) Income Before Income Taxes 319 261 746 Income Tax Provision 60 46 172 Net Income $ 259 $ 215 $ 574 |
Derivative Instruments and He33
Derivative Instruments and Hedging Activities (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Unsettled Derivative Instruments | Unsettled Derivative Instruments As of December 31, 2016 , we had entered into the following crude oil derivative instruments: Swaps Collars Settlement Period Type of Contract Index Bbls Per Day Weighted Average Fixed Price Weighted Average Short Put Price Weighted Average Floor Price Weighted Average Ceiling Price 1H17 (1) Swaps NYMEX WTI 6,000 $ 55.08 $ — $ — $ — 1H17 (1) Two-Way Collars NYMEX WTI 2,000 — — 40.00 50.44 1H17 (1) Swaps Dated Brent 3,000 62.80 — — — 2H17 (1) Call Option (2) NYMEX WTI 3,000 — — — 60.12 2H17 (1) Swaptions (3) NYMEX WTI 3,000 50.05 — — — 2H17 (1) Swaptions (3) Dated Brent 3,000 62.80 — — — 2017 Three-Way Collars NYMEX WTI 24,000 — 39.08 47.71 61.20 2017 Two-Way Collars NYMEX WTI 7,000 — — 40.00 53.29 2017 Swaps NYMEX WTI 4,000 50.90 — — — 2017 Call Option (2) NYMEX WTI 3,000 — — — 57.00 2017 Three-Way Collars ICE Brent 2,000 — 43.00 50.00 63.15 2017 Three-Way Collars Dated Brent 2,000 — 35.00 45.00 66.33 2018 Three-Way Collars NYMEX WTI 5,000 — 43.00 50.00 68.50 2018 Swaps NYMEX WTI 5,000 54.03 — — — 2018 Swaptions (3) NYMEX WTI 3,000 56.10 — — — 2018 Three-Way Collars Dated Brent 3,000 — 40.00 50.00 70.41 (1) We traditionally enter into a hedge contract term of one year. For 2017 we have entered into various derivative hedging arrangements with a contract term of six months resulting in non-uniform annual volumes and weighted average prices. (2) We have entered into crude oil derivative enhanced swaps with strike prices that are above the market value as of trade commencement. To effect the enhanced non-cash swap structure, we sold call options to the applicable counterparty to receive the above market terms. (3) We have entered into certain derivative contracts (swaptions), which give counterparties the option to extend with similar terms for an additional 6-month or 12-month period. As of December 31, 2016 , we had entered into the following natural gas derivative instruments: Swaps Collars Settlement Period Type of Contract Index MMBtu Per Day Weighted Average Fixed Price Weighted Average Short Put Price Weighted Average Floor Price Weighted Average Ceiling Price 1H17 (1) Swaps NYMEX HH 30,000 $ 2.92 $ — $ — $ — 2H17 (1) Swaps NYMEX HH 30,000 3.45 — — — 2H17 (1) Swaptions (2) NYMEX HH 30,000 2.92 — — — 2017 Three-Way Collars NYMEX HH 210,000 — 2.54 2.96 3.62 2017 Swaps NYMEX HH 110,000 3.16 — — — 2017 Two-Way Collars NYMEX HH 70,000 — — 2.93 3.32 2018 Three-Way Collars NYMEX HH 70,000 — 2.50 2.80 3.76 (1) We traditionally enter into a hedge contract term of one year. For 2017 we have entered into various derivative hedging arrangements with a contract term of six months resulting in non-uniform annual volumes and weighted average prices. (2) We have entered into certain derivative contracts (swaptions), which give counterparties the option to extend with similar terms for an additional 6-month or 12-month period. |
Fair Value of Derivative Instruments | The fair values of derivative instruments in our consolidated balance sheets were as follows: Fair Value of Derivative Instruments Asset Derivative Instruments Liability Derivative Instruments December 31, December 31, December 31, December 31, Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value (millions) Commodity Derivative Instruments Current Assets $ — Current Assets $ 582 Current Liabilities $ 102 Current Liabilities $ — Noncurrent Assets — Noncurrent Assets 10 Noncurrent Liabilities 14 Noncurrent Liabilities — Total $ — $ 592 $ 116 $ — |
Effect of derivative instruments on consolidated statement of operations | The effect of derivative instruments on our consolidated statements of operations was as follows: Year Ended December 31, (millions) 2016 2015 2014 Cash (Received) Paid in Settlement of Commodity Derivative Instruments Crude Oil $ (499 ) $ (844 ) $ (34 ) Natural Gas (70 ) (147 ) 5 NGLs (1) — (18 ) — Total Cash Received in Settlement of Commodity Derivative Instruments (569 ) (1,009 ) (29 ) Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments Crude Oil 582 423 (863 ) Natural Gas 126 65 (84 ) NGLs (1) — 20 — Total Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments 708 508 (947 ) Loss (Gain) on Commodity Derivative Instruments Crude Oil 83 (421 ) (897 ) Natural Gas 56 (82 ) (79 ) NGLs (1) — 2 — Total Loss (Gain) on Commodity Derivative Instruments $ 139 $ (501 ) $ (976 ) (1) Amounts for NGLs relate to commodity derivative instruments, acquired in the Rosetta Merger, which expired as of December 31, 2015. |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of Change in Asset Retirement Obligation | Changes in asset retirement obligations were as follows: Year Ended December 31, (millions) 2016 2015 Asset Retirement Obligations, Beginning Balance $ 989 $ 751 Liabilities Incurred 21 67 Liabilities Settled (120 ) (38 ) Revision of Estimate (3 ) 166 Accretion Expense 48 43 Asset Retirement Obligations, Ending Balance $ 935 $ 989 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Debt Disclosure [Abstract] | |
Debt | Our debt consists of the following: December 31, December 31, (millions, except percentages) Debt Interest Rate Debt Interest Rate Revolving Credit Facility, due August 27, 2020 $ — — $ — — Noble Midstream Revolving Credit Facility, due September 20, 2021 — — — — Capital Lease and Other Obligations 375 — 403 — Term Loan Facility, due January 6, 2019 550 2.01 % — — 8.25% Senior Notes, due March 1, 2019 1,000 8.25 % 1,000 8.25 % 5.625% Senior Notes, due May 1, 2021 (1) 379 5.63 % 693 5.63 % 4.15% Senior Notes, due December 15, 2021 1,000 4.15 % 1,000 4.15 % 5.875% Senior Notes, due June 1, 2022 (1) 18 5.88 % 597 5.88 % 7.25% Senior Notes, due October 15, 2023 100 7.25 % 100 7.25 % 5.875% Senior Notes, due June 1, 2024 (1) 8 5.88 % 499 5.88 % 3.90% Senior Notes, due November 15, 2024 650 3.90 % 650 3.90 % 8.00% Senior Notes, due April 1, 2027 250 8.00 % 250 8.00 % 6.00% Senior Notes, due March 1, 2041 850 6.00 % 850 6.00 % 5.25% Senior Notes, due November 15, 2043 1,000 5.25 % 1,000 5.25 % 5.05% Senior Notes, due November 15, 2044 850 5.05 % 850 5.05 % 7.25% Senior Debentures, due August 1, 2097 84 7.25 % 84 7.25 % Total $ 7,114 $ 7,976 Unamortized Discount (23 ) (24 ) Unamortized Premium (2) 17 113 Unamortized Debt Issuance Costs (34 ) (36 ) Total Debt, Net of Discount $ 7,074 $ 8,029 Less Amounts Due Within One Year Capital Lease and Other Obligations (63 ) (53 ) Long-Term Debt Due After One Year $ 7,011 $ 7,976 (1) Represents senior notes assumed in the Rosetta Merger. See Note 3. Acquisitions, Divestitures and Merger . (2) Debt premium is attributable to senior notes assumed in the Rosetta Merger. |
Annual maturities of outstanding debt | Annual Debt Maturities Annual maturities of outstanding debt, excluding capital lease payments, are as follows: (millions) Debt Principal Payments December 31, 2016 2017 $ — 2018 — 2019 1,550 2020 — 2021 1,379 Thereafter 3,810 Total $ 6,739 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |
Components of Income Before Income Taxes Table | Components of income (loss) from operations before income taxes are as follows: Year Ended December 31, (millions) 2016 2015 2014 Domestic $ (1,859 ) $ (2,338 ) $ 282 Foreign 87 119 1,428 Total $ (1,772 ) $ (2,219 ) $ 1,710 |
Components of Income Tax Provision Table | The income tax provision (benefit) consists of the following: Year Ended December 31, (millions) 2016 2015 2014 Current Taxes Federal $ (4 ) $ (1 ) $ 19 State 5 — 1 Foreign 196 107 208 Total Current $ 197 $ 106 $ 228 Deferred Taxes Federal $ (784 ) $ 216 $ 237 State (24 ) (5 ) 13 Foreign (176 ) (95 ) 18 Total Deferred $ (984 ) $ 116 $ 268 Total Income Tax Provision (Benefit) Attributable to Noble Energy $ (787 ) $ 222 $ 496 Effective Tax Rate 44.4 % (10.0 )% 29.0 % |
Tax Rate Reconciliation Table | A reconciliation of the federal statutory tax rate to the effective tax rate is as follows: Year Ended December 31, (percentages) 2016 2015 2014 Federal Statutory Rate 35.0 % 35.0 % 35.0 % Effect of Earnings of Equity Method Investees 1.0 0.6 (3.3 ) Noncontrolling Interests 0.4 — — Foreign Rate Change 1.6 — — State Taxes, Net of Federal Benefit 1.3 0.3 0.8 Difference Between US and Foreign Rates (0.1 ) 2.6 (14.2 ) Foreign Exploration Loss 0.1 2.7 — Change in Valuation Allowance (2.0 ) — 1.9 Oil Profits Tax - Israel — 0.1 0.2 Tax Contingency 0.2 0.4 0.1 Accumulated Undistributed Foreign Earnings 7.2 (37.7 ) 8.2 Goodwill Impairment — (12.3 ) — Other, Net (0.3 ) (1.7 ) 0.3 Effective Rate 44.4 % (10.0 )% 29.0 % |
Deferred Tax Assets and Liabilities | Deferred tax assets and liabilities resulted from the following: December 31, (millions) 2016 2015 Deferred Tax Assets Loss Carryforwards $ 474 $ 468 Employee Compensation and Benefits 150 151 Other 49 81 Total Deferred Tax Assets $ 673 $ 700 Valuation Allowance - Foreign Loss Carryforwards (242 ) (206 ) Net Deferred Tax Assets $ 431 $ 494 Deferred Tax Liabilities Mark to Market of Commodity Derivative Instruments 44 (128 ) Accumulated Undistributed Foreign Earnings (240 ) (368 ) Property, Plant and Equipment, Principally Due to Differences in Depreciation, Amortization, Lease Impairment and Abandonments (2,054 ) (2,824 ) Total Deferred Tax Liability $ (2,250 ) $ (3,320 ) Net Deferred Tax Liability $ (1,819 ) $ (2,826 ) |
Deferred Tax Liability Balance Sheet Classifcation | Net deferred tax liabilities were classified in the consolidated balance sheets as follows: December 31, (millions) 2016 2015 Deferred Income Tax Liability - Current $ — $ — Deferred Income Tax Liability - Noncurrent (1,819 ) (2,826 ) Net Deferred Tax Liability $ (1,819 ) $ (2,826 ) |
Schedule of Unrecognized Tax Benefits | A reconciliation of our beginning and ending amounts of unrecognized tax benefits follows: (millions) Twelve Months Ended December 31, 2016 Unrecognized Tax Benefits, Beginning Balance $ 8 Additions for Tax Positions Related to Current Year — Additions for Tax Positions of Prior Years — Reductions for Tax Positions of Prior Years (3 ) Settlements (2 ) Unrecognized Tax Benefits, Ending Balance $ 3 |
Stock-Based and Other Compens37
Stock-Based and Other Compensation Plans (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Share-based Compensation [Abstract] | |
Stock-based compensation expense | We recognized total stock-based compensation expense as follows: Year Ended December 31, (millions) 2016 2015 2014 Stock-Based Compensation Expense Included in General and Administrative Expense $ 62 $ 50 $ 63 Exploration Expense and Other 15 36 24 Total Stock-Based Compensation Expense $ 77 $ 86 $ 87 Tax Benefit Recognized $ (27 ) $ (30 ) $ (31 ) |
Share-based Compensation Awards | The assumptions used in valuing stock options granted were as follows: Year Ended December 31, (weighted averages) 2016 2015 2014 Expected Term (in Years) 6.3 6.0 5.9 Expected Volatility 32.4 % 32.6 % 35.1 % Risk-Free Rate 1.6 % 1.4 % 1.8 % Expected Dividend Yield 0.7 % 1.2 % 1.1 % Weighted Average Grant-Date Fair Value $ 10.10 $ 13.93 $ 20.31 Stock option activity was as follows: Options Weighted Average Exercise Price Weighted Average Remaining Contractual Term Aggregate Intrinsic Value (per share) (in years) (in millions) Outstanding at December 31, 2015 14,571,012 $ 44.59 Granted 2,441,042 31.66 Exercised (954,898 ) 25.96 Forfeited (968,294 ) 47.27 Outstanding at December 31, 2016 15,088,862 $ 43.49 5.4 $ 40 Exercisable at December 31, 2016 10,999,318 $ 44.54 4.3 $ 26 The total intrinsic value of options exercised was $10 million in 2016, $7 million in 2015, and $58 million in 2014. As of December 31, 2016 , $26 million of compensation cost related to unvested stock options granted under the Plans remained to be recognized. The cost is expected to be recognized over a weighted-average period of 1.3 years. We issue new shares of our common stock to settle option exercises. Dividends are not paid on unexercised options. Restricted Stock Awards Awards of time-vested restricted stock (shares subject to service conditions) are valued at the price of our common stock at the date of award. The fair value of the market based restricted stock awards was estimated on the date of award using a Monte Carlo valuation model that uses the assumptions in the following table. The Monte Carlo valuation model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility represents the extent to which our stock price is expected to fluctuate between now and the award’s anticipated term. We use the historical volatility of Noble Energy common stock for the three -year period ended prior to the date of award. The risk-free rate is based on a three-year period for U.S. Treasury securities as of the year ended prior to the date of award. The assumptions used in valuing market based restricted stock awards granted were as follows: Year Ended December 31, 2016 2015 Number of Simulations 500,000 500,000 Expected Volatility 38 % 30 % Risk-Free Rate 1.0 % 0.8 % Restricted stock activity was as follows: Subject to Time Vesting Subject to Market Conditions Number of Shares Weighted Average Award Date Fair Value Number of Shares Weighted Average Award Date Fair Value (per share) (per share) Outstanding at December 31, 2015 1,019,470 $ 45.55 1,929,922 $ 28.50 Awarded 898,916 31.67 363,256 24.80 Vested (421,227 ) 52.50 (340,410 ) 42.71 Forfeited (125,379 ) 35.54 (449,776 ) 37.86 Outstanding at December 31, 2016 1,371,780 $ 36.37 1,502,992 $ 27.43 The assumptions used in valuing market based phantom units awarded were as follows: Year Ended December 31, 2016 Number of Simulations 500,000 Expected Volatility 38 % Risk-Free Rate 0.9 % Phantom unit activity was as follows: Subject to Time Vesting Subject to Market Conditions Number of Units Weighted Number of Units Weighted Average Award Date Fair Value (per share) (per share) Outstanding at December 31, 2015 — $ — — $ — Awarded 791,000 31.65 218,180 6.82 Vested (2,501 ) 31.65 — — Forfeited (76,410 ) 31.65 (8,676 ) 6.82 Outstanding at December 31, 2016 712,089 $ 31.65 209,504 $ 6.82 |
Schedule of components for Rabbi Trust | Deferred Compensation Plan We have a non-qualified deferred compensation plan for which participant-directed investments are held in a rabbi trust and are available to satisfy the claims of our creditors in the event of bankruptcy or insolvency. Participants in that nonqualified deferred compensation plan may elect to receive distributions in either cash or shares of our common stock. Components of that rabbi trust are as follows: December 31, (millions, except share amounts) 2016 2015 Rabbi Trust Assets Mutual Fund Investments $ 62 $ 63 Noble Energy Common Stock (at Fair Value) 26 35 Total Rabbi Trust Assets $ 88 $ 98 Liability Under Related Deferred Compensation Plan $ 88 $ 98 Number of Shares of Noble Energy Common Stock Held by Rabbi Trust 671,269 872,277 |
Schedule of benefit obligation, plant assets and AOCL balances for pension, restoration and other postretirement benefit plans | s |
Fair Value Measurements and D38
Fair Value Measurements and Disclosures (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Fair Value Disclosures [Abstract] | |
Assets and liabilities measured at fair value on a recurring basis | Measurement information for assets and liabilities that are measured at fair value on a recurring basis was as follows: Fair Value Measurements Using (millions) Quoted Prices in Active Markets (Level 1) (1) Significant Other Observable Inputs (Level 2) (1) Significant Unobservable Inputs (Level 3) (1) Adjustment (2) Fair Value Measurement December 31, 2016 Financial Assets Mutual Fund Investments $ 71 $ — $ — $ — $ 71 Commodity Derivative Instruments — 5 — (5 ) — Financial Liabilities Commodity Derivative Instruments — (121 ) — 5 (116 ) Portion of Deferred Compensation Liability Measured at Fair Value (88 ) — — — (88 ) Stock Based Compensation Liability Measured at Fair Value (9 ) — — — — (9 ) December 31, 2015 Financial Assets Mutual Fund Investments $ 90 $ — $ — $ — $ 90 Commodity Derivative Instruments — 600 (8 ) 592 Financial Liabilities Commodity Derivative Instruments — (8 ) — 8 — Portion of Deferred Compensation Liability Measured at Fair Value (98 ) — — — (98 ) (1) See Note 1. Summary of Significant Accounting Policies - Fair Value Measurements for a description of the fair value hierarchy. (2) Amount represents the impact of netting clauses within our master agreements that allow us to net cash settle asset and liability positions with the same counterparty. |
Assets and liabilities measured at fair value on a noncurring basis | Information about the impaired assets is as follows: Fair Value Measurements Using Description Quoted Prices in Active Markets (Level 1) (1) Significant Other Observable Inputs (Level 2) (1) Significant Unobservable Inputs (Level 3) (1) Net Book Value (2) Total Pre-tax (Non-cash) Impairment Loss (millions) Year Ended December 31, 2016 Impaired Oil and Gas Properties $ — $ — $ — $ 92 $ 92 Impaired Materials and Supplies Inventory — — 91 105 14 Year Ended December 31, 2015 Impaired Oil and Gas Properties — — 752 1,285 533 Impaired Materials and Supplies Inventory — — 61 81 20 Year Ended December 31, 2014 Impaired Oil and Gas Properties — — 100 600 500 (1) See Note 1. Summary of Significant Accounting Policies - Fair Value Measurements for a description of the fair value hierarchy. (2) Amount represents net book value at the date of assessment. |
Additional fair value disclosures | Fair value information regarding our debt is as follows: December 31, December 31, (millions) Carrying Amount Fair Value Carrying Amount Fair Value Long-Term Debt, Net (1) $ 6,699 $ 7,112 $ 7,626 $ 7,105 (1) Net of unamortized discount, premium and debt issuance costs and excludes capital lease and other obligations. |
Earnings (Loss) Per Share (Tabl
Earnings (Loss) Per Share (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Earnings Per Share [Abstract] | |
Calculation of Basic and Diluted Earnings (Loss) Per Share | The following table summarizes the calculation of basic and diluted earnings (loss) per share: Year Ended December 31, (millions, except per share amounts) 2016 2015 2014 Net Income (Loss) Attributable to Noble Energy $ (998 ) $ (2,441 ) $ 1,214 Earnings Adjustment from Assumed Conversion of Dilutive Shares of Common Stock in Rabbi Trust (1) — — (17 ) Net Income (Loss) Used for Diluted Earnings (Loss) Per Share Calculation $ (998 ) $ (2,441 ) $ 1,197 Weighted Average Number of Shares Outstanding, Basic (2) 430 402 361 Incremental Shares From Assumed Conversion of Dilutive Stock Options, Restricted Stock, and Shares of Common Stock in Rabbi Trust (1) — — 6 Weighted Average Number of Shares Outstanding, Diluted 430 402 367 Earnings (Loss) Attributable to Noble Energy Per Share, Basic $ (2.32 ) $ (6.07 ) $ 3.36 Earnings (Loss) Attributable to Noble Energy Per Share, Diluted (2.32 ) (6.07 ) 3.27 Additional Information Number of antidilutive stock options, shares of restricted stock and shares of common stock in rabbi trust excluded from calculation above 14 10 3 Weighted average option exercise price per share $ 45.69 $ 52.39 $ 60.30 (1) For the years ended December 31, 2016 and 2015, all outstanding options and non-vested restricted shares have been excluded from the calculation of diluted earnings (loss) per share as Noble Energy incurred a loss. Therefore, inclusion of outstanding options and non-vested restricted shares in the calculation of diluted earnings (loss) per share would be anti-dilutive. Consistent with GAAP, when dilutive, deferred compensation gains or losses, net of tax, are excluded from net income while our common shares held in the rabbi trust are included in the diluted share count. For this reason, the diluted earnings (loss) per share calculation for the year ended December 31, 2014 excludes deferred compensation gains, net of tax. (2) The weighted average number of shares outstanding for the year ended December 31, 2015 includes the weighted average shares of common stock issued in connection with the underwritten public offering of 24.15 million shares of Noble Energy common stock in first quarter 2015 and issued in connection with the exchange of approximately 41 million shares for all outstanding shares of Rosetta common stock on July 20, 2015. |
Segment Information (Tables)
Segment Information (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Segment Reporting [Abstract] | |
Segment Information | Consolidated United States Eastern Mediter-ranean West Africa Other Int'l & Corporate Year Ended December 31, 2016 Revenues from Third Parties (1) $ 3,389 $ 2,416 $ 540 $ 433 $ — Income from Equity Method Investees 102 52 — 50 — Total Revenues 3,491 2,468 540 483 — Exploration Expense 925 245 34 483 163 DD&A 2,454 2,122 81 205 46 Asset Impairments 92 — 88 — 4 Loss on Commodity Derivative Instruments 139 126 — 13 — Income (Loss) Before Income Taxes (1,772 ) (1,052 ) 543 (338 ) (925 ) Equity Method Investments 400 183 — 217 — Additions to Long-Lived Assets 1,526 1,359 88 54 25 Total Assets at End of Year (2) 21,011 17,029 2,233 1,479 270 Year Ended December 31, 2015 Revenues from Third Parties (1) $ 3,093 $ 2,011 $ 497 $ 580 $ 5 Income from Equity Method Investees 90 51 — 39 — Total Revenues 3,183 2,062 497 619 5 Exploration Expense 488 203 12 46 227 DD&A 2,131 1,692 70 326 43 Asset Impairments 533 158 36 339 — Goodwill Impairment 779 779 — — — Gain on Commodity Derivative Instruments (501 ) (347 ) — (154 ) — Income (Loss) Before Income Taxes (2,219 ) (1,553 ) 306 (77 ) (895 ) Equity Method Investments 453 226 — 227 — Additions to Long-Lived Assets 3,062 2,534 147 124 257 Goodwill at End of Year (3) — — — — — Total Assets at End of Year (2) 24,196 18,831 2,677 2,299 389 Year Ended December 31, 2014 Revenues from Third Parties (1) $ 4,945 $ 3,189 $ 479 $ 1,177 $ 100 Income from Equity Method Investees 170 9 — 161 — Total Revenues 5,115 3,198 479 1,338 100 Exploration Expense 498 268 17 26 187 DD&A 1,759 1,318 63 299 79 Asset Impairments 500 392 14 — 94 Gain on Divestitures (73 ) (34 ) — — (39 ) Loss on Commodity Derivative Instruments (976 ) (604 ) — (372 ) — Income (Loss) Before Income Taxes 1,710 1,150 284 1,222 (946 ) Equity Method Investments 325 82 — 223 20 Additions to Long-Lived Assets 5,152 4,389 201 261 301 Goodwill at End of Year (3) 620 620 — — — Total Assets at End of Year (2) 22,518 16,365 2,806 2,763 584 (1) Revenues from third parties for all foreign countries, in total, were $973 million in 2016 , $1.1 billion in 2015 and $1.8 billion 2014 . (2) Long-lived assets located in all foreign countries, in total, were $3.0 billion , $3.9 billion , and $4.4 billion at December 31, 2016 , 2015 , and 2014 , respectively. |
Concentration of Risk (Tables)
Concentration of Risk (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Concentration of Risk [Abstract] | |
Schedules of Concentration of Risk, by Risk Factor | The largest single non-affiliated purchasers of our production were as follows: Percentage of Crude Oil Sales Percentage of Total Oil, Gas & NGL Sales Year Ended December 31, 2016 Glencore Energy UK Ltd 22 % 12 % Shell (1) 24 % 13 % Year Ended December 31, 2015 Glencore Energy UK Ltd 30 % 18 % Shell (1) 18 % 11 % Year Ended December 31, 2014 Glencore Energy UK Ltd 32 % 22 % Shell (1) 15 % 10 % (1) Includes sales to Shell Trading (US) Company and/or Shell International Trading and Shipping Limited. |
Additional Shareholders' Equi42
Additional Shareholders' Equity Information (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Additional Shareholders' Equity Information [Abstract] | |
Schedule Of Activity In Shares Of Common And Treasury Stock | Activity in shares of our common stock and treasury stock was as follows: Year Ended December 31, 2016 2015 Common Stock Shares Issued Shares, Beginning of Period 469,718,512 402,329,325 Exercise of Common Stock Options 954,898 343,145 Restricted Stock Awards, Net of Forfeitures 687,017 1,847,802 Public Equity Offering — 24,150,000 Shares Exchanged in Rosetta Merger — 41,048,240 Shares, End of Period 471,360,427 469,718,512 Treasury Stock Shares, Beginning of Period 37,925,625 37,635,890 Shares Received From Employees in Payment of Withholding Taxes Due on Vesting of Shares of Restricted Stock 236,700 490,744 Rabbi Trust Shares Distributed and/or Sold (201,009 ) (201,009 ) Shares, End of Period 37,961,316 37,925,625 |
Accumulated other comprehensive income (loss) in the shareholders' equity section of the balance sheet | Accumulated other comprehensive loss in the shareholders’ equity section of the balance sheet included: Accumulated Other Comprehensive Loss (millions) Interest Rate Cash Flow Hedges Pension- Related and Other Total December 31, 2013 $ (24 ) $ (93 ) $ (117 ) Realized Amounts Reclassified Into Earnings 1 11 12 Unrealized Change in Fair Value — 15 15 December 31, 2014 (23 ) (67 ) (90 ) Realized Amounts Reclassified Into Earnings 1 62 63 Unrealized Change in Fair Value — (6 ) (6 ) December 31, 2015 (22 ) (11 ) (33 ) Realized Amounts Reclassified Into Earnings 1 4 5 Unrealized Change in Fair Value — (3 ) (3 ) December 31, 2016 $ (21 ) $ (10 ) $ (31 ) |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Commitments and Contingencies Disclosure [Abstract] | |
Minimum commitments | Minimum commitments as of December 31, 2016 consist of the following: (millions) Drilling, Equipment, and Purchase Obligations Transportation and Gathering Obligations Operating Lease Obligations Capital Lease and Other Obligations (1) Total 2017 $ 255 $ 250 $ 30 $ 77 $ 612 2018 96 312 42 79 529 2019 52 314 30 52 448 2020 27 275 28 52 382 2021 9 237 28 38 312 2022 and Thereafter 30 1,566 188 163 1,947 Total $ 469 $ 2,954 $ 346 $ 461 $ 4,230 (1) Annual lease payments, net to our interest, exclude regular maintenance and operational costs. See Note 10. Long-Term Debt . |
Summary of Significant Accoun44
Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Property, Plant and Equipment [Line Items] | |||
Total capitalized interest | $ 84 | $ 144 | $ 116 |
Minimum | |||
Property, Plant and Equipment [Line Items] | |||
Useful lives of gathering facilitates and processing plants (in years) | 3 years | ||
Useful lives of other property (in years) | 3 years | ||
Maximum | |||
Property, Plant and Equipment [Line Items] | |||
Useful lives of gathering facilitates and processing plants (in years) | 30 years | ||
Useful lives of other property (in years) | 30 years |
Summary of Significant Accoun45
Summary of Significant Accounting Policies (Details 2) - USD ($) | 12 Months Ended | ||||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Apr. 28, 2015 | Apr. 27, 2015 | |
Change in Stockholder Equity Due to Shareholder Amendment [Line Items] | |||||
Common Stock, shares authorized (in shares) | 1,000,000,000 | 500,000,000 | |||
Goodwill Impairment | $ 0 | $ 779,000,000 | $ 0 | ||
Goodwill allocation | 4,000,000 | ||||
Goodwill | 0 | $ 620,000,000 | |||
Common Stock Authorized prior to Certificate of Incorporation Amendment | |||||
Change in Stockholder Equity Due to Shareholder Amendment [Line Items] | |||||
Common Stock, shares authorized (in shares) | 500,000,000 | ||||
Common Stock Authorized after Certificate of Incorporation Amendment | |||||
Change in Stockholder Equity Due to Shareholder Amendment [Line Items] | |||||
Common Stock, shares authorized (in shares) | 1,000,000,000 | ||||
Rosetta Merger | |||||
Change in Stockholder Equity Due to Shareholder Amendment [Line Items] | |||||
Acquired goodwill | $ 163,000,000 |
Additional Financial Statemen46
Additional Financial Statement Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Additional Financial Statement Information [Line Items] | |||
Oil and Gas Sales Revenue | $ 3,389 | $ 3,093 | $ 4,945 |
Working interest sold | 3.50% | ||
Farm down | 35.00% | ||
Production Expense | |||
Lease Operating Expense | $ 542 | 563 | 593 |
Production and Ad Valorem Taxes | 78 | 127 | 184 |
Transportation and Gathering Expense (1) | 463 | 289 | 168 |
Total | 1,083 | 979 | 945 |
Leasehold Impairment and Amortization | 148 | 113 | 43 |
Dry Hole Cost | 579 | 266 | 226 |
Seismic, Geological and Geophysical | 76 | 34 | 86 |
Staff Expense | 77 | 43 | 72 |
Other | 45 | 32 | 71 |
Exploration Expense | 925 | 488 | 498 |
Other Operating (Income) Expense, Net | |||
Marketing Expense | 58 | 33 | 16 |
Loss on Terminated Contract | 41 | 0 | 0 |
(Gain) Loss on Divestitures | (238) | 0 | (73) |
Corporate Restructuring Charges | 8 | 51 | 0 |
Gain on Debt Extinguishment | (80) | 0 | 0 |
Pension Plan Expense | 0 | 88 | 0 |
Rosetta Merger Expense | (25) | 81 | 0 |
Other, Net | 70 | 96 | 49 |
Total | (166) | 349 | (8) |
Other Non-Operating (Income) Expense, Net | |||
Deferred Compensation (Income) Expense | 11 | (12) | (25) |
Other (Income) Expense, Net | (2) | (3) | (1) |
Total | 9 | (15) | (26) |
Accounts Receivable, Net | |||
Commodity Sales | 403 | 298 | |
Joint Interest Billings | 106 | 20 | |
Proceeds Receivable | 40 | 0 | |
Other | 86 | 151 | |
Allowance for Doubtful Accounts | (20) | (19) | |
Total | 615 | 450 | |
Other Current Assets | |||
Inventories, Materials and Supplies | 71 | 92 | |
Inventories, Crude Oil | 18 | 23 | |
Assets Held for Sale | 18 | 67 | |
Restricted Cash | 30 | 0 | |
Prepaid Expenses and Other Assets, Current | 23 | 34 | |
Total | 160 | 216 | |
Other Noncurrent Assets | |||
Equity Method Investments | 400 | 453 | 325 |
Mutual Fund Investments | 71 | 90 | |
Other Assets, Noncurrent | 37 | 77 | |
Total | 508 | 620 | |
Other Current Liabilities | |||
Production and Ad Valorem Taxes | 115 | 166 | |
Commodity Derivative Liabilities, Current | 102 | 0 | |
Income Taxes Payable | 53 | 86 | |
Asset Retirement Obligations, Current | 160 | 128 | |
Interest Payable | 76 | 83 | |
Current Portion of Capital Lease and Other Obligations | 63 | 53 | |
Other Liabilities, Current | 173 | 161 | |
Total | 742 | 677 | |
Other Noncurrent Liabilities | |||
Deferred Compensation Liabilities, Noncurrent | 218 | 217 | |
Asset Retirement Obligations, Noncurrent | 775 | 861 | |
Production and Ad Valorem Taxes | 47 | 68 | |
Other Liabilities, Noncurrent | 63 | 73 | |
Total | $ 1,103 | 1,219 | |
Scenario, Previously Reported | NGL Revenue Previously Netted with Expense | |||
Additional Financial Statement Information [Line Items] | |||
Oil and Gas Sales Revenue | $ 50 | $ 14 |
Additional Financial Statemen47
Additional Financial Statement Information (Details 2) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Additional Financial Statement Information [Abstract] | |||
Other Other Operating Income (Expense) | $ (70) | $ (96) | $ (49) |
Cash Paid During the Year For | |||
Interest, Net of Amount Capitalized | 327 | 260 | 189 |
Income Taxes Paid, Net | 236 | 202 | 150 |
Non-Cash Financing and Investing Activities | |||
Increase in Capital Lease and Other Obligations | $ 5 | $ 55 | $ 110 |
Merger, Acquisitions and Dive48
Merger, Acquisitions and Divestitures - Narrative (Details) | Jan. 13, 2017USD ($)$ / sharesshares | Jul. 20, 2015USD ($)abusiness$ / sharesshares | Dec. 31, 2016USD ($) | Dec. 31, 2016USD ($)awell | Jun. 30, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2016USD ($)ashares | Dec. 31, 2015USD ($)shares | Dec. 31, 2014USD ($) | Mar. 31, 2016USD ($) |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Stock issued (shares) | shares | 0 | 41,048,240 | ||||||||
Sales Proceeds | $ 1,241,000,000 | $ 151,000,000 | $ 321,000,000 | |||||||
Gain on Divestitures | $ 238,000,000 | 0 | 73,000,000 | |||||||
Farm down | 35.00% | 35.00% | 35.00% | |||||||
Remaining proceeds | $ 40,000,000 | $ 40,000,000 | $ 0 | $ 40,000,000 | 0 | |||||
Severance, consulting, investment, advistory, legal and other related merger-related fees | (25,000,000) | 81,000,000 | 0 | |||||||
Revenue since acquisition | 181,000,000 | 457,000,000 | ||||||||
Pre-tax loss since acquisition | (120,000,000) | 20,000,000 | ||||||||
Purchase price adjustment | $ 25,000,000 | 25,000,000 | ||||||||
Goodwill | 0 | 0 | 620,000,000 | |||||||
Goodwill Impairment | $ 0 | 779,000,000 | 0 | |||||||
CONSOL Carried Cost Obligation | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Land held (acres) | a | 363,000 | |||||||||
Working interest | 100.00% | 100.00% | 100.00% | |||||||
Cash remitted | $ 213,000,000 | |||||||||
Wells Ranch Development Area | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Land exchanged (acres) | a | 11,700 | |||||||||
Alon A And Alon C | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Farm down | 47.00% | 47.00% | 47.00% | |||||||
Total consideration value | $ 73,000,000 | $ 73,000,000 | $ 73,000,000 | |||||||
Asset consideration | 67,000,000 | 67,000,000 | 67,000,000 | |||||||
Consideration adjustment | $ 6,000,000 | |||||||||
Bronco Development Area | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Land sold (acres) | a | 13,500 | |||||||||
Producing and Undeveloped Net Acres in the DJ Basin | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Sales Proceeds | $ 486,000,000 | |||||||||
Land sold (acres) | a | 33,100 | |||||||||
Weld County, Colorado | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Consideration expected | $ 505,000,000 | $ 505,000,000 | $ 505,000,000 | |||||||
MONTANA | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Sales Proceeds | 152,000,000 | |||||||||
Onshore United States properties | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Gain on Divestitures | (23,000,000) | |||||||||
Tamar Field, Offshore Israel | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Gain on Divestitures | $ 261,000,000 | |||||||||
Farm down | 3.50% | 3.50% | 3.50% | |||||||
Total consideration value | $ 431,000,000 | $ 431,000,000 | $ 431,000,000 | |||||||
Asset consideration | 316,000,000 | 316,000,000 | 316,000,000 | |||||||
Cyprus Block 12 | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Proceeds from farm-out | 131,000,000 | 131,000,000 | $ 131,000,000 | |||||||
Total consideration value | $ 131,000,000 | |||||||||
Rosetta Resources, Inc | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Cash paid ($ per share) | $ / shares | $ 36.97 | |||||||||
Stock issued (shares) | shares | 41,000,000 | |||||||||
Consideration transferred | $ 1,529,000,000 | |||||||||
Number of Businesses Acquired | business | 2 | |||||||||
Merger-related costs incurred | $ 81,000,000 | 81,000,000 | ||||||||
Severance, consulting, investment, advistory, legal and other related merger-related fees | 66,000,000 | |||||||||
Noncash share-based compensation expense | 15,000,000 | |||||||||
Goodwill | $ 138,000,000 | $ 163,000,000 | 163,000,000 | |||||||
Permian | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Cash paid | $ 30,000,000 | |||||||||
Consideration transferred | $ 300,000,000 | |||||||||
Number of wells | well | 7 | |||||||||
Common Stock | Rosetta Resources, Inc | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Business Combination, stock exchange ratio | 0.542 | |||||||||
CHINA | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Sales Proceeds | 186,000,000 | |||||||||
Gain on Divestitures | (35,000,000) | |||||||||
Midland Basin | Rosetta Resources, Inc | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Long-term Debt, Fair Value | $ 2,000,000,000 | |||||||||
Business Combination, Gas And Oil Area Acquired | a | 9,000 | |||||||||
Eagle Ford Shale | Rosetta Resources, Inc | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Business Combination, Gas And Oil Area Acquired | a | 50,000 | |||||||||
Permian | Rosetta Resources, Inc | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Business Combination, Gas And Oil Area Acquired | a | 54,000 | |||||||||
Delaware Basin | Rosetta Resources, Inc | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Business Combination, Gas And Oil Area Acquired | a | 45,000 | |||||||||
Rosetta Resources, Inc | Rosetta Resources, Inc | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Severance, consulting, investment, advistory, legal and other related merger-related fees | $ 37,000,000 | |||||||||
Subsequent Event | Clayton Williams Energy | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Cash and equity paid | $ 2,700,000,000 | |||||||||
Shares issued per share | shares | 2.7874 | |||||||||
Cash paid ($ per share) | $ / shares | $ 34.75 | |||||||||
Stock issued (shares) | shares | 55,000,000 | |||||||||
Cash paid | $ 665,000,000 | |||||||||
Consideration transferred | 3,200,000,000 | |||||||||
Debt assumed | $ 500,000,000 | |||||||||
Onshore United States properties | ||||||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||
Sales Proceeds | 135,000,000 | |||||||||
Gain on Divestitures | $ (36,000,000) |
Merger, Acquisitions, and Dives
Merger, Acquisitions, and Divestitures Merger, Acquisitions and Divestitures - Merger (Details) - USD ($) | Jul. 20, 2015 | Jun. 30, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Business Acquisition [Line Items] | |||||
Stock issued (shares) | 0 | 41,048,240 | |||
Goodwill | $ 0 | $ 620,000,000 | |||
Gain to other operating expense | $ 25,000,000 | $ 25,000,000 | |||
Business Acquisition, Pro Forma Information [Abstract] | |||||
Business Acquisition, Pro Forma Revenue | 3,491,000,000 | 3,478,000,000 | 6,126,000,000 | ||
Business Acquisition, Pro Forma Net Income (Loss) | $ (998,000,000) | $ (2,393,000,000) | $ 1,607,000,000 | ||
Business Acquisition, Pro Forma Earnings Per Share, Basic | $ (2.32) | $ (5.64) | $ 4.01 | ||
Business Acquisition, Pro Forma Earnings Per Share, Diluted | $ (2.32) | $ (5.64) | $ 3.94 | ||
Rosetta Resources, Inc | |||||
Business Acquisition [Line Items] | |||||
Stock issued (shares) | 41,000,000 | ||||
Noble Energy common stock price on July 20, 2015 (in dollars per share) | $ 36.97 | ||||
Fair value of common stock issued | $ 1,518,000,000 | ||||
Plus: fair value of Rosetta's restricted stock awards and performance awards assumed | 10,000,000 | ||||
Plus: Rosetta stock options assumed | 1,000,000 | ||||
Total purchase price | 1,529,000,000 | ||||
Accounts Payable | 100,000,000 | ||||
Current Liabilities | 37,000,000 | ||||
Long-Term Debt | 1,992,000,000 | ||||
Other Long Term Liabilities | 23,000,000 | ||||
Asset Retirement Obligation | 27,000,000 | ||||
Total purchase price plus liabilities assumed | 3,708,000,000 | ||||
Cash and Equivalents | 61,000,000 | ||||
Other Current Assets | 76,000,000 | ||||
Derivative Instruments | 209,000,000 | ||||
Proved Properties | 1,613,000,000 | ||||
Undeveloped Leaseholds | 1,355,000,000 | ||||
Gathering and Processing Assets | 207,000,000 | ||||
Asset Retirement Obligation | 27,000,000 | ||||
Other Property Plant and Equipment | 5,000,000 | ||||
Long Term Deferred Tax Asset | 17,000,000 | ||||
Goodwill | 138,000,000 | $ 163,000,000 | |||
Total Asset Value | $ 3,708,000,000 |
Merger, Acquisitions and Dive50
Merger, Acquisitions and Divestitures - Sales Transactions (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Discontinued Operations and Disposal Groups [Abstract] | |||
Sales Proceeds | $ 1,241 | $ 151 | $ 321 |
Net Book Value of Assets Sold | (993) | (156) | (297) |
Asset Retirement Obligations Associated with Assets Sold | 7 | 8 | 48 |
Goodwill Allocated to Assets Sold | 0 | (4) | (7) |
Other Closing Adjustments | (17) | 1 | 8 |
Gain on Divestitures | $ 238 | $ 0 | $ 73 |
Noble Midstream Partners LP (De
Noble Midstream Partners LP (Details) - USD ($) $ / shares in Units, $ in Millions | Sep. 20, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Related Party Transaction [Line Items] | ||||
Proceeds from Issuance or Sale of Equity | $ 0 | $ 1,112 | $ 0 | |
IPO | Noble Midstream Revolving Credit Facility, due September 20, 2021 | ||||
Related Party Transaction [Line Items] | ||||
Offering costs | $ 24 | |||
IPO | Noble Midstream Revolving Credit Facility, due September 20, 2021 | Common Units | ||||
Related Party Transaction [Line Items] | ||||
Sale (units) | 14,375,000 | |||
Issued ($ per share) | $ 22.50 | |||
Issued, net ($ per share) | $ 21.21 | |||
Over-Allotment Option | Noble Midstream Revolving Credit Facility, due September 20, 2021 | Common Units | ||||
Related Party Transaction [Line Items] | ||||
Sale (units) | 1,875,000 | |||
Noble Energy | Noble Midstream Revolving Credit Facility, due September 20, 2021 | Common Units | ||||
Related Party Transaction [Line Items] | ||||
Sale (units) | 1,527,584 | |||
Noble Energy | Noble Midstream Revolving Credit Facility, due September 20, 2021 | Subordinated Units | ||||
Related Party Transaction [Line Items] | ||||
Sale (units) | 15,902,584 | |||
Affiliated Entity | Noble Energy | Noble Midstream Revolving Credit Facility, due September 20, 2021 | Common Units | ||||
Related Party Transaction [Line Items] | ||||
Ownership | 4.80% | |||
Affiliated Entity | Noble Energy | Noble Midstream Revolving Credit Facility, due September 20, 2021 | Subordinated Units | ||||
Related Party Transaction [Line Items] | ||||
Ownership | 50.00% | |||
Noble Midstream Partners LP | Noble Midstream Revolving Credit Facility, due September 20, 2021 | ||||
Related Party Transaction [Line Items] | ||||
Proceeds from Issuance or Sale of Equity | $ 299 | $ 299 | $ 0 | $ 0 |
Asset Impairments (Details)
Asset Impairments (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Impaired Long-Lived Assets Held and Used [Line Items] | ||||
Asset Impairments | $ 5 | $ 92 | $ 533 | $ 500 |
Onshore US | ||||
Impaired Long-Lived Assets Held and Used [Line Items] | ||||
Asset Impairments | 0 | 0 | 42 | |
Deepwater Gulf of Mexico | ||||
Impaired Long-Lived Assets Held and Used [Line Items] | ||||
Asset Impairments | 0 | 158 | 350 | |
Equatorial Guinea | ||||
Impaired Long-Lived Assets Held and Used [Line Items] | ||||
Asset Impairments | 0 | 339 | 0 | |
Eastern Mediterranean | ||||
Impaired Long-Lived Assets Held and Used [Line Items] | ||||
Asset Impairments | 88 | 36 | 14 | |
North Sea | ||||
Impaired Long-Lived Assets Held and Used [Line Items] | ||||
Asset Impairments | 0 | 0 | 94 | |
Other International and Corporate | ||||
Impaired Long-Lived Assets Held and Used [Line Items] | ||||
Asset Impairments | 4 | $ 0 | $ 0 | |
Leviathan-1 Deep | ||||
Impaired Long-Lived Assets Held and Used [Line Items] | ||||
Asset Impairments | $ 88 |
Asset Impairments Impaired Long
Asset Impairments Impaired Long-Lived Assets Held and Used- text (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Impaired Long-Lived Assets Held and Used [Line Items] | ||||
Asset Impairments | $ 5 | $ 92 | $ 533 | $ 500 |
Other (Onshore US) | ||||
Impaired Long-Lived Assets Held and Used [Line Items] | ||||
Asset Impairments | 481 | |||
Gulf of Mexico and Eastern Mediterranean | ||||
Impaired Long-Lived Assets Held and Used [Line Items] | ||||
Asset Impairments | $ 47 | |||
United States | ||||
Impaired Long-Lived Assets Held and Used [Line Items] | ||||
Asset Impairments | 250 | |||
South Raton (Deepwater Gulf of Mexico) | ||||
Impaired Long-Lived Assets Held and Used [Line Items] | ||||
Asset Impairments | 74 | |||
Other Deepwater Gulf of Mexico | ||||
Impaired Long-Lived Assets Held and Used [Line Items] | ||||
Asset Impairments | 51 | |||
Reclassification Of Non-Strategic Properties As Held For Sale | ||||
Impaired Long-Lived Assets Held and Used [Line Items] | ||||
Asset Impairments | $ 31 |
Capitalized Exploratory Well 54
Capitalized Exploratory Well Costs (Details) $ in Millions | 12 Months Ended | |||||
Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | |
Exploratory Wells Drilled [Line Items] | ||||||
Farm down | 35.00% | |||||
Capitalized costs charged to expense | $ (525) | $ (88) | $ (84) | |||
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward] | ||||||
Capitalized Exploratory Well Costs, Beginning of Period | 1,353 | 1,337 | 1,301 | |||
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves | 84 | 123 | 316 | |||
Divestitures and Other (1) | (143) | 0 | 0 | |||
Capitalized Exploratory Well Costs Charged to Expense | (1) | (19) | (196) | |||
Capitalized Exploratory Well Costs, End of Period | 768 | 1,353 | 1,337 | |||
Exploratory Well Costs Capitalized for a Period of One Year or Less | $ 69 | $ 95 | $ 247 | |||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 699 | 1,258 | 1,090 | |||
Capitalized Exploratory Well Costs, | $ 1,353 | $ 1,337 | $ 1,301 | $ 768 | $ 1,353 | $ 1,337 |
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 10 | 14 | 13 |
Capitalized Exploratory Well 55
Capitalized Exploratory Well Costs (Details 2) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Mar. 31, 2016 | |
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Cost threshold | $ 20 | |||
Capitalized undeveloped leasehold cost | 2,200 | |||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 699 | $ 1,258 | $ 1,090 | |
Undeveloped Leasehold Impairment | 93 | $ 21 | $ 0 | |
Provision for losses | 34 | |||
Suspended Since 2013 and 2014 | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 183 | |||
Suspended Since 2011 and 2012 | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 263 | |||
Suspended Since 2010 and Prior | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 253 | |||
Troubadour | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 52 | |||
Troubadour | Suspended Since 2013 and 2014 | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 5 | |||
Troubadour | Suspended Since 2011 and 2012 | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 47 | |||
Troubadour | Suspended Since 2010 and Prior | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 0 | |||
Katmai | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 98 | |||
Katmai | Suspended Since 2013 and 2014 | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 98 | |||
Katmai | Suspended Since 2011 and 2012 | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 0 | |||
Katmai | Suspended Since 2010 and Prior | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 0 | |||
Yolanda Offshore Equatorial Guinea [Member] | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 45 | |||
Yolanda Offshore Equatorial Guinea [Member] | Suspended Since 2013 and 2014 | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 7 | |||
Yolanda Offshore Equatorial Guinea [Member] | Suspended Since 2011 and 2012 | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 9 | |||
Yolanda Offshore Equatorial Guinea [Member] | Suspended Since 2010 and Prior | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 29 | |||
Yolanda (Block I) | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 22 | |||
Yolanda (Block I) | Suspended Since 2013 and 2014 | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 3 | |||
Yolanda (Block I) | Suspended Since 2011 and 2012 | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 5 | |||
Yolanda (Block I) | Suspended Since 2010 and Prior | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 14 | |||
YoYo (YoYo Block) | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 54 | |||
YoYo (YoYo Block) | Suspended Since 2013 and 2014 | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 6 | |||
YoYo (YoYo Block) | Suspended Since 2011 and 2012 | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 13 | |||
YoYo (YoYo Block) | Suspended Since 2010 and Prior | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 35 | |||
Leviathan | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 199 | |||
Leviathan | Suspended Since 2013 and 2014 | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 18 | |||
Leviathan | Suspended Since 2011 and 2012 | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 77 | |||
Leviathan | Suspended Since 2010 and Prior | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 104 | |||
Leviathan-1 Deep | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 85 | |||
Leviathan-1 Deep | Suspended Since 2013 and 2014 | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 7 | |||
Leviathan-1 Deep | Suspended Since 2011 and 2012 | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 51 | |||
Leviathan-1 Deep | Suspended Since 2010 and Prior | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 27 | |||
Dalit | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 31 | |||
Dalit | Suspended Since 2013 and 2014 | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 4 | |||
Dalit | Suspended Since 2011 and 2012 | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 7 | |||
Dalit | Suspended Since 2010 and Prior | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 20 | |||
Cyprus | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 89 | |||
Cyprus | Suspended Since 2013 and 2014 | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 12 | |||
Cyprus | Suspended Since 2011 and 2012 | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 54 | |||
Cyprus | Suspended Since 2010 and Prior | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 23 | |||
Projects less than $20 million | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 24 | |||
Projects less than $20 million | Suspended Since 2013 and 2014 | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 23 | |||
Projects less than $20 million | Suspended Since 2011 and 2012 | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 0 | |||
Projects less than $20 million | Suspended Since 2010 and Prior | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Exploratory Well Costs Capitalized for a Period Greater Than One Year Since Commencement of Drilling | 1 | |||
Onshore US | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Capitalized undeveloped leasehold cost | 2,100 | |||
Deepwater Gulf of Mexico | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Capitalized undeveloped leasehold cost | 105 | |||
International | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Capitalized undeveloped leasehold cost | 32 | |||
Cyprus Block 12 | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Total consideration value | $ 131 | |||
Gulf of Mexico and Falkland Island | ||||
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items] | ||||
Capitalized undeveloped leasehold cost | $ 127 |
Equity Method Investments (Deta
Equity Method Investments (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Schedule of Equity Method Investments [Line Items] | ||||
Distributions from Equity Method Investments | $ 70 | $ 0 | $ 156 | |
Equity Method Investments | $ 400 | 400 | 453 | 325 |
Equity Method Investment, Financial Statement, Reported Amounts [Abstract] | ||||
Retained earnings related to undistributed earnings of equity method investees | 95 | |||
AMPCO Equity Method Investment, Difference Between Carrying Amount and Underlying Equity [Abstract] | ||||
Difference between the carrying value of an equity method investment and the underlying net assets of the investee | 12 | 12 | ||
Balance Sheet Information | ||||
Current Assets | 313 | 313 | 343 | |
Noncurrent Assets | 1,390 | 1,390 | 1,418 | |
Current Liabilities | 149 | 149 | 229 | |
Noncurrent Liabilities | $ 256 | 256 | 108 | |
Statements of Operations Information | ||||
Operating Revenues | 667 | 645 | 1,142 | |
Operating Expenses | 355 | 393 | 405 | |
Operating Income | 312 | 252 | 737 | |
Other (Income) Net | (7) | (9) | (9) | |
Income Before Income Taxes | 319 | 261 | 746 | |
Income Tax Provision | 60 | 46 | 172 | |
Net Income | $ 259 | 215 | $ 574 | |
AMPCO | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Ownership interest in equity method investments (in hundredths) | 45.00% | 45.00% | ||
Equity Method Investments | $ 120 | $ 120 | 120 | |
Alba Plant | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Ownership interest in equity method investments (in hundredths) | 28.00% | 28.00% | ||
Equity Method Investments | $ 82 | $ 82 | 87 | |
CONE Investments | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Ownership interest in equity method investments (in hundredths) | 50.00% | 50.00% | ||
Distributions from Equity Method Investments | $ 70 | |||
Equity Method Investments | $ 172 | $ 172 | 214 | |
CONE Midstream | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Ownership interest in equity method investments (in hundredths) | 34.00% | 34.00% | ||
Other | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Equity Method Investments | $ 26 | $ 26 | $ 32 | |
Common Units | CONE Midstream | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Owned (shares) | 7,110,638 | 7,110,638 | ||
Subordinated Units | CONE Midstream | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Owned (shares) | 14,581,560 | 14,581,560 |
Derivative Instruments and He57
Derivative Instruments and Hedging Activities (Details) | 12 Months Ended |
Dec. 31, 2016bbl / dMMBTU / d$ / bbl$ / MMBTU | |
Crude Oil Commodity Contract | Swaps - NYMEX WTI 2017 | |
Derivative [Line Items] | |
Settlement Period | 2,017 |
Index | NYMEX WTI |
Volume Per Day | bbl / d | 4,000 |
Weighted Average Fixed Price | 50.90 |
Crude Oil Commodity Contract | Three Way Collars - NYMEX WTI 2017 | |
Derivative [Line Items] | |
Settlement Period | 2,017 |
Index | NYMEX WTI |
Volume Per Day | bbl / d | 24,000 |
Weighted Average Short Put Price | 39.08 |
Weighted Average Floor Price | 47.71 |
Weighted Average Ceiling Price | 61.20 |
Crude Oil Commodity Contract | Call - NYMEX WTI 2017 | |
Derivative [Line Items] | |
Settlement Period | 2,017 |
Index | NYMEX WTI |
Volume Per Day | bbl / d | 3,000 |
Weighted Average Ceiling Price | 57 |
Crude Oil Commodity Contract | Three Way Collars - ICE Brent 2017 | |
Derivative [Line Items] | |
Settlement Period | 2,017 |
Index | ICE Brent |
Volume Per Day | bbl / d | 2,000 |
Weighted Average Short Put Price | 43 |
Weighted Average Floor Price | 50 |
Weighted Average Ceiling Price | 63.15 |
Crude Oil Commodity Contract | Two Way Collars - NYMEX WTI 2017 | |
Derivative [Line Items] | |
Settlement Period | 2,017 |
Index | NYMEX WTI |
Volume Per Day | bbl / d | 7,000 |
Weighted Average Floor Price | 40 |
Weighted Average Ceiling Price | 53.29 |
Crude Oil Commodity Contract | Three Way Collars - Dated Brent 2017 | |
Derivative [Line Items] | |
Settlement Period | 2,017 |
Index | Dated Brent |
Volume Per Day | bbl / d | 2,000 |
Weighted Average Short Put Price | 35 |
Weighted Average Floor Price | 45 |
Weighted Average Ceiling Price | 66.33 |
Crude Oil Commodity Contract | Three Way Collars - NYMEX WTI 2018 | |
Derivative [Line Items] | |
Settlement Period | 2,018 |
Index | NYMEX WTI |
Volume Per Day | bbl / d | 5,000 |
Weighted Average Short Put Price | 43 |
Weighted Average Floor Price | 50 |
Weighted Average Ceiling Price | 68.50 |
Crude Oil Commodity Contract | Swaps - NYMEX WTI 2018 | |
Derivative [Line Items] | |
Settlement Period | 2,018 |
Index | NYMEX WTI |
Volume Per Day | bbl / d | 5,000 |
Weighted Average Fixed Price | 54.03 |
Crude Oil Commodity Contract | Swaptions - NYMEX WTI 2018 | |
Derivative [Line Items] | |
Settlement Period | 2,018 |
Index | NYMEX WTI |
Volume Per Day | bbl / d | 3,000 |
Weighted Average Fixed Price | 56.10 |
Crude Oil Commodity Contract | Three Way Collars - Dated Brent 2018 | |
Derivative [Line Items] | |
Settlement Period | 2,018 |
Index | Dated Brent |
Volume Per Day | bbl / d | 3,000 |
Weighted Average Short Put Price | 40 |
Weighted Average Floor Price | 50 |
Weighted Average Ceiling Price | 70.41 |
Natural Gas Commodity Contract | Swaps - NYMEX HH 2016 | |
Derivative [Line Items] | |
Settlement Period | 1H17 (1) |
Index | NYMEX HH |
Volume Per Day | MMBTU / d | 30,000 |
Weighted Average Fixed Price | $ / MMBTU | 2.92 |
Natural Gas Commodity Contract | Swaps - NYMEX HH 2017 [Member] | |
Derivative [Line Items] | |
Settlement Period | 2,017 |
Index | NYMEX HH |
Volume Per Day | MMBTU / d | 110,000 |
Weighted Average Fixed Price | $ / MMBTU | 3.16 |
Natural Gas Commodity Contract | Three Way Collars - NYMEX HH 2017 [Member] | |
Derivative [Line Items] | |
Settlement Period | 2,017 |
Index | NYMEX HH |
Volume Per Day | MMBTU / d | 210,000 |
Weighted Average Short Put Price | $ / MMBTU | 2.54 |
Weighted Average Floor Price | $ / MMBTU | 2.96 |
Weighted Average Ceiling Price | $ / MMBTU | 3.62 |
Natural Gas Commodity Contract | Two Way Collars - NYMEX HH 2017 [Member] | |
Derivative [Line Items] | |
Settlement Period | 2,017 |
Index | NYMEX HH |
Volume Per Day | MMBTU / d | 70,000 |
Weighted Average Floor Price | $ / MMBTU | 2.93 |
Weighted Average Ceiling Price | $ / MMBTU | 3.32 |
Natural Gas Commodity Contract | Three Way Collars - NYMEX HH 2018 [Member] | |
Derivative [Line Items] | |
Settlement Period | 2,018 |
Index | NYMEX HH |
Volume Per Day | MMBTU / d | 70,000 |
Weighted Average Short Put Price | $ / MMBTU | 2.50 |
Weighted Average Floor Price | $ / MMBTU | 2.80 |
Weighted Average Ceiling Price | $ / MMBTU | 3.76 |
First half 2017 | Crude Oil Commodity Contract | Swaps - NYMEX WTI 2017 | |
Derivative [Line Items] | |
Settlement Period | 1H17 (1) |
Index | NYMEX WTI |
Volume Per Day | bbl / d | 6,000 |
Weighted Average Fixed Price | 55.08 |
First half 2017 | Crude Oil Commodity Contract | Swaps - Dated Brent 2017 | |
Derivative [Line Items] | |
Settlement Period | 1H17 (1) |
Index | Dated Brent |
Volume Per Day | bbl / d | 3,000 |
Weighted Average Fixed Price | 62.80 |
First half 2017 | Crude Oil Commodity Contract | Two Way Collars - NYMEX WTI 2017 | |
Derivative [Line Items] | |
Settlement Period | 1H17 (1) |
Index | NYMEX WTI |
Volume Per Day | bbl / d | 2,000 |
Weighted Average Floor Price | 40 |
Weighted Average Ceiling Price | 50.44 |
Second half 2017 | Crude Oil Commodity Contract | Swaps - NYMEX WTI 2017 | |
Derivative [Line Items] | |
Settlement Period | 2H17 (1) |
Index | Dated Brent |
Volume Per Day | bbl / d | 3,000 |
Weighted Average Fixed Price | 62.80 |
Second half 2017 | Crude Oil Commodity Contract | Swaps - Dated Brent 2017 | |
Derivative [Line Items] | |
Settlement Period | 2H17 (1) |
Index | NYMEX WTI |
Volume Per Day | bbl / d | 3,000 |
Weighted Average Fixed Price | 50.05 |
Second half 2017 | Crude Oil Commodity Contract | Call - NYMEX WTI 2017 | |
Derivative [Line Items] | |
Settlement Period | 2H17 (1) |
Index | NYMEX WTI |
Volume Per Day | bbl / d | 3,000 |
Weighted Average Ceiling Price | 60.12 |
Second half 2017 | Natural Gas Commodity Contract | Swaps - NYMEX HH 2017 [Member] | |
Derivative [Line Items] | |
Settlement Period | 2H17 (1) |
Index | NYMEX HH |
Volume Per Day | MMBTU / d | 30,000 |
Weighted Average Fixed Price | $ / MMBTU | 3.45 |
Second half 2017 | Natural Gas Commodity Contract | Swaptions - NYMEX HH 2017 [Member] [Member] | |
Derivative [Line Items] | |
Volume Per Day | MMBTU / d | 30,000 |
Weighted Average Fixed Price | $ / MMBTU | 2.92 |
Derivative Instruments and He58
Derivative Instruments and Hedging Activities (Details 2) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Derivatives, Fair Value [Line Items] | |||
Asset Derivative Instruments | $ 0 | $ 592 | |
Liability Derivative Instruments | 116 | 0 | |
Cash (Received) Paid in Settlement of Commodity Derivative Instruments | 139 | (501) | $ (976) |
Total Cash Received in Settlement of Commodity Derivative Instruments | (569) | (1,009) | (29) |
Total Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments | 708 | 508 | (947) |
Total Loss (Gain) on Commodity Derivative Instruments | 139 | (501) | (976) |
Crude Oil | |||
Derivatives, Fair Value [Line Items] | |||
Cash (Received) Paid in Settlement of Commodity Derivative Instruments | (499) | (844) | (34) |
Total Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments | 582 | 423 | (863) |
Total Loss (Gain) on Commodity Derivative Instruments | 83 | (421) | (897) |
Natural Gas | |||
Derivatives, Fair Value [Line Items] | |||
Cash (Received) Paid in Settlement of Commodity Derivative Instruments | (70) | (147) | 5 |
Total Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments | 126 | 65 | (84) |
Total Loss (Gain) on Commodity Derivative Instruments | 56 | (82) | (79) |
Natural Gas Liquids | |||
Derivatives, Fair Value [Line Items] | |||
Cash (Received) Paid in Settlement of Commodity Derivative Instruments | 0 | (18) | 0 |
Total Non-cash Portion of Loss (Gain) on Commodity Derivative Instruments | 0 | 20 | 0 |
Total Loss (Gain) on Commodity Derivative Instruments | 0 | 2 | $ 0 |
Current Assets | |||
Derivatives, Fair Value [Line Items] | |||
Asset Derivative Instruments | 0 | 582 | |
Current Liabilities | |||
Derivatives, Fair Value [Line Items] | |||
Liability Derivative Instruments | 102 | 0 | |
Noncurrent Assets | |||
Derivatives, Fair Value [Line Items] | |||
Asset Derivative Instruments | 0 | 10 | |
Noncurrent Liabilities | |||
Derivatives, Fair Value [Line Items] | |||
Liability Derivative Instruments | $ 14 | $ 0 |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Asset Retirement Obligations, Beginning Balance | $ 989 | $ 751 |
Liabilities Incurred | 21 | 67 |
Liabilities Settled | (120) | (38) |
Revision of Estimate | (3) | 166 |
Accretion Expense | 48 | 43 |
Asset Retirement Obligations, Ending Balance | 935 | 989 |
Deepwater Gulf of Mexico | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Liabilities Incurred | 16 | |
Liabilities Settled | (2) | |
Revision of Estimate | 35 | |
Eagle Ford Shale and Permian Delaware Basin | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Liabilities Incurred | 29 | |
DJ Basin (Onshore US) | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Liabilities Settled | (23) | |
Revision of Estimate | 96 | |
Onshore US | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Liabilities Incurred | 22 | |
Equatorial Guinea | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Revision of Estimate | (10) | |
Eastern Mediterranean | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Revision of Estimate | 48 | |
Non-Core Onshore US | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Revision of Estimate | (3) | |
North Sea | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Liabilities Settled | $ (13) | |
Onshore US | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Liabilities Incurred | 49 | |
Deepwater Gulf of Mexico | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Liabilities Incurred | 65 | |
Tamar Field, Offshore Israel | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Liabilities Incurred | 5 | |
North Sea | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Liabilities Incurred | $ 1 |
Long-Term Debt (Details)
Long-Term Debt (Details) - USD ($) | Jan. 06, 2016 | Jul. 29, 2015 | Oct. 03, 2013 | Dec. 31, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Sep. 20, 2016 | Aug. 27, 2015 |
Debt Instrument [Line Items] | |||||||||
Debt | $ 7,114,000,000 | $ 7,114,000,000 | $ 7,976,000,000 | ||||||
Unamortized Discount | (23,000,000) | (23,000,000) | (24,000,000) | ||||||
Debt Instrument, Unamortized Premium | 17,000,000 | 17,000,000 | 113,000,000 | ||||||
Total Debt, Net of Discount | 7,074,000,000 | 7,074,000,000 | 8,029,000,000 | ||||||
Capital Lease Obligations, Current | (63,000,000) | (63,000,000) | (53,000,000) | ||||||
Long-Term Debt Due After One Year | 7,011,000,000 | 7,011,000,000 | 7,976,000,000 | ||||||
Debt Exchange, Percent of Outstanding Notes Tendered for Exchange | 99.40% | ||||||||
Deferred Finance Costs, Net | $ 12,000,000 | ||||||||
Repayments of Lines of Credit | $ 70,000,000 | 850,000,000 | 0 | $ 0 | |||||
Repayments of Long-term Debt [Abstract] | |||||||||
2,014 | 0 | 0 | |||||||
2,015 | 0 | 0 | |||||||
2,016 | 1,550,000,000 | 1,550,000,000 | |||||||
2,017 | 0 | 0 | |||||||
2,018 | 1,379,000,000 | 1,379,000,000 | |||||||
Thereafter | 3,810,000,000 | 3,810,000,000 | |||||||
Total | 6,739,000,000 | 6,739,000,000 | |||||||
Gain on extinguishment | 80,000,000 | 0 | 0 | ||||||
Repayments of Long-term Lines of Credit | 850,000,000 | 0 | 70,000,000 | $ 0 | |||||
Term Loan Facility | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt | 1,400,000,000 | 1,400,000,000 | |||||||
Line of Credit | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt | $ 0 | $ 0 | $ 0 | ||||||
Interest Rate | 0.00% | 0.00% | 0.00% | ||||||
Debt Instrument, Offering Date | Aug. 27, 2015 | ||||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 4,000,000,000 | ||||||||
Credit facility aggregate short-term loans and letters of credit, maximum | $ 500,000,000 | ||||||||
Credit facility covenant term debt to capitalization ratio maximum | 65.00% | ||||||||
Credit facility interest rate, Eurodollar rate plus, minimum | 0.90% | ||||||||
Credit facility fee rate basis points, minimum | 0.10% | ||||||||
Credit facility fee rate basis points, maximum | 0.25% | ||||||||
Credit facility interest rate, Eurodollar rate plus, maximum | 1.50% | ||||||||
Noble Midstream Revolving Credit Facility, due September 20, 2021 | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt | $ 0 | $ 0 | $ 0 | ||||||
Interest Rate | 0.00% | 0.00% | 0.00% | ||||||
Capital Lease and Other Obligations | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt | $ 375,000,000 | $ 375,000,000 | $ 403,000,000 | ||||||
Interest Rate | 0.00% | 0.00% | 0.00% | ||||||
Capital Lease Obligations, Current | $ (63,000,000) | $ (63,000,000) | $ (53,000,000) | ||||||
8.25% Senior Notes, due March 1, 2019 | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt | $ 1,000,000,000 | $ 1,000,000,000 | $ 1,000,000,000 | ||||||
Interest Rate | 8.25% | 8.25% | 8.25% | ||||||
Senior Notes, due May 1, 2021 | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt | $ 379,000,000 | $ 379,000,000 | $ 693,000,000 | ||||||
Interest Rate | 5.625% | 5.625% | 5.625% | 5.625% | |||||
Debt Instrument, Maturity Date | May 1, 2021 | ||||||||
4.15% Senior Notes, due December 15, 2021 | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt | $ 1,000,000,000 | $ 1,000,000,000 | $ 1,000,000,000 | ||||||
Interest Rate | 4.15% | 4.15% | 4.15% | ||||||
Senior Notes, due June 1, 2022 | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt | $ 18,000,000 | $ 18,000,000 | $ 597,000,000 | ||||||
Interest Rate | 5.875% | 5.875% | 5.875% | 5.875% | |||||
Debt Instrument, Maturity Date | Jun. 1, 2022 | ||||||||
7.25% Senior Notes, due October 15, 2023 | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt | $ 100,000,000 | $ 100,000,000 | $ 100,000,000 | ||||||
Interest Rate | 7.25% | 7.25% | 7.25% | ||||||
Unamortized Debt Issuance Expense | $ (34,000,000) | $ (34,000,000) | $ (36,000,000) | ||||||
Senior Notes, due June 1, 2024 | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt | $ 8,000,000 | $ 8,000,000 | $ 499,000,000 | ||||||
Interest Rate | 5.875% | 5.875% | 5.875% | 5.875% | |||||
Debt Instrument, Maturity Date | Jun. 1, 2024 | ||||||||
Senior Notes Due November 15, 2024 | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt | $ 650,000,000 | $ 650,000,000 | $ 650,000,000 | ||||||
Interest Rate | 3.90% | 3.90% | 3.90% | ||||||
8.00% Senior Notes, due April 1, 2027 | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt | $ 250,000,000 | $ 250,000,000 | $ 250,000,000 | ||||||
Interest Rate | 8.00% | 8.00% | 8.00% | ||||||
6.00% Senior Notes, due March 1, 2041 | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt | $ 850,000,000 | $ 850,000,000 | $ 850,000,000 | ||||||
Interest Rate | 6.00% | 6.00% | 6.00% | ||||||
5.25% Senior Notes, due November 15, 2043 | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt | $ 1,000,000,000 | $ 1,000,000,000 | $ 1,000,000,000 | ||||||
Interest Rate | 5.25% | 5.25% | 5.25% | ||||||
Senior Notes, due November 15, 2044 | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt | $ 850,000,000 | $ 850,000,000 | $ 850,000,000 | ||||||
Interest Rate | 5.05% | 5.05% | 5.05% | ||||||
7.25% Senior Debentures, due August 1, 2097 | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt | $ 84,000,000 | $ 84,000,000 | $ 84,000,000 | ||||||
Interest Rate | 7.25% | 7.25% | 7.25% | ||||||
Credit Facility | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt | $ 550,000,000 | $ 550,000,000 | $ 0 | ||||||
Interest Rate | 2.01% | 2.01% | 0.00% | ||||||
Line of Credit | Term Loan Facility | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt Instrument, Term | 3 years | ||||||||
Repayments of Long-term Debt [Abstract] | |||||||||
Proceeds | $ 1,380,000,000 | ||||||||
Line of Credit | Credit Facility | |||||||||
Debt Instrument [Line Items] | |||||||||
Credit facility fee rate basis points, minimum | 0.10% | ||||||||
Credit facility fee rate basis points, maximum | 0.75% | ||||||||
Federal Funds Effective Swap Rate | Line of Credit | Term Loan Facility | |||||||||
Repayments of Long-term Debt [Abstract] | |||||||||
Basis spread | 0.50% | ||||||||
London Interbank Offered Rate (LIBOR) | Line of Credit | Term Loan Facility | |||||||||
Repayments of Long-term Debt [Abstract] | |||||||||
Basis spread | 1.00% | ||||||||
London Interbank Offered Rate (LIBOR) | Line of Credit | Credit Facility | |||||||||
Debt Instrument [Line Items] | |||||||||
Credit facility interest rate, Eurodollar rate plus, minimum | 1.00% | ||||||||
Credit facility interest rate, Eurodollar rate plus, maximum | 1.75% | ||||||||
Noble Midstream Revolving Credit Facility, due September 20, 2021 | Line of Credit | |||||||||
Debt Instrument [Line Items] | |||||||||
Debt Instrument, Term | 5 years | ||||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 350,000,000 | ||||||||
Repayments of Long-term Debt [Abstract] | |||||||||
Available increase in capacity | 350,000,000 | ||||||||
Noble Midstream Revolving Credit Facility, due September 20, 2021 | Federal Funds Effective Swap Rate | Line of Credit | |||||||||
Repayments of Long-term Debt [Abstract] | |||||||||
Basis spread | 0.50% | ||||||||
Noble Midstream Revolving Credit Facility, due September 20, 2021 | London Interbank Offered Rate (LIBOR) | Line of Credit | |||||||||
Repayments of Long-term Debt [Abstract] | |||||||||
Basis spread | 1.00% | ||||||||
Letter of Credit | Noble Midstream Revolving Credit Facility, due September 20, 2021 | Line of Credit | |||||||||
Debt Instrument [Line Items] | |||||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 100,000,000 | ||||||||
Other Operating Income (Expense) | Line of Credit | Credit Facility | |||||||||
Repayments of Long-term Debt [Abstract] | |||||||||
Gain on extinguishment | $ 80,000,000 |
Income Taxes (Details)
Income Taxes (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | |||||
Jan. 31, 2017 | Jan. 31, 2016 | Jul. 31, 2013 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Jul. 20, 2015 | |
Components of income (loss) before income taxes [Abstract] | |||||||
Domestic | $ (1,859) | $ (2,338) | $ 282 | ||||
Foreign | 87 | 119 | 1,428 | ||||
(Loss) Income Before Income Taxes | (1,772) | (2,219) | 1,710 | ||||
Current Taxes | |||||||
Federal | (4) | (1) | 19 | ||||
State | 5 | 0 | 1 | ||||
Foreign | 196 | 107 | 208 | ||||
Total Current | 197 | 106 | 228 | ||||
Deferred Taxes | |||||||
Federal | (784) | 216 | 237 | ||||
State | (24) | (5) | 13 | ||||
Foreign | (176) | (95) | 18 | ||||
Total Deferred | (984) | 116 | 268 | ||||
Total Income Tax Provision (Benefit) Including Noncontrolling Interests | (787) | 222 | 496 | ||||
Total Income Tax Provision (Benefit) Attributable to Noble Energy | $ (787) | $ 222 | $ 496 | ||||
Effective Tax Rate (in hundredths) | 44.40% | (10.00%) | 29.00% | ||||
Federal statutory tax rate reconciliation [Abstract] | |||||||
Federal Statutory Rate (in hundredths) | 35.00% | 35.00% | 35.00% | ||||
Effect of | |||||||
Earnings of Equity Method Investees (in hundredths) | 1.00% | 0.60% | (3.30%) | ||||
Noncontrolling Interests | 0.40% | (0.00%) | (0.00%) | ||||
Foreign Rate Change | 1.60% | 0.00% | 0.00% | ||||
State Taxes, Net of Federal Benefit (in hundredths) | 1.30% | 0.30% | 0.80% | ||||
Difference Between US and Foreign Rates (in hundredths) | (0.10%) | 2.60% | (14.20%) | ||||
Foreign Exploration Loss (in hundredths) | 0.10% | 2.70% | 0.00% | ||||
Change in Valuation Allowance (in hundredths) | (2.00%) | 0.00% | 1.90% | ||||
Oil Profits Tax - Israel (in hundredths) | 0.00% | 0.10% | 0.20% | ||||
Tax Contingency (in hundredths) | 0.20% | 0.40% | 0.10% | ||||
Indefinite Reinvestment of Foreign Earnings (in hundredths) | 7.20% | (37.70%) | 8.20% | ||||
Goodwill Impairment | 0.00% | (12.30%) | 0.00% | ||||
Other, Net (in hundredths) | (0.30%) | (1.70%) | 0.30% | ||||
Effective Tax Rate (in hundredths) | 44.40% | (10.00%) | 29.00% | ||||
Deferred Tax Assets | |||||||
Loss Carryforwards | $ 474 | $ 468 | |||||
Employee Compensation and Benefits | 150 | 151 | |||||
Other | 49 | 81 | |||||
Total Deferred Tax Assets | 673 | 700 | |||||
Net Deferred Tax Assets | 431 | 494 | |||||
Deferred Tax Assets, Derivative Instruments | 44 | ||||||
Deferred Tax Liabilities | |||||||
Mark to Market of Commodity Derivative Instruments | (128) | ||||||
Accumulated Undistributed Foreign Earnings | 240 | 368 | |||||
Property, Plant and Equipment, Principally Due to Differences in Depreciation, Amortization, Lease Impairment and Abandonments | (2,054) | (2,824) | |||||
Deferred Tax Liabilities, Gross | 2,250 | 3,320 | |||||
Total Deferred Tax Liability | (1,819) | (2,826) | |||||
Deferred Tax Asset and Liability Classification [Abstract] | |||||||
Deferred Tax Liabilities, Net, Current | 0 | 0 | |||||
Deferred Income Tax Liability - Noncurrent | (1,819) | (2,826) | |||||
Accumulated Undistributed Earnings of Foreign Subsidiaries [Abstract] | |||||||
Accumulated undistributed earnings of foreign subsidiaries | 1,600 | ||||||
Estimated future US taxes on the eventual remittance of accumulated undistributed foreign subsidiary earnings | $ 128 | ||||||
US [Member] | |||||||
Earliest Year Open to Examination [Abstract] | |||||||
Income Tax Examination, Year under Examination | 2,013 | ||||||
Equatorial Guinea [Member] | |||||||
Earliest Year Open to Examination [Abstract] | |||||||
Income Tax Examination, Year under Examination | 2,011 | ||||||
Israel [Member] | |||||||
Effect of | |||||||
Statutory Federal Corporate Tax Rate Future Year | 25.00% | 26.50% | |||||
Change in taxes due to change in rate | $ 30 | ||||||
Earliest Year Open to Examination [Abstract] | |||||||
Income Tax Examination, Year under Examination | 2,015 | ||||||
Foreign Loss Carryforward [Member] | |||||||
Deferred Tax Assets | |||||||
Deferred Tax Assets, Valuation Allowance | $ (242) | (206) | |||||
Deferred Tax Liabilities | |||||||
Valuation Allowance Deferred Tax Asset Reversal | $ 60 | ||||||
Rosetta Resources, Inc | |||||||
Deferred Tax Liabilities | |||||||
Operating Loss Carryforwards | $ 681 | ||||||
Subsequent Event | Israel [Member] | |||||||
Effect of | |||||||
Statutory Federal Corporate Tax Rate Future Year | 24.00% |
Income Taxes Income Taxes (Deta
Income Taxes Income Taxes (Details 2) $ in Millions | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |
Unrecognized Tax Benefits, Beginning Balance | $ 8 |
Additions for Tax Positions Related to Current Year | 0 |
Additions for Tax Positions of Prior Years | 0 |
Reductions for Tax Positions of Prior Years | (3) |
Settlements | (2) |
Unrecognized Tax Benefits, Ending Balance | 3 |
Unrecognized tax benefits that would impact our effective tax rate if recognized | $ 8 |
Stock-Based and Other Compens63
Stock-Based and Other Compensation Plans (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | |||
Total Stock-Based Compensation Expense | $ 77 | $ 86 | $ 87 |
Tax Benefit Recognized | (27) | (30) | (31) |
General and Administrative Expense | |||
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | |||
Total Stock-Based Compensation Expense | 62 | 50 | 63 |
Exploration Expense and Other | |||
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | |||
Total Stock-Based Compensation Expense | $ 15 | $ 36 | $ 24 |
Stock-Based and Other Compens64
Stock-Based and Other Compensation Plans (Details 2) - USD ($) $ / shares in Units, $ in Millions | Feb. 01, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Stock option activity [Rollforward] | ||||
Exercised (in shares) | (954,898) | (343,145) | ||
Employee Service Share-based Compensation, Aggregate Disclosures [Abstract] | ||||
Share price ($ per share) | $ 31.65 | |||
Stock Option | ||||
Assumptions used to value stock option awards [Abstract] | ||||
Expected term (in years) | 6 years 3 months 18 days | 6 years | 5 years 10 months 24 days | |
Expected volatility (in hundredths) | 32.40% | 32.60% | 35.10% | |
Risk-free rate (in hundredths) | 1.60% | 1.40% | 1.80% | |
Expected dividend yield (in hundredths) | 0.70% | 1.20% | 1.10% | |
Weighted-average grant-date fair value of options granted (in dollars per share) | $ 10.10 | $ 13.93 | $ 20.31 | |
Stock option activity [Rollforward] | ||||
Outstanding, beginning balance (in shares) | 14,571,012 | |||
Granted (in shares) | 2,441,042 | |||
Exercised (in shares) | (954,898) | |||
Forfeited (in shares) | (968,294) | |||
Outstanding, ending balance (in shares) | 15,088,862 | 14,571,012 | ||
Exercisable (in shares) | 10,999,318 | |||
Stock option activity, additional disclosures [Abstract] | ||||
Weighted average exercise price per share outstanding, beginning balance (in dollars per share) | $ 44.59 | |||
Weighted average exercise price per share granted (in dollars per share) | 31.66 | |||
Weighted average exercise price per share exercised (in dollars per share) | 25.96 | |||
Weighted average exercise price per share forfeited (in dollars per share) | 47.27 | |||
Weighted average exercise price per share outstanding, ending balance (in dollars per share) | 43.49 | $ 44.59 | ||
Weighted average exercise price per exercisable share (in dollars per share) | $ 44.54 | |||
Weighted average remaining contractual term of shares outstanding (in years) | 5 years 4 months 24 days | |||
Aggregate intrinsic value of shares outstanding | $ 40 | |||
Weighted average remaining contractual term, exercisable shares (in years) | 4 years 3 months 18 days | |||
Aggregate intrinsic value, exercisable shares | $ 26 | |||
Employee Service Share-based Compensation, Aggregate Disclosures [Abstract] | ||||
Minimum term to maturity on US Treasuries used to determine the risk free rate assumption in valuing stock options | 5 years | |||
Maximum term to maturity on US Treasuries used to determine the risk free rate assumption in valuing stock options | 7 years | |||
The period ended, prior to the date of grant, over which an average of daily stock prices is computed in determining the dividend yield | 3 years | |||
Duration of dividends | 1 year | |||
Total intrinsic value of options exercised | $ 10 | $ 7 | $ 58 | |
Unrecognized compensation cost related to nonvested awards | $ 26 | |||
The weighted-average period over which unrecognized compensation cost is to be recognized (in years) | 1 year 3 months 18 days | |||
Restricted Stock | ||||
Assumptions used to value stock option awards [Abstract] | ||||
Expected volatility (in hundredths) | 38.00% | 30.00% | ||
Risk-free rate (in hundredths) | 1.00% | 0.80% | ||
Restricted stock awards, shares subject to service conditions, additional disclosures [Abstract] | ||||
Weighted average award date fair value, shares awarded (in dollars per share) | $ 29.99 | $ 35.53 | $ 41.22 | |
Employee Service Share-based Compensation, Aggregate Disclosures [Abstract] | ||||
The period ended, prior to the date of grant, over which an average of daily stock prices is computed in determining the dividend yield | 3 years | |||
Unrecognized compensation cost related to nonvested awards | $ 32 | |||
The weighted-average period over which unrecognized compensation cost is to be recognized (in years) | 1 year 3 months 18 days | |||
Weighted average award date fair value, shares awarded (in dollars per share) | $ 29.99 | $ 35.53 | $ 41.22 | |
Total fair value of vested restricted stock | $ 24 | $ 62 | $ 50 | |
Phantom Share Units (PSUs) | ||||
Assumptions used to value stock option awards [Abstract] | ||||
Expected volatility (in hundredths) | 38.00% | |||
Risk-free rate (in hundredths) | 0.90% | |||
Employee Service Share-based Compensation, Aggregate Disclosures [Abstract] | ||||
Unrecognized compensation cost related to nonvested awards | $ 18 | |||
The weighted-average period over which unrecognized compensation cost is to be recognized (in years) | 2 years | |||
Stock Option And Restricted Stock Plan 1992 | ||||
Employee Service Share-based Compensation, Aggregate Disclosures [Abstract] | ||||
Maximum number of shares of common stock authorized for issuance After April 26, 2011 (in shares) | 77,400,000 | |||
Number of shares of common stock reserved for issuance (in shares) | 27,581,280 | |||
Shares of common stock available for future grants and awards (in shares) | 13,059,725 | |||
Expiration period (in years) | 10 years | |||
Stock option vesting period | 3 years | |||
Stock Option And Restricted Stock Plan 1992 | Phantom Share Units (PSUs) | ||||
Employee Service Share-based Compensation, Aggregate Disclosures [Abstract] | ||||
Stock option vesting period | 3 years | |||
Issued (shares) | 1,000,000 | |||
Maximum number of times fair market value of stock price of award issued | 400.00% | |||
Accrued liability | $ 9 | |||
2015 Stock Plan for Non-Employee Directors | ||||
Employee Service Share-based Compensation, Aggregate Disclosures [Abstract] | ||||
Maximum number of shares of common stock authorized for issuance After April 26, 2011 (in shares) | 708,996 | |||
Number of shares of common stock reserved for issuance (in shares) | 705,615 | |||
Shares of common stock available for future grants and awards (in shares) | 563,075 | |||
Stock Plan for Non-Employee Directors 2005 | ||||
Employee Service Share-based Compensation, Aggregate Disclosures [Abstract] | ||||
Number of shares of common stock reserved for issuance (in shares) | 404,865 | |||
Expiration period (in years) | 10 years | |||
Stock option vesting period | 1 year | |||
Subject to Time Vesting | Restricted Stock | ||||
Restricted Stock Awards Activity [Roll Forward] | ||||
Outstanding, beginning balance (in shares) | 1,019,470 | |||
Awarded (in shares) | 898,916 | |||
Vested (in shares) | (421,227) | |||
Forfeited (in shares) | (125,379) | |||
Outstanding, ending balance (in shares) | 1,371,780 | 1,019,470 | ||
Restricted stock awards, shares subject to service conditions, additional disclosures [Abstract] | ||||
Weighted average award date fair value, beginning of period (in dollars per share) | $ 45.55 | |||
Weighted average award date fair value, shares awarded (in dollars per share) | 31.67 | |||
Weighted average award date fair value, shares vested (in dollars per share) | 52.50 | |||
Weighted average award date fair value, shares forfeited (in dollars per share) | 35.54 | |||
Weighted average award date fair value, end of period (in dollars per share) | 36.37 | $ 45.55 | ||
Employee Service Share-based Compensation, Aggregate Disclosures [Abstract] | ||||
Weighted average award date fair value, shares awarded (in dollars per share) | $ 31.67 | |||
Subject to Time Vesting | Phantom Share Units (PSUs) | ||||
Restricted Stock Awards Activity [Roll Forward] | ||||
Outstanding, beginning balance (in shares) | 0 | |||
Awarded (in shares) | 791,000 | |||
Vested (in shares) | (2,501) | |||
Forfeited (in shares) | (76,410) | |||
Outstanding, ending balance (in shares) | 712,089 | 0 | ||
Restricted stock awards, shares subject to service conditions, additional disclosures [Abstract] | ||||
Weighted average award date fair value, beginning of period (in dollars per share) | $ 0 | |||
Weighted average award date fair value, shares awarded (in dollars per share) | 31.65 | |||
Weighted average award date fair value, shares vested (in dollars per share) | 31.65 | |||
Weighted average award date fair value, shares forfeited (in dollars per share) | 31.65 | |||
Weighted average award date fair value, end of period (in dollars per share) | 31.65 | $ 0 | ||
Employee Service Share-based Compensation, Aggregate Disclosures [Abstract] | ||||
Weighted average award date fair value, shares awarded (in dollars per share) | $ 31.65 | |||
Subject to Market Conditions | Restricted Stock | ||||
Restricted Stock Awards Activity [Roll Forward] | ||||
Outstanding, beginning balance (in shares) | 1,929,922 | |||
Awarded (in shares) | 363,256 | |||
Vested (in shares) | (340,410) | |||
Forfeited (in shares) | (449,776) | |||
Outstanding, ending balance (in shares) | 1,502,992 | 1,929,922 | ||
Restricted stock awards, shares subject to service conditions, additional disclosures [Abstract] | ||||
Weighted average award date fair value, beginning of period (in dollars per share) | $ 28.50 | |||
Weighted average award date fair value, shares awarded (in dollars per share) | 24.80 | |||
Weighted average award date fair value, shares vested (in dollars per share) | 42.71 | |||
Weighted average award date fair value, shares forfeited (in dollars per share) | 37.86 | |||
Weighted average award date fair value, end of period (in dollars per share) | 27.43 | $ 28.50 | ||
Employee Service Share-based Compensation, Aggregate Disclosures [Abstract] | ||||
Weighted average award date fair value, shares awarded (in dollars per share) | $ 24.80 | |||
Subject to Market Conditions | Phantom Share Units (PSUs) | ||||
Restricted Stock Awards Activity [Roll Forward] | ||||
Outstanding, beginning balance (in shares) | 0 | |||
Awarded (in shares) | 218,180 | |||
Vested (in shares) | 0 | |||
Forfeited (in shares) | (8,676) | |||
Outstanding, ending balance (in shares) | 209,504 | 0 | ||
Restricted stock awards, shares subject to service conditions, additional disclosures [Abstract] | ||||
Weighted average award date fair value, beginning of period (in dollars per share) | $ 0 | |||
Weighted average award date fair value, shares awarded (in dollars per share) | 6.82 | |||
Weighted average award date fair value, shares vested (in dollars per share) | 0 | |||
Weighted average award date fair value, shares forfeited (in dollars per share) | 6.82 | |||
Weighted average award date fair value, end of period (in dollars per share) | 6.82 | $ 0 | ||
Employee Service Share-based Compensation, Aggregate Disclosures [Abstract] | ||||
Weighted average award date fair value, shares awarded (in dollars per share) | $ 6.82 | |||
Officer | Stock Option And Restricted Stock Plan 1992 | Phantom Share Units (PSUs) | ||||
Employee Service Share-based Compensation, Aggregate Disclosures [Abstract] | ||||
Stock option vesting period | 2 years | |||
Minimum | Stock Option And Restricted Stock Plan 1992 | ||||
Employee Service Share-based Compensation, Aggregate Disclosures [Abstract] | ||||
Stock option vesting period | 2 years |
Stock-Based and Other Compens65
Stock-Based and Other Compensation Plans Stock-Based and Other Compensation Plans (Details 3) - simulation | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Restricted Stock | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Number of Simulations | 500,000 | 500,000 |
Expected volatility (in hundredths) | 38.00% | 30.00% |
Risk-free rate (in hundredths) | 1.00% | 0.80% |
Phantom Share Units (PSUs) | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Number of Simulations | 500,000 | |
Expected volatility (in hundredths) | 38.00% | |
Risk-free rate (in hundredths) | 0.90% |
Stock-Based and Other Compens66
Stock-Based and Other Compensation Plans (Details 4) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items] | |||
Deferred Compensation (Income) Expense | $ 11 | $ (12) | $ (25) |
401K Plan Employer Matching Contribution, Percent | 6.00% | ||
401K Plan Employer Cash Contributions | $ 32 | 35 | $ 26 |
Mutual Fund Investments | 62 | 63 | |
Noble Energy Common Stock (at Fair Value) | 26 | 35 | |
Total Rabbi Trust Assets | 88 | 98 | |
Liability Under Related Deferred Compensation Plan | $ 88 | $ 98 | |
Number of Shares of Noble Energy Common Stock Held by Rabbi Trust | 671,269 | 872,276.87 | |
Shares of common stock held by rabbi trust (in dollars per share) | $ 16.72 | ||
Deferred compensation arrangement most shares held by individual | 600,000 | ||
Deferred compensation arrangement, percent of the most shares held by individual | 89.00% | ||
Deferred compensation distribution timeline | 3 years | ||
Deferred compensation arrangement plan, distribution amount | 200,000 | 200,000 | |
Deferred compensation arrangement shares sold | 1,009 | 1,009 | 19,049 |
Deferred compensation arrangements trust plan, distribution amount | $ 22 | $ 18 | $ 22 |
Deferred compensation liabilities | 121 | $ 119 | |
Phantom Share Units (PSUs) | |||
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items] | |||
Unrecognized compensation cost related to nonvested awards | $ 18 | ||
The weighted-average period over which unrecognized compensation cost is to be recognized (in years) | 2 years |
Fair Value Measurements and D67
Fair Value Measurements and Disclosures of Assets and Liabilities Measured on a Nonrecurring Basis (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Financial Assets | ||||
Mutual Fund Investments | $ 90 | $ 71 | $ 90 | |
Commodity Derivative Instruments | 592 | 0 | 592 | |
Financial Liabilities | ||||
Commodity Derivative Instruments | 0 | (116) | 0 | |
Stock Based Compensation Liability Measured at Fair Value | (98) | (88) | (98) | |
Fair Value Liabilities Measured on a Recurring Basis Stock Compensation Liability | (9) | |||
Asset Impairment Charges [Abstract] | ||||
Impaired Oil and Gas Properties | 5 | 92 | 533 | $ 500 |
Oil and Gas Property, Net Book Value | 92 | 1,285 | ||
Impaired Materials and Supplies Inventory | 14 | 20 | ||
Material and Supply Inventory, Net Book Value | $ 105 | 81 | ||
Impaired Oil and Gas Properties, Net Book Value | 600 | |||
Discount Rate for Impairment Model | 10.00% | |||
Quoted Prices in Active Markets (Level 1) | ||||
Financial Assets | ||||
Mutual Fund Investments | 90 | $ 71 | 90 | |
Commodity Derivative Instruments | 0 | 0 | 0 | |
Financial Liabilities | ||||
Commodity Derivative Instruments | 0 | 0 | 0 | |
Stock Based Compensation Liability Measured at Fair Value | (98) | (88) | (98) | |
Fair Value Liabilities Measured on a Recurring Basis Stock Compensation Liability | (9) | |||
Asset Impairment Charges [Abstract] | ||||
Impaired Oil and Gas Properties | 0 | 0 | 0 | |
Impaired Materials and Supplies Inventory | 0 | 0 | ||
Significant Other Observable Inputs (Level 2) | ||||
Financial Assets | ||||
Mutual Fund Investments | 0 | 0 | 0 | |
Commodity Derivative Instruments | 600 | 5 | 600 | |
Financial Liabilities | ||||
Commodity Derivative Instruments | (8) | (121) | (8) | |
Stock Based Compensation Liability Measured at Fair Value | 0 | 0 | 0 | |
Fair Value Liabilities Measured on a Recurring Basis Stock Compensation Liability | 0 | |||
Asset Impairment Charges [Abstract] | ||||
Impaired Oil and Gas Properties | 0 | 0 | 0 | |
Impaired Materials and Supplies Inventory | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) | ||||
Financial Assets | ||||
Mutual Fund Investments | 0 | 0 | 0 | |
Commodity Derivative Instruments | 0 | |||
Financial Liabilities | ||||
Commodity Derivative Instruments | 0 | 0 | 0 | |
Stock Based Compensation Liability Measured at Fair Value | 0 | 0 | 0 | |
Fair Value Liabilities Measured on a Recurring Basis Stock Compensation Liability | 0 | |||
Asset Impairment Charges [Abstract] | ||||
Impaired Oil and Gas Properties | 0 | 752 | $ 100 | |
Impaired Materials and Supplies Inventory | 91 | 61 | ||
Adjustment | ||||
Financial Assets | ||||
Mutual Fund Investments | 0 | 0 | 0 | |
Commodity Derivative Instruments | (8) | (5) | (8) | |
Financial Liabilities | ||||
Commodity Derivative Instruments | 8 | 5 | 8 | |
Stock Based Compensation Liability Measured at Fair Value | $ 0 | 0 | $ 0 | |
Fair Value Liabilities Measured on a Recurring Basis Stock Compensation Liability | $ 0 |
Fair Value Measurements and D68
Fair Value Measurements and Disclosures (Details 2) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Fair Value | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term Debt, Net of Unamortized Discount | $ 7,112 | $ 7,105 |
Carrying Amount | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-term Debt, Net of Unamortized Discount | $ 6,699 | $ 7,626 |
Earnings (Loss) Per Share (Deta
Earnings (Loss) Per Share (Details) - USD ($) $ / shares in Units, $ in Millions | Jul. 20, 2015 | Mar. 03, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | ||||||
Net Income (Loss) Attributable to Noble Energy | $ (998) | $ (2,441) | $ 1,214 | |||
Earnings Adjustment from Assumed Conversion of Dilutive Shares of Common Stock in Rabbi Trust | 0 | 0 | (17) | |||
Net Income (Loss) Used for Diluted Earnings (Loss) Per Share Calculation | $ (998) | $ (2,441) | $ 1,197 | |||
Weighted Average Number of Shares Outstanding, Basic (in shares) | 430,000,000 | 402,000,000 | 361,000,000 | |||
Incremental Shares From Assumed Conversion of Dilutive Stock Options and Restricted Stock (in shares) | 0 | 0 | 6,000,000 | |||
Weighted Average Number of Shares Outstanding, Diluted (in shares) | 430,000,000 | 402,000,000 | 367,000,000 | |||
Earnings (Loss) from Continuing Operations Per Share, Basic (in dollars per share) | $ (2.32) | $ (6.07) | $ 3.36 | |||
Earnings (Loss) from Continuing Operations Per Share, Diluted (in dollars per share) | $ (2.32) | $ (6.07) | $ 3.27 | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount (in shares) | 14,000,000 | 10,000,000 | 3,000,000 | |||
Weighted average Exercise Price of antidilutive options (in dollars per share) | $ 45.69 | $ 52.39 | $ 60.30 | |||
Shares issued | 0 | 24,150,000 | ||||
Shares of Noble Energy common stock issued to Rosetta shareholders | 0 | 41,048,240 | ||||
Underwritten Public Offering | ||||||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | ||||||
Shares issued | 21,000,000 | 24,150,000 | ||||
Rosetta Resources, Inc | ||||||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | ||||||
Shares of Noble Energy common stock issued to Rosetta shareholders | 41,000,000 |
Segment Information (Details)
Segment Information (Details) | 3 Months Ended | 12 Months Ended | ||
Dec. 31, 2015USD ($) | Dec. 31, 2016USD ($)Operating_Segments | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | |
Segment Reporting Information [Line Items] | ||||
Number of Operating Segments | Operating_Segments | 4 | |||
Oil and Gas Sales Revenue | $ 3,389,000,000 | $ 3,093,000,000 | $ 4,945,000,000 | |
Income from Equity Method Investees | 102,000,000 | 90,000,000 | 170,000,000 | |
Revenues | 3,491,000,000 | 3,183,000,000 | 5,115,000,000 | |
Exploration Expense | 925,000,000 | 488,000,000 | 498,000,000 | |
DD&A | 2,454,000,000 | 2,131,000,000 | 1,759,000,000 | |
Asset Impairments | $ 5,000,000 | 92,000,000 | 533,000,000 | 500,000,000 |
Goodwill Impairment | 0 | 779,000,000 | 0 | |
(Gain) Loss on Divestitures | (238,000,000) | 0 | (73,000,000) | |
Cash (Received) Paid in Settlement of Commodity Derivative Instruments | 139,000,000 | (501,000,000) | (976,000,000) | |
Income (Loss) Before Income Taxes | (1,772,000,000) | (2,219,000,000) | 1,710,000,000 | |
Equity Method Investments | 453,000,000 | 400,000,000 | 453,000,000 | 325,000,000 |
Additions to Long-Lived Assets | 1,526,000,000 | 3,062,000,000 | 5,152,000,000 | |
Goodwill at End of Year (2) | 0 | 0 | 620,000,000 | |
Total Assets at End of Year | 24,196,000,000 | 21,011,000,000 | 24,196,000,000 | 22,518,000,000 |
Foreign Countries | ||||
Segment Reporting Information [Line Items] | ||||
Other Revenue, Net | 1,000,000,000 | 1,100,000,000 | 1,800,000,000 | |
Total Assets at End of Year | 3,900,000,000 | 3,000,000,000 | 3,900,000,000 | 4,400,000,000 |
United States | ||||
Segment Reporting Information [Line Items] | ||||
Oil and Gas Sales Revenue | 2,416,000,000 | 2,011,000,000 | 3,189,000,000 | |
Income from Equity Method Investees | 52,000,000 | 51,000,000 | 9,000,000 | |
Revenues | 2,468,000,000 | 2,062,000,000 | 3,198,000,000 | |
Exploration Expense | 245,000,000 | 203,000,000 | 268,000,000 | |
DD&A | 2,122,000,000 | 1,692,000,000 | 1,318,000,000 | |
Asset Impairments | 0 | 158,000,000 | 392,000,000 | |
Goodwill Impairment | 779,000,000 | |||
(Gain) Loss on Divestitures | (34,000,000) | |||
Cash (Received) Paid in Settlement of Commodity Derivative Instruments | 126,000,000 | (347,000,000) | (604,000,000) | |
Income (Loss) Before Income Taxes | (1,052,000,000) | (1,553,000,000) | 1,150,000,000 | |
Equity Method Investments | 226,000,000 | 183,000,000 | 226,000,000 | 82,000,000 |
Additions to Long-Lived Assets | 1,359,000,000 | 2,534,000,000 | 4,389,000,000 | |
Goodwill at End of Year (2) | 0 | 0 | 620,000,000 | |
Total Assets at End of Year | 18,831,000,000 | 17,029,000,000 | 18,831,000,000 | 16,365,000,000 |
West Africa | ||||
Segment Reporting Information [Line Items] | ||||
Oil and Gas Sales Revenue | 433,000,000 | 580,000,000 | 1,177,000,000 | |
Income from Equity Method Investees | 50,000,000 | 39,000,000 | 161,000,000 | |
Revenues | 483,000,000 | 619,000,000 | 1,338,000,000 | |
Exploration Expense | 483,000,000 | 46,000,000 | 26,000,000 | |
DD&A | 205,000,000 | 326,000,000 | 299,000,000 | |
Asset Impairments | 0 | 339,000,000 | 0 | |
Goodwill Impairment | 0 | |||
(Gain) Loss on Divestitures | 0 | |||
Cash (Received) Paid in Settlement of Commodity Derivative Instruments | 13,000,000 | (154,000,000) | (372,000,000) | |
Income (Loss) Before Income Taxes | (338,000,000) | (77,000,000) | 1,222,000,000 | |
Equity Method Investments | 227,000,000 | 217,000,000 | 227,000,000 | 223,000,000 |
Additions to Long-Lived Assets | 54,000,000 | 124,000,000 | 261,000,000 | |
Goodwill at End of Year (2) | 0 | 0 | 0 | |
Total Assets at End of Year | 2,299,000,000 | 1,479,000,000 | 2,299,000,000 | 2,763,000,000 |
Eastern Mediterranean | ||||
Segment Reporting Information [Line Items] | ||||
Oil and Gas Sales Revenue | 540,000,000 | 497,000,000 | 479,000,000 | |
Income from Equity Method Investees | 0 | 0 | 0 | |
Revenues | 540,000,000 | 497,000,000 | 479,000,000 | |
Exploration Expense | 34,000,000 | 12,000,000 | 17,000,000 | |
DD&A | 81,000,000 | 70,000,000 | 63,000,000 | |
Asset Impairments | 88,000,000 | 36,000,000 | 14,000,000 | |
Goodwill Impairment | 0 | |||
(Gain) Loss on Divestitures | 0 | |||
Cash (Received) Paid in Settlement of Commodity Derivative Instruments | 0 | 0 | 0 | |
Income (Loss) Before Income Taxes | 543,000,000 | 306,000,000 | 284,000,000 | |
Equity Method Investments | 0 | 0 | 0 | 0 |
Additions to Long-Lived Assets | 88,000,000 | 147,000,000 | 201,000,000 | |
Goodwill at End of Year (2) | 0 | 0 | 0 | |
Total Assets at End of Year | 2,677,000,000 | 2,233,000,000 | 2,677,000,000 | 2,806,000,000 |
Other Int'l & Corporate | ||||
Segment Reporting Information [Line Items] | ||||
Oil and Gas Sales Revenue | 0 | 5,000,000 | 100,000,000 | |
Income from Equity Method Investees | 0 | 0 | 0 | |
Revenues | 0 | 5,000,000 | 100,000,000 | |
Exploration Expense | 163,000,000 | 227,000,000 | 187,000,000 | |
DD&A | 46,000,000 | 43,000,000 | 79,000,000 | |
Asset Impairments | 4,000,000 | 0 | 94,000,000 | |
Goodwill Impairment | 0 | |||
(Gain) Loss on Divestitures | (39,000,000) | |||
Cash (Received) Paid in Settlement of Commodity Derivative Instruments | 0 | 0 | 0 | |
Income (Loss) Before Income Taxes | (925,000,000) | (895,000,000) | (946,000,000) | |
Equity Method Investments | 0 | 0 | 0 | 20,000,000 |
Additions to Long-Lived Assets | 25,000,000 | 257,000,000 | 301,000,000 | |
Goodwill at End of Year (2) | 0 | 0 | 0 | |
Total Assets at End of Year | $ 389,000,000 | $ 270,000,000 | $ 389,000,000 | $ 584,000,000 |
Concentration of Risk (Details)
Concentration of Risk (Details) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Concentration of credit risk [Abstract] | |||
Short term deposits original maturities at time of purchase, description | three months or less | ||
Accounts receivables, majority of accounts payment terms, description | 30 days or less | ||
Glencore Energy UK Ltd | |||
Concentration Risk [Line Items] | |||
Percentage of crude oil sales (in hundredths) | 22.00% | 30.00% | 32.00% |
Percentage of total oil, gas & NGL sales (in hundredths) | 12.00% | 18.00% | 22.00% |
Shell | |||
Concentration Risk [Line Items] | |||
Percentage of crude oil sales (in hundredths) | 24.00% | 18.00% | 15.00% |
Percentage of total oil, gas & NGL sales (in hundredths) | 13.00% | 11.00% | 10.00% |
Additional Shareholders' Equi72
Additional Shareholders' Equity Information (Details) - USD ($) $ / shares in Units, $ in Millions | Mar. 25, 2015 | Mar. 03, 2015 | Dec. 31, 2016 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Components And Changes In Accumulated Other Comprehensive Income [Line Items] | |||||||
Common Stock, par value per share (in dollars per share) | $ 0.01 | $ 0.01 | $ 0.01 | ||||
Proceeds from Issuance of Noble Energy Common Stock, Net of Offering Costs | $ 0 | $ 1,112 | $ 0 | ||||
Repayment of facility | $ 850 | $ 0 | $ 70 | $ 0 | |||
Common stock shares issued [Rollforward] | |||||||
Shares, beginning of period (in shares) | 402,329,325 | 469,718,512 | 402,329,325 | ||||
Exercise of common stock options (in shares) | 954,898 | 343,145 | |||||
Restricted stock awards, net of forfeitures (in shares) | 687,017 | 1,847,802 | |||||
Public Equity Offering (in shares) | 0 | 24,150,000 | |||||
Stock issued (shares) | 0 | 41,048,240 | |||||
Shares, end of period (in shares) | 471,360,427 | 471,360,427 | 469,718,512 | 402,329,325 | |||
Treasury stock [Rollforward] | |||||||
Shares, beginning of period (in shares) | 37,635,890 | 37,925,625 | 37,635,890 | ||||
Shares received from employees in payment of withholding taxes due on vesting of shares of restricted stock (in shares) | 236,700 | 490,744 | |||||
Rabbi Trust Shares Distributed and/or Sold (in shares) | (201,009) | (201,009) | |||||
Shares, end of period (in shares) | 37,961,316 | 37,961,316 | 37,925,625 | 37,635,890 | |||
Accumulated Other Comprehensive Loss | |||||||
Beginning Balance | $ (90) | $ (33) | $ (90) | $ (117) | |||
Realized Amounts Reclassified Into Earnings | 5 | 63 | 12 | ||||
Unrealized Change in Fair Value | (3) | (6) | 15 | ||||
End Balance | $ (31) | $ (31) | $ (33) | $ (90) | |||
Effective income tax rate applied to AOCI (in hundredths) | 35.00% | 35.00% | 35.00% | ||||
Deferred loss | $ (21) | ||||||
Interest Rate Cash Flow Hedges | |||||||
Accumulated Other Comprehensive Loss | |||||||
Beginning Balance | (23) | (22) | $ (23) | $ (24) | |||
Realized Amounts Reclassified Into Earnings | 1 | 1 | 1 | ||||
Unrealized Change in Fair Value | 0 | 0 | 0 | ||||
End Balance | (21) | (21) | (22) | (23) | |||
Pension- Related and Other | |||||||
Accumulated Other Comprehensive Loss | |||||||
Beginning Balance | $ (67) | (11) | (67) | (93) | |||
Realized Amounts Reclassified Into Earnings | 4 | 62 | 11 | ||||
Unrealized Change in Fair Value | (3) | (6) | 15 | ||||
End Balance | $ (10) | $ (10) | $ (11) | $ (67) | |||
Underwritten Public Offering | |||||||
Components And Changes In Accumulated Other Comprehensive Income [Line Items] | |||||||
Common Stock, par value per share (in dollars per share) | $ 0.01 | ||||||
Sales price (in dollars per share) | $ 47.50 | ||||||
Proceeds from Issuance of Noble Energy Common Stock, Net of Offering Costs | $ 1,100 | ||||||
Repayment of facility | $ 150 | ||||||
Common stock shares issued [Rollforward] | |||||||
Public Equity Offering (in shares) | 21,000,000 | 24,150,000 | |||||
Over-Allotment Option | |||||||
Components And Changes In Accumulated Other Comprehensive Income [Line Items] | |||||||
Common Stock, par value per share (in dollars per share) | $ 0.01 | ||||||
Common stock shares issued [Rollforward] | |||||||
Public Equity Offering (in shares) | 3.15 |
Commitments and Contingencies73
Commitments and Contingencies (Details) - USD ($) | 1 Months Ended | 12 Months Ended | 24 Months Ended | ||
May 31, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2016 | |
Other Commitments [Line Items] | |||||
Supplemental environmental projects | $ 178,780 | ||||
Reduced penalty | $ 44,695 | ||||
Rental Expense for office buildings and oil and gas operations equipment | $ 76,000,000 | $ 84,000,000 | $ 69,000,000 | ||
Consent Decree | |||||
Other Commitments [Line Items] | |||||
Civil penalty | $ 4,950,000 | $ 54,700,000 | |||
Mitigation projects | 4,500,000 | ||||
Supplemental environmental projects | 4,000,000 | ||||
Marcellus Shale Firm Transportation Agreement | |||||
Other Commitments [Line Items] | |||||
Long-term Purchase Commitment, Amount | 2,100,000,000 | ||||
United States | |||||
Other Commitments [Line Items] | |||||
Long-term Purchase Commitment, Amount | $ 900,000,000 | ||||
Minimum | Marcellus Shale Firm Transportation Agreement | |||||
Other Commitments [Line Items] | |||||
Commitment Obligation, Term | 1 year | ||||
Minimum | United States | |||||
Other Commitments [Line Items] | |||||
Commitment Obligation, Term | 1 year | ||||
Maximum | Marcellus Shale Firm Transportation Agreement | |||||
Other Commitments [Line Items] | |||||
Commitment Obligation, Term | 32 years | ||||
Maximum | United States | |||||
Other Commitments [Line Items] | |||||
Commitment Obligation, Term | 12 years |
Commitments and Contingencies74
Commitments and Contingencies (Details 2) $ in Millions | Dec. 31, 2016USD ($) |
Other Commitments [Line Items] | |
2,016 | $ 612 |
2,017 | 529 |
2,018 | 448 |
2,019 | 382 |
2,020 | 312 |
2021 and Thereafter | 1,947 |
Total | 4,230 |
Drilling, Equipment, and Purchase Obligations | |
Other Commitments [Line Items] | |
2,016 | 255 |
2,017 | 96 |
2,018 | 52 |
2,019 | 27 |
2,020 | 9 |
2021 and Thereafter | 30 |
Total | 469 |
Transportation and Gathering Obligations | |
Other Commitments [Line Items] | |
2,016 | 250 |
2,017 | 312 |
2,018 | 314 |
2,019 | 275 |
2,020 | 237 |
2021 and Thereafter | 1,566 |
Total | 2,954 |
Operating Lease Obligations | |
Other Commitments [Line Items] | |
2,016 | 30 |
2,017 | 42 |
2,018 | 30 |
2,019 | 28 |
2,020 | 28 |
2021 and Thereafter | 188 |
Total | 346 |
Capital Lease and Other Obligations | |
Other Commitments [Line Items] | |
2,016 | 77 |
2,017 | 79 |
2,018 | 52 |
2,019 | 52 |
2,020 | 38 |
2021 and Thereafter | 163 |
Total | $ 461 |