Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Feb. 15, 2018 | Jun. 30, 2017 | |
Document and Entity Information [Abstract] | |||
Entity Registrant Name | NEWFIELD EXPLORATION CO /DE/ | ||
Entity Central Index Key | 912,750 | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2017 | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2,017 | ||
Document Fiscal Period Focus | FY | ||
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 | $ 5,596,079,497 | ||
Entity Common Stock, Shares Outstanding | 199,722,409 |
Consolidated Balance Sheet
Consolidated Balance Sheet - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Current assets: | ||
Cash and cash equivalents | $ 326 | $ 555 |
Short-term investments | 0 | 25 |
Accounts receivable, net | 292 | 232 |
Inventories | 15 | 16 |
Derivative assets | 15 | 75 |
Other current assets | 98 | 46 |
Total current assets | 746 | 949 |
Oil and gas properties, net — full cost method ($1,200 and $1,238 were excluded from amortization at December 31, 2017 and 2016, respectively) | 3,931 | 3,140 |
Other property and equipment, net | 168 | 167 |
Derivative assets | 1 | 0 |
Long-term investments | 24 | 19 |
Restricted cash | 40 | 25 |
Other assets | 51 | 12 |
Total assets | 4,961 | 4,312 |
Current liabilities: | ||
Accounts payable | 46 | 33 |
Accrued liabilities | 591 | 498 |
Advances from joint owners | 80 | 54 |
Asset retirement obligations | 3 | 2 |
Derivative liabilities | 98 | 97 |
Total current liabilities | 818 | 684 |
Other liabilities | 69 | 63 |
Derivative liabilities | 26 | 3 |
Long-term debt | 2,434 | 2,431 |
Asset retirement obligations | 130 | 154 |
Deferred taxes | 76 | 39 |
Total long-term liabilities | 2,735 | 2,690 |
Stockholders' equity: | ||
Preferred stock ($0.01 par value, 5,000,000 shares authorized; no shares issued) | 0 | 0 |
Common stock ($0.01 par value, 300,000,000 shares authorized at December 31, 2017 and 2016; 201,363,345 and 200,150,392 shares issued at December 31, 2017 and 2016, respectively) | 2 | 2 |
Additional paid-in capital | 3,303 | 3,247 |
Treasury stock (at cost, 1,658,476 and 1,195,809 shares at December 31, 2017 and 2016, respectively) | (59) | (44) |
Accumulated other comprehensive income (loss) | 0 | (2) |
Retained earnings (deficit) | (1,838) | (2,265) |
Total stockholders' equity | 1,408 | 938 |
Total liabilities and stockholders' equity | $ 4,961 | $ 4,312 |
Consolidated Balance Sheet (Par
Consolidated Balance Sheet (Parenthetical) - USD ($) | Dec. 31, 2017 | Dec. 31, 2016 |
ASSETS | ||
Property and Equipment, at cost | $ 1,200,000,000 | $ 1,238,000,000 |
Stockholders' equity: | ||
Preferred stock ($0.01 par value) | $ 0.01 | $ 0.01 |
Preferred stock (5,000,000 shares authorized) | 5,000,000 | 5,000,000 |
Preferred stock (no shares issued) | 0 | 0 |
Common stock ($0.01 par value) | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 300,000,000 | 300,000,000 |
Common stock, shares issued | 201,363,345 | 200,150,392 |
Treasury Stock, shares | 1,658,476 | 1,195,809 |
Commitments and contingencies | $ 0 | $ 0 |
Consolidated Statement of Opera
Consolidated Statement of Operations and Comprehensive Income - USD ($) shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Income Statement [Abstract] | |||
Oil, gas and NGL revenues | $ 1,767 | $ 1,472 | $ 1,557 |
Operating expenses: | |||
Lease operating | 215 | 244 | 285 |
Transportation and processing | 300 | 272 | 212 |
Production and other taxes | 64 | 42 | 46 |
Depreciation, depletion and amortization | 467 | 572 | 917 |
General and administrative | 200 | 213 | 244 |
Ceiling test and other impairments | 0 | 1,028 | 4,904 |
Other | 6 | 20 | 10 |
Total operating expenses | 1,252 | 2,391 | 6,618 |
Income (loss) from operations | 515 | (919) | (5,061) |
Nonoperating Income (Expense) [Abstract] | |||
Interest expense | (150) | (154) | (164) |
Capitalized interest | 61 | 51 | 33 |
Commodity derivative income (expense) | (47) | (191) | 259 |
Other, net | 7 | 5 | (14) |
Total other income (expense) | (129) | (289) | 114 |
Income (loss) before income taxes | 386 | (1,208) | (4,947) |
Income Tax Disclosure [Abstract] | |||
Current | (78) | 9 | 17 |
Deferred | 37 | 13 | (1,602) |
Total income tax provision (benefit) | (41) | 22 | (1,585) |
Net income (loss) | $ 427 | $ (1,230) | $ (3,362) |
Earnings Per Share [Abstract] | |||
Basic | $ 2.14 | $ (6.36) | $ (21.18) |
Diluted | $ 2.13 | $ (6.36) | $ (21.18) |
Weighted-average number of shares outstanding for basic earnings (loss) per share | 199 | 193 | 159 |
Weighted-average number of shares outstanding for diluted earnings (loss) per share | 200 | 193 | 159 |
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent | $ 2 | $ 0 | $ (1) |
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | $ 429 | $ (1,230) | $ (3,363) |
Consolidated Statement of Cash
Consolidated Statement of Cash Flows - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Cash flows from operating activities: | |||
Net income (loss) | $ 427 | $ (1,230) | $ (3,362) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Depreciation, depletion and amortization | 467 | 572 | 917 |
Deferred | 37 | 13 | (1,602) |
Stock-based compensation | 34 | 22 | 25 |
Unrealized (gain) loss on derivative contracts | 83 | 392 | 246 |
Ceiling test and other impairments | 0 | 1,028 | 4,904 |
Other, net | 14 | 13 | 43 |
Changes in operating assets and liabilities: | |||
(Increase) decrease in accounts receivable | (60) | 22 | 83 |
Increase (decrease) in accounts payable and accrued liabilities | 27 | (3) | (45) |
Other items, net | (77) | (3) | 0 |
Net cash provided by (used in) operating activities | 952 | 826 | 1,209 |
Cash flows from investing activities: | |||
Additions to oil and gas properties | (1,156) | (868) | (1,607) |
Acquisitions of oil and gas properties | (110) | (486) | (125) |
Proceeds from sales of oil and gas properties | 96 | 405 | 90 |
Additions to other property and equipment | (23) | (17) | (13) |
Proceeds from insurance settlement, net | 0 | 0 | 57 |
Proceeds from Sale, Maturity and Collection of Investments | 50 | 0 | 0 |
Purchases of investments | (25) | (25) | 0 |
Net cash provided by (used in) investing activities | (1,168) | (991) | (1,598) |
Cash flows from financing activities: | |||
Proceeds from borrowings under credit arrangements | 0 | 536 | 1,908 |
Repayments of borrowings under credit arrangements | 0 | (575) | (2,315) |
Proceeds from issuance of senior notes | 0 | 0 | 691 |
Repayment of senior subordinated notes | 0 | 0 | (700) |
Debt issue costs | 0 | 0 | (8) |
Proceeds from issuances of common stock, net | 3 | 779 | 819 |
Purchases of treasury stock, net | (15) | (22) | (12) |
Other | (1) | (3) | (3) |
Net cash provided by (used in) financing activities | (13) | 715 | 380 |
Increase (decrease) in cash and cash equivalents | (229) | 550 | (9) |
Cash and cash equivalents, beginning of period | 555 | 5 | 14 |
Cash and cash equivalents, end of period | $ 326 | $ 555 | $ 5 |
Consolidated Statement of Stock
Consolidated Statement of Stockholders' Equity - USD ($) $ in Millions | Total | Common Stock | Treasury Stock | Additional Paid-in Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) |
Common Stock, Shares, Issued | 137,600,000 | |||||
Common Stock Value | $ 1 | |||||
Treasury Stock, Shares | (300,000) | |||||
Treasury Stock | $ (10) | |||||
Additional paid-in capital | 1,576 | |||||
Retained Earnings (Accumulated Deficit) | 2,327 | |||||
Accumulated other comprehensive income (loss) | (1) | |||||
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest | 3,893 | |||||
Stock Issued During Period, Shares, New Issues | 26,500,000 | |||||
Stock Issued During Period, Value, New Issues | $ 1 | |||||
Stock Issued During Period, Value, Restricted Stock Award, Net of Forfeitures | 819 | $ 818 | ||||
Stock-based compensation | 42 | 42 | ||||
Treasury Stock, Shares, Acquired | (300,000) | |||||
Treasury Stock, Value, Acquired, Cost Method | (12) | $ (12) | 0 | |||
Net income (loss) | (3,362) | $ (3,362) | ||||
Other Comprehensive Income (Loss), Net of Tax | $ (1) | $ (1) | ||||
Common Stock, Shares, Issued | 164,100,000 | |||||
Common Stock Value | $ 2 | |||||
Treasury Stock, Shares | (600,000) | |||||
Treasury Stock | $ (22) | |||||
Additional paid-in capital | 2,436 | |||||
Retained Earnings (Accumulated Deficit) | (1,035) | |||||
Accumulated other comprehensive income (loss) | (2) | |||||
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest | 1,379 | |||||
Stock Issued During Period, Shares, New Issues | 36,100,000 | |||||
Stock Issued During Period, Value, New Issues | $ 0 | |||||
Stock Issued During Period, Value, Restricted Stock Award, Net of Forfeitures | 779 | 779 | ||||
Stock-based compensation | 32 | 32 | ||||
Treasury Stock, Shares, Acquired | (600,000) | |||||
Treasury Stock, Value, Acquired, Cost Method | (22) | $ (22) | 0 | |||
Net income (loss) | (1,230) | $ (1,230) | ||||
Other Comprehensive Income (Loss), Net of Tax | $ 0 | |||||
Common Stock, Shares, Issued | 200,150,392 | |||||
Common Stock Value | $ 2 | |||||
Treasury Stock, Shares | (1,195,809) | |||||
Treasury Stock | $ (44) | |||||
Additional paid-in capital | 3,247 | |||||
Retained Earnings (Accumulated Deficit) | (2,265) | |||||
Accumulated other comprehensive income (loss) | (2) | |||||
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest | 938 | |||||
Stock Issued During Period, Shares, New Issues | 1,200,000 | |||||
Stock Issued During Period, Value, New Issues | $ 0 | |||||
Stock Issued During Period, Value, Restricted Stock Award, Net of Forfeitures | 3 | 3 | ||||
Stock-based compensation | 53 | 53 | ||||
Treasury Stock, Shares, Acquired | (500,000) | |||||
Treasury Stock, Value, Acquired, Cost Method | (15) | $ (15) | $ 0 | |||
Net income (loss) | 427 | |||||
Other Comprehensive Income (Loss), Net of Tax | $ 2 | |||||
Common Stock, Shares, Issued | 201,363,345 | |||||
Common Stock Value | $ 2 | |||||
Treasury Stock, Shares | (1,658,476) | |||||
Treasury Stock | $ (59) | |||||
Additional paid-in capital | 3,303 | |||||
Retained Earnings (Accumulated Deficit) | (1,838) | |||||
Accumulated other comprehensive income (loss) | 0 | |||||
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest | $ 1,408 |
Organization and Summary of Sig
Organization and Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Organization and Summary of Significant Accounting Policies | Organization and Summary of Significant Accounting Policies Organization and Principles of Consolidation We are an independent energy company engaged in the exploration, development and production of crude oil, natural gas and natural gas liquids (NGLs). Our U.S. operations are onshore and focus primarily on large scale, liquids-rich resource plays in the Anadarko and Arkoma basins of Oklahoma, the Williston Basin of North Dakota and the Uinta Basin of Utah. In addition, we have oil assets offshore China. Our consolidated financial statements include the accounts of Newfield Exploration Company, a Delaware corporation, and its subsidiaries. We proportionately consolidate our interests in oil and natural gas exploration and production joint ventures and partnerships in accordance with industry practice. All significant intercompany balances and transactions have been eliminated. Unless otherwise specified or the context otherwise requires, all references in these notes to "Newfield," "we," "us," "our" or the "Company" are to Newfield Exploration Company and its subsidiaries. Risks and Uncertainties As an independent oil and natural gas producer, our revenue, profitability and future rate of growth are substantially dependent on prevailing prices for oil, natural gas and NGLs. Historically, the energy markets have been very volatile, and there can be no assurance that commodity prices will not be subject to wide fluctuations in the future. A substantial or extended decline in commodity prices could have a material adverse effect on our financial position, results of operations, cash flows, access to capital and on the quantities of oil, natural gas and NGL reserves that we can economically produce. Other risks and uncertainties that could affect us in a volatile commodity price environment include, but are not limited to, counterparty credit risk for our receivables, responsibility for decommissioning liabilities for offshore interests we no longer own, inability to access credit markets, regulatory risks and our ability to meet financial ratios and covenants in our financing agreements. Use of Estimates The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America (U.S. GAAP) requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities; disclosure of contingent assets and liabilities at the date of the financial statements; the reported amounts of revenues and expenses during the reporting period; and the quantities and values of proved oil, natural gas and NGL reserves used in calculating depletion and assessing impairment of our oil and gas properties. Actual results could differ significantly from these estimates. Our most significant estimates are associated with the quantities of proved oil, natural gas and NGL reserves, the timing and amount of transfers of our unevaluated properties into our amortizable full cost pool, the recoverability of our deferred tax assets and the fair value of our derivative contracts. Restructuring Costs Restructuring costs include severance and related benefit costs, costs associated with abandoned office space, employee relocation costs and other associated costs. Employee severance and related benefit costs are recognized on a straight-line basis over the required service period, if any. Employee relocation costs are expensed as incurred. On the date a leased property ceases to be used, a liability for non-cancellable office-lease costs associated with restructuring is recognized and measured at fair value on our consolidated balance sheet. Fair value estimates include assumptions regarding estimated future sublease payments. These estimates could materially differ from actual results and may require revision to initial estimates of the liability. See Note 17 , " Restructuring Costs ," for additional disclosures. Revenue Recognition All of our oil, natural gas and NGLs are sold at market-based prices adjusted for location and quality differentials to a variety of purchasers. We record revenue when we deliver our production to the customer and collectability is reasonably assured. Revenues from the production of oil, natural gas and NGLs on properties in which we have joint ownership are recorded under the sales method. Under the sales method, the Company and other joint owners may sell more or less than their entitled share of production. Should the Company’s excess sales exceed our share of estimated remaining recoverable reserves, a liability is recorded. Foreign Currency The functional currency for our China operations is the U.S. dollar. Gains and losses incurred on transactions in a currency other than the U.S. dollar are recorded under the caption "Other income (expense) — Other, net" on our consolidated statement of operations. Cash and Cash Equivalents Cash and cash equivalents include highly liquid investments with a maturity of three months or less when acquired and are stated at cost, which approximates fair value. We invest cash in excess of near-term capital and operating requirements in U.S. Treasury Notes, Eurodollar time deposits and money market funds, which are classified as cash and cash equivalents on our consolidated balance sheet. Restricted Cash Restricted cash consists of amounts held in escrow accounts to satisfy future plug and abandonment obligations for our China operations. These amounts are restricted as to their current use and will be released as we plug and abandon wells and facilities in China. Consistent with our other plug and abandonment activities, changes in restricted cash are included in cash flows from operating activities in our consolidated statement of cash flows. Investments Long-term investments consist of debt and equity securities, a majority of which are classified as "available-for-sale" and stated at fair value. Accordingly, unrealized gains and losses and the related deferred income tax effects are excluded from earnings and reported in other comprehensive income within our consolidated statement of stockholders' equity. The portion of accumulated other comprehensive income within our consolidated statement of stockholders' equity related to investments was $3 million at December 31, 2017 and $1 million at December 31, 2016 and 2015 . Realized gains or losses are computed based on specific identification of the securities sold. We regularly assess our investments for impairment and consider any impairment to be other than temporary if we intend to sell the security, it is more likely than not that we will be required to sell the security, or we do not expect to recover our cost of the security. Allowance for Doubtful Accounts We routinely assess material trade and other receivables to determine their collectability. Many of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of related joint interest billings. Generally, our oil and gas receivables are collected within 45 to 60 days of production. We accrue a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected. Other Current Assets Other current assets primarily consist of federal income tax refunds receivable, capital and lease operating expense prepayments and other prepaid items, including but not limited to, rent and insurance. For the years ended December 31, 2017 and 2016 , federal income tax refunds receivable were $53 million and $24 million , respectively. See Note 8, " Income Taxes ," for further discussion. Inventories Inventories primarily consist of tubular goods and well equipment held for use in our oil and natural gas operations and oil produced but not sold in our China operations. Inventories are carried at the lower of cost or net realizable value. Substantially all of the crude oil from our offshore operations in China is produced into floating storage facilities and sold periodically as barge quantities accumulate. The carrying value of oil inventory is the sum of related production costs and depletion expense. See Note 3 , " Inventories ," for further discussion. Oil and Gas Properties We use the full cost method of accounting for our oil and gas activities. Under this method, all costs incurred in the acquisition, exploration and development of oil and gas properties, including salaries, benefits, interest and other internal costs directly attributable to these activities, are capitalized into country-based cost centers. Proceeds from the sale of oil and gas properties are applied to reduce the costs in the applicable cost center unless the reduction would significantly alter the relationship between capitalized costs and proved reserves, in which case a gain or loss is recognized. Capitalized costs and estimated future development costs are amortized using a unit-of-production method based on proved reserves associated with the applicable cost center. For each cost center, the net capitalized costs of oil and gas properties are limited to the lower of the unamortized cost or the cost center ceiling. A particular cost center ceiling is equal to the sum of: • the present value ( 10% per annum discount rate) of estimated future net revenues from proved reserves using oil, natural gas and NGL reserve estimation requirements, which require use of the unweighted average first-day-of-the-month commodity prices for the prior 12 months (SEC pricing), adjusted for market differentials applicable to our reserves (including the effects of derivative contracts that are designated for hedge accounting, if any); plus • the costs of properties not included in the costs being amortized, if any; less • related income tax effects. If net capitalized costs of oil and gas properties exceed the cost center ceiling, we are subject to a ceiling test impairment to the extent of such excess. If required, a ceiling test impairment reduces earnings and stockholders’ equity in the period of occurrence and, holding other factors constant, results in lower depreciation, depletion and amortization expense in future periods. The risk that we will be required to impair the carrying value of our oil and gas properties increases when oil, natural gas and NGL prices decrease significantly for a prolonged period, or if we have substantial downward revisions in our estimated proved reserves. Costs associated with unevaluated properties are excluded from our full cost pool until we have evaluated the properties or impairment is indicated. The costs associated with unevaluated leasehold acreage, related seismic data and capitalized interest and direct internal costs are initially excluded from our full cost pool. Leasehold costs are either transferred to our full cost pool with the costs of drilling a well on the lease or are assessed at least annually for possible impairment or reduction in value. Leasehold costs are transferred to our full cost pool to the extent a reduction in value has occurred, or a charge is made against earnings if the costs were incurred in a country for which a reserve base has not been established. See Note 6 , " Oil and Gas Properties ," for a detailed discussion regarding our oil and gas property and our asset acquisitions and sales transactions. Other Property and Equipment Furniture, fixtures and equipment are recorded at cost and depreciated using the straight-line method over their estimated useful lives, which range from three to seven years. Gathering systems and equipment are recorded at cost and depreciated using the straight-line method over their estimated useful lives of 25 years. Asset Retirement Obligations If a reasonable estimate of the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells can be made, we record a liability (an asset retirement obligation or ARO) on our consolidated balance sheet and capitalize the present value of the asset retirement cost in oil and gas properties in the period in which the ARO is incurred. Settlements include payments made to satisfy the AROs, as well as transfer of the AROs to purchasers of our divested properties. In general, the amount of the initial recorded ARO and the costs capitalized will equal the estimated future costs to satisfy the abandonment obligation assuming normal operation of the asset, using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, which is then discounted back to the date that the abandonment obligation was incurred using the credit adjusted risk-free rate for our Company. After recording these amounts, the ARO is accreted to its future estimated value and the original capitalized costs are depreciated on a unit-of-production basis within the related full cost pool. Both the accretion and depreciation are included in depreciation, depletion and amortization expense on our consolidated statement of operations. See Note 10 , " Asset Retirement Obligations ," for further discussion. Contingencies We are subject to legal proceedings, claims, liabilities and environmental matters that arise in the ordinary course of business. We accrue for losses when such losses are considered probable and the amounts can be reasonably estimated. See Note 12 , " Commitments and Contingencies ," for a more detailed discussion regarding our contingencies. Environmental Matters Environmental costs that relate to current operations are expensed as incurred. Remediation costs that relate to an existing condition caused by past operations are accrued when it is probable that those costs will be incurred and can be reasonably estimated based upon evaluations of currently available facts related to each site. Income Taxes We use the liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are determined by applying tax regulations existing at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in our financial statements. We assess the available positive and negative evidence to estimate if sufficient taxable income will be generated to utilize deferred tax assets. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. We also evaluate potential uncertain tax positions, and if necessary, establish accruals for such items. See Note 8 , " Income Taxes ," for further discussion. Stock-Based Compensation We apply a fair value-based method of accounting for stock-based compensation, which requires recognition in the financial statements of the cost of services received in exchange for equity and liability awards. For equity awards, compensation expense is based on the fair value on the grant or modification date and is recognized in our financial statements over the applicable service period. The fair value of our service based restricted stock and restricted stock units are based on the Company's stock price on the date of grant. We utilize the Black-Scholes option-pricing model to measure the fair value of stock options and a Monte Carlo lattice-based model for our market-based restricted stock units. We also have cash-settled restricted stock units that are accounted for under the liability method, which requires us to recognize the fair value of each award based on the Company's stock price at the end of each period. See Note 15 , " Stock-Based Compensation ," for a full discussion of our stock-based compensation. Concentration of Credit Risk We operate a substantial portion of our oil and gas properties. As the operator of a property, we make full payment for costs associated with the property and seek reimbursement from the other joint interest owners in the property for their share of those costs. In addition, when warranted, we require prepayments from our joint interest owners for drilling and completion projects. Our joint interest owners consist primarily of independent oil and gas producers whose ability to reimburse us could be negatively impacted by adverse market conditions. The purchasers of our oil, gas and NGL production consist primarily of independent marketers, major oil and gas companies, refiners and gas pipeline companies. We perform credit evaluations of the purchasers of our production and monitor their financial condition on an ongoing basis. Based on our evaluations and monitoring, we obtain cash escrows, letters of credit or parental guarantees from some purchasers. All of our derivative transactions were carried out in the over-the-counter market and are not typically subject to margin-deposit requirements. We monitor the credit ratings of our derivative counterparties on an ongoing basis and have netting arrangements that provide for offsetting payables against receivables by counterparty. Although we have entered into derivative contracts with multiple counterparties to mitigate our exposure to any individual counterparty, if any of our counterparties were to default on its obligations to us under the derivative contracts or seek bankruptcy protection, it could have a material adverse effect on our ability to fund our planned activities and could result in a larger percentage of our future production being subject to commodity price volatility. In addition, in poor economic environments and tight financial markets, the risk of a counterparty default is heightened and fewer counterparties may participate in derivative transactions, which could result in greater concentration of our exposure to any one counterparty or a larger percentage of our future production being subject to commodity price changes. The use of derivative transactions involves the risk that the counterparties, which generally are financial institutions, will be unable to meet the financial terms of such transactions. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty, and we have netting arrangements with all of our counterparties that provide for offsetting payables against receivables by counterparty. At December 31, 2017 , 10 of our 15 counterparties accounted for approximately 82% of our contracted volumes, with the largest counterparty accounting for approximately 12% . At December 31, 2017 , approximately 79% of our volumes subject to derivative instruments are with lenders under our credit facility. Our credit facility, senior notes and substantially all of our derivative instruments contain provisions that provide for cross defaults and acceleration of those debt and derivative instruments in certain situations. Major Customers None of our customers accounted for 10% or more of our total revenues in 2017 . During 2016 , China National Offshore Oil Corporation Ltd. accounted for 12% of our total revenues. During 2015 , China National Offshore Oil Corporation Ltd., MidCon Gathering LLC and Sunoco Logistics Partners Operations GP LLC accounted for 13% , 11% and 10% , respectively, of our total revenues. We believe that the loss of a major customer would not have a material adverse effect on us because alternative purchasers are available. Derivative Financial Instruments Our derivative instruments are recorded on the consolidated balance sheet at fair value as either an asset or a liability with changes in fair value recognized currently in earnings. While we utilize our derivative instruments to manage the price risk attributable to our expected oil, gas and NGL production, we have elected not to designate our derivative instruments as accounting hedges under the accounting guidance. The related cash flow impact of our derivative activities is reflected as cash flows from operating activities unless the derivatives are determined to have a significant financing element at inception, in which case they are classified within financing activities. See Note 4 , " Derivative Financial Instruments ," for a more detailed discussion of our derivative activities. Offsetting Assets and Liabilities Our derivative financial instruments are subject to master netting arrangements and are reflected on our consolidated balance sheet accordingly. See Note 4 , " Derivative Financial Instruments ," for details regarding the gross amounts, as well as the impact of our netting arrangements on our net derivative position. New Accounting Requirements In May 2014, the Financial Accounting Standards Board (FASB) issued guidance regarding the accounting for revenue from contracts with customers. The guidance is effective for interim and annual periods beginning after December 15, 2017 and may be applied retrospectively or using a modified retrospective approach to adjust retained earnings (deficit). We will adopt the guidance in the first quarter of 2018 using the modified retrospective approach to adjust retained earnings (deficit). We have completed the process of evaluating our current revenue recognition policies to the new requirements for each of our revenue categories and have not identified any material differences in the amount and timing of revenue recognition. In November 2016, the FASB issued guidance regarding the classification and presentation of changes in restricted cash on the statement of cash flows. The guidance requires that a statement of cash flows explains the change during the period in the total of cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents using a retrospective approach. The guidance is effective for interim and annual periods beginning after December 15, 2017. Adoption of this standard will impact our cash flow from operations in periods with changes in restricted cash. In January 2016, the FASB issued guidance regarding several broad topics related to the recognition and measurement of financial assets and liabilities. The guidance is effective for interim and annual periods beginning after December 15, 2017. We do not expect this guidance to have a material impact on our financial statements. In February 2016, the FASB issued guidance regarding the accounting for leases. The guidance requires recognition of most leases on the balance sheet. The guidance requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The guidance is effective for interim and annual periods beginning after December 15, 2018. We are currently evaluating the impact of this guidance on our financial statements. |
Accounts Receivable
Accounts Receivable | 12 Months Ended |
Dec. 31, 2017 | |
Accounts Receivable, Net, Current [Abstract] | |
Loans, Notes, Trade and Other Receivables Disclosure [Text Block] | Accounts receivable consisted of the following at December 31: 2017 2016 (In millions) Revenue $ 175 $ 163 Joint interest 108 53 Other 25 32 Reserve for doubtful accounts (16 ) (16 ) Total accounts receivable, net $ 292 $ 232 Reserve for doubtful accounts at December 31, 2017 and 2016 includes an allowance for $15 million related to the sale of our Malaysia operations in 2014. See Note 12, " Commitments and Contingencies " to our consolidated financial statements in Item 8 of this report for additional details regarding our Malaysia litigation. |
Inventories Inventories (Notes)
Inventories Inventories (Notes) | 12 Months Ended |
Dec. 31, 2017 | |
Inventory Disclosure [Abstract] | |
Inventory Disclosure [Text Block] | During 2017 , 2016 and 2015 , we had inventory writedowns of $2 million , $1 million and $5 million , respectively. These writedowns are included in "Operating expenses — Other" on our consolidated statement of operations and comprehensive income. At December 31, 2017 , we had no crude oil inventory in China due to the shut-in of production in our Pearl field and the lifting of remaining barrels in August 2017. At December 31, 2016 , the crude oil inventory from our China operations consisted of approximately 11,500 barrels. |
Derivative Financial Instrument
Derivative Financial Instruments | 12 Months Ended |
Dec. 31, 2017 | |
Derivative Instruments and Hedges, Assets [Abstract] | |
Derivative Financial Instruments Text Block | Derivative Financial Instruments Commodity Derivative Instruments We utilize derivative strategies that consist of either a single derivative instrument or a combination of instruments to manage the variability in cash flows associated with the forecasted sale of our future domestic oil, natural gas, and NGL production. While the use of derivative instruments may limit or partially reduce the downside risk of adverse commodity price movements, their use also may limit future income from favorable commodity price movements. • Fixed-price swaps. With respect to a swap position, the counterparty is required to make a payment to us if the settlement price for any settlement period is less than the swap strike price, and we are required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap strike price. • Fixed-price swaps with sold puts. A swap with a sold put position consists of a standard swap position plus a put sold by us with a strike price below the associated fixed-price swap. This structure enables us to increase the fixed-price swap with the value received through the sale of the put. If the settlement price for any settlement period falls equal to or below the put strike price, then we will only receive the difference between the swap price and the put strike price. If the settlement price is greater than the put strike price, the result is the same as it would have been with a standard swap only. • Swaptions. A swaption is an option to exercise a swap where the buyer (counterparty) of the swaption purchases the right from the seller (Newfield), but not the obligation, to enter into a fixed-price swap with the seller on a predetermined date (expiration date). The swap price is a fixed price determined at the time of the swaption contract. If the swaption is exercised, the contract will become a swap treated consistent with our other fixed-price swaps. • Collars (combination of purchased put options (floor) and sold call options (ceiling)) . For a collar position, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor strike price while we are required to make payment to the counterparty if the settlement price for any settlement period is above the ceiling strike price. Neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor strike price and equal to or less than the ceiling strike price. • Collars with sold puts. A collar with a sold put position consists of a standard collar position plus a put sold by us with a strike price below the floor strike price of the collar. This structure enables us to improve the collar strike prices with the value received through the sale of the additional put. If the settlement price for any settlement period falls equal to or below the additional put strike price, then we will receive the difference between the floor strike price and the additional put strike price. If the settlement price is greater than the additional put strike price, the result is the same as it would have been with a standard collar only. While we do not use derivatives for speculative trading purposes, periodically, we may restructure our derivative positions by purchasing, selling or unwinding certain derivative instruments. The detailed outstanding derivative position tables below represent our net positions after considering the impacts of any applicable restructuring. For discussion of the accounting policies associated with our derivative financial instruments (including the offsetting of derivative assets and liabilities), see Note 1 , " Organization and Summary of Significant Accounting Policies ." Our oil and gas derivative contracts are settled based upon reported prices on the NYMEX, and our NGLs are settled on posted prices at Mont Belvieu. The estimated fair value of these contracts is based upon various factors, including future prices, over-the-counter quotations, estimated volatility, non-performance risk adjustments using counterparty rates of default and time to maturity. The calculation of the fair value of options requires the use of an option-pricing model. See Note 5 , " Fair Value Measurements ." At December 31, 2017 , we had outstanding derivative positions as set forth in the tables below. Crude Oil NYMEX Contract Price Per Bbl Collars Estimated Fair Value Period and Type of Instrument Volume in MBbls Swaps Puts (Weighted Average) Floors Ceilings (In millions) 2018: Swaptions (1) — $ 59.00 $ — $ — $ — $ (1 ) Fixed-price swaps 2,733 51.54 — — — (21 ) Fixed-price swaps with sold puts 644 Fixed-price swaps 56.78 — — — (1 ) Sold puts (2) — 44.00 — — — Collars 2,002 50.59 56.70 (9 ) Collars with sold puts: 14,315 Collars — — 48.42 56.42 (62 ) Sold puts — 39.46 — — (2 ) 2019: Collars with sold puts: 10,566 Collars — — 50.59 57.13 (15 ) Sold puts — 40.60 — — (11 ) Total $ (122 ) _________________ (1) During the fourth quarter of 2017, we sold crude oil swaption contracts that, if exercised on their expiration date in the first quarter of 2018, would protect 273,000 Bbls of second quarter 2018 production from future commodity price volatility. These contracts give the counterparties the option to enter into swap contracts with us at $59.00 /bbl for second quarter 2018. (2) For the fixed-price swaps with sold puts, if the market price remains below our sold puts at contract settlement, we will receive the market price plus the difference between our swaps and our sold puts. Natural Gas Period and Type of Instrument NYMEX Contract Price Per MMBtu Collars Volume in MMMBtus Swaps (Weighted Average) Puts (Weighted Average) Floors (Weighted Average) Ceilings (Weighted Average) Estimated Fair Value Asset (Liability) (In millions) 2018: Fixed-price swaps 42,100 $ 2.99 $ — $ — $ — $ 7 Collars 23,500 — — 3.08 3.61 7 Collars with sold puts 6,420 Collars — — 2.87 3.32 1 Sold puts — 2.30 — — — 2019: Fixed-price swaps 3,650 2.91 — — — Collars 9,000 — 3.00 3.47 1 Total $ 16 Natural Gas Liquids (Propane) Period and Type of Instrument Mont Belvieu Contract Price Per Gallon Volume in MBbls Swaps (Weighted Average) Estimated Fair Value Asset (Liability) (In millions) 2018: Fixed-price swaps 1,184 $ 0.81 $ (2 ) Total $ (2 ) Additional Disclosures about Derivative Financial Instruments We had derivative financial instruments recorded in our consolidated balance sheet as assets (liabilities) at their respective estimated fair value, as set forth below. Derivative Assets Derivative Liabilities Gross Fair Value Offset in Balance Sheet Balance Sheet Location Gross Fair Value Offset in Balance Sheet Balance Sheet Location Current Noncurrent Current Noncurrent December 31, 2017 (In millions) (In millions) Oil positions $ 48 $ (48 ) $ — $ — $ (170 ) $ 48 $ (96 ) $ (26 ) Natural gas positions 22 (6 ) 15 1 (6 ) 6 — — NGL positions — — — — (2 ) — (2 ) — Total $ 70 $ (54 ) $ 15 $ 1 $ (178 ) $ 54 $ (98 ) $ (26 ) December 31, 2016 Oil positions $ 226 $ (151 ) $ 75 $ — $ (197 ) $ 151 $ (46 ) $ — Natural gas positions 10 (10 ) — — (64 ) 10 (51 ) (3 ) NGL positions — — — — — — — — Total $ 236 $ (161 ) $ 75 $ — $ (261 ) $ 161 $ (97 ) $ (3 ) The amount of gain (loss) recognized in "Commodity derivative income (expense)" in our consolidated statement of operations and comprehensive income related to our derivative financial instruments follows: Year Ended December 31, 2017 2016 2015 (In millions) Derivatives not designated as hedging instruments: Realized gain (loss) on oil positions $ 48 $ 199 $ 375 Realized gain (loss) on natural gas positions (12 ) 2 130 Realized gain (loss) on NGL positions — — — Total realized gain (loss) 36 201 505 Unrealized gain (loss) on oil positions (152 ) (316 ) (165 ) Unrealized gain (loss) on natural gas positions 71 (76 ) (81 ) Unrealized gain (loss) on NGL positions (2 ) — — Total unrealized gain (loss) (83 ) (392 ) (246 ) Total $ (47 ) $ (191 ) $ 259 |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements Text Block | Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The authoritative guidance requires disclosure of the framework for measuring fair value and requires that fair value measurements be classified and disclosed in one of the following categories: Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2: Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that we value using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter commodity fixed-price swaps and, as of the third quarter of 2017, commodity options (i.e. price collars, sold puts, purchased calls or swaptions). We use a modified Black-Scholes option pricing valuation model for option and swaption derivative contracts that considers various inputs including: (a) forward prices for commodities, (b) time value, (c) volatility factors, (d) counterparty credit risk and (e) current market and contractual prices for the underlying instruments. Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy. We continue to evaluate our inputs to ensure the fair value level classification is appropriate. When transfers between levels occur, it is our policy to assume that the transfer occurred at the date of the event or change in circumstances that caused the transfer. The determination of the fair values of our derivative contracts incorporates various factors, which include not only the impact of our non-performance risk on our liabilities but also the credit standing of the counterparties involved. We utilize counterparty rate of default values to assess the impact of non-performance risk when evaluating receivables from counterparties and our credit rate when evaluating liabilities. Recurring Fair Value Measurements The following table summarizes the valuation of our assets and liabilities that are measured at fair value on a recurring basis. Fair Value Measurement Classification Quoted Prices in Active Markets for Identical Assets or (Liabilities) (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total (In millions) As of December 31, 2017: Money market fund investments $ 162 $ — $ — $ 162 Deferred compensation plan assets 7 — — 7 Equity securities available-for-sale 12 — — 12 Oil, gas and NGL derivative contracts — (108 ) — (108 ) Stock-based compensation liability awards (7 ) — — (7 ) Total $ 174 $ (108 ) $ — $ 66 As of December 31, 2016: Money market fund investments $ 320 $ — $ — $ 320 Deferred compensation plan assets 6 — — 6 Equity securities available-for-sale 9 — — 9 Oil and gas derivative swap contracts — 50 — 50 Oil and gas derivative option contracts — — (75 ) (75 ) Stock-based compensation liability awards (11 ) — — (11 ) Total $ 324 $ 50 $ (75 ) $ 299 Level 3 Fair Value Measurements The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the indicated periods. Derivatives Stock-Based Compensation Total (In millions) Balance at January 1, 2015 $ (381 ) $ (3 ) $ (384 ) Unrealized gains (losses) included in earnings (217 ) 3 (214 ) Purchases, issuances, sales and settlements: Settlements 290 — 290 Transfers into Level 3 — — — Transfers out of Level 3 — — — Balance at December 31, 2015 $ (308 ) $ — $ (308 ) Change in unrealized gains or losses included in earnings relating to Level 3 instruments still held at December 31, 2015 $ (143 ) $ 3 $ (140 ) Balance at January 1, 2016 $ (308 ) $ — $ (308 ) Unrealized gains (losses) included in earnings (33 ) — (33 ) Purchases, issuances, sales and settlements: Settlements 220 — 220 Transfers into Level 3 — — — Transfers out of Level 3 (1) 46 — 46 Balance at December 31, 2016 $ (75 ) $ — $ (75 ) Change in unrealized gains or losses included in earnings relating to Level 3 instruments still held at December 31, 2016 $ 13 $ — $ 13 Balance at January 1, 2017 $ (75 ) $ — $ (75 ) Unrealized gains (losses) included in earnings (17 ) — (17 ) Purchases, issuances, sales and settlements: Settlements 30 — 30 Transfers into Level 3 — — — Transfers out of Level 3 (2) 62 — 62 Balance at December 31, 2017 $ — $ — $ — Change in unrealized gains or losses included in earnings relating to Level 3 instruments still held at December 31, 2017 $ — $ — $ — _________________ (1) During the second quarter of 2016, we transferred $46 million of derivative option contracts out of the Level 3 category as a result of our Level 3 swaptions being exercised by the counterparties as swaps in June 2016. (2) During the third quarter of 2017, we transferred $62 million of derivative option contracts out of the Level 3 hierarchy into Level 2 hierarchy as a result of our ability to derive volatility inputs from directly observable sources. Fair Value of Debt The estimated fair value of our notes, based on quoted prices in active markets (Level 1) as of December 31, was as follows: 2017 2016 (In millions) 5¾% Senior Notes due 2022 $ 802 $ 789 5⅝% Senior Notes due 2024 1,089 1,044 5⅜% Senior Notes due 2026 739 714 Any amounts outstanding under our revolving credit facility and money market lines of credit as of the indicated dates are stated at cost, which approximates fair value. See Note 11 , " Debt ." |
Oil and Gas Properties
Oil and Gas Properties | 12 Months Ended |
Dec. 31, 2017 | |
Oil and Gas Property [Abstract] | |
Oil and Gas Assets Text Block | Oil and Gas Properties At December 31, oil and gas properties consisted of the following: 2017 2016 (In millions) Proved $ 23,272 $ 21,998 Unproved 1,200 1,238 Gross oil and gas properties 24,472 23,236 Accumulated depreciation, depletion and amortization (10,032 ) (9,587 ) Accumulated impairment (10,509 ) (10,509 ) Net oil and gas properties $ 3,931 $ 3,140 We capitalized approximately $124 million , $121 million and $107 million of interest and direct internal costs in 2017 , 2016 and 2015 , respectively. Costs withheld from amortization as of December 31, 2017 consisted of the following: Costs Incurred In 2017 2016 2015 2014 Total (In millions) Acquisition costs $ 108 $ 483 $ 274 $ 46 $ 911 Exploration costs — — — — — Capitalized internal cost 38 49 32 15 134 Capitalized interest 61 51 33 10 155 Total costs withheld from amortization $ 207 $ 583 $ 339 $ 71 $ 1,200 Ceiling Test Impairments Under the full cost method, we are subject to quarterly calculations of a "ceiling" or limitation on the amount of oil and gas property costs that can be capitalized on our balance sheet. At December 31, 2017 , the ceiling value of our reserves was calculated based upon SEC pricing of $51.34 per barrel for oil and $2.98 per MMBtu for natural gas. Using these prices, our ceiling values exceeded the net capitalized costs of oil and gas properties for the U.S. and China, respectively, and no ceiling test impairment was required in 2017. Future declines in SEC pricing or downward revisions to our estimated proved reserves could result in additional ceiling test impairments of our oil and gas properties in subsequent periods. Ceiling test impairments during 2016 and 2015 consisted of the following: SEC Pricing US Ceiling Test Impairments China Ceiling Test Impairments Total Ceiling Test Impairments Oil Natural Gas Gross Net of Tax (1) Gross Net of Tax (1) Gross Net of Tax (1) (Per Bbl) (Per MMBtu) (In millions) 2016 Quarter Ended: March 31 $ 46.23 $ 2.40 $ 461 $ 461 $ 45 $ 45 $ 506 $ 506 June 30 43.14 2.24 501 501 21 21 522 522 September 30 41.73 2.28 — — — — — — December 31 42.82 2.48 — — — — — — Total 2016 $ 962 $ 962 $ 66 $ 66 $ 1,028 $ 1,028 2015 Quarter Ended: March 31 (2) $ 82.60 $ 3.88 $ 788 $ 496 $ — $ — $ 788 $ 496 June 30 71.56 3.39 1,521 958 — — 1,521 958 September 30 59.09 3.06 1,817 1,193 72 29 1,889 1,222 December 31 50.11 2.59 656 620 46 31 702 651 Total 2015 (2) $ 4,782 $ 3,267 $ 118 $ 60 $ 4,900 $ 3,327 _________________ (1) Starting in the first quarter of 2016, there was no tax impact due to a full valuation allowance on our deferred tax assets. See Note 8 , " Income Taxes ," for additional information regarding the deferred tax asset valuation allowance. (2) Excludes domestic rig impairment of $4 million . Bohai Bay (China) Sales Agreement In May 2017, we closed our previously disclosed sale transaction with certain of our joint venture partners to divest our interest in the Bohai Bay field in China for approximately $32 million , including customary post-close adjustments. Upon completion of our assessment, the sale of our Bohai Bay assets did not significantly alter the relationship between capitalized costs and proved reserves for our China full cost pool and, as such, all proceeds were recorded as adjustments to our China full cost pool with no gain or loss recognized. These consolidated financial statements include the results of our Bohai Bay operations through the date of sale. Texas Asset Sale In September 2016, we closed the sale of substantially all of our oil and gas assets in Texas for approximately $380 million , subject to customary post-close adjustments. The sale of our Texas assets did not significantly alter the relationship between capitalized costs and proved reserves for our U.S. cost pool, and as such, all proceeds were recorded as adjustments to our domestic full cost pool with no gain or loss recognized. These consolidated financial statements include the results of our Texas operations through the date of sale. Anadarko Basin Acquisition In June 2016, we acquired additional properties in the Anadarko Basin STACK play for an adjusted cash purchase price of $476 million , subject to customary post-close adjustments. We also assumed asset retirement obligations of $8 million . We allocated $398 million to unproved properties and wells in progress and $86 million to proved oil and gas properties. Other Asset Acquisitions and Sales During 2017 , 2016 and 2015 , we acquired various other oil and gas properties for approximately $100 million , $7 million and $125 million , respectively, and sold certain other oil and gas properties for proceeds of approximately $72 million , $39 million and $90 million , respectively. The related cash flows and results of operations for these divested assets are included in our consolidated financial statements up to the date of sale. All of the proceeds associated with our asset sales were recorded as adjustments to our domestic full cost pool |
Other Property and Equipment Ot
Other Property and Equipment Other Property and Equipment | 12 Months Ended |
Dec. 31, 2017 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment Disclosure [Text Block] | At December 31, other property and equipment consisted of the following: 2017 2016 (In millions) Furniture, fixtures and equipment $ 165 $ 150 Gathering systems and equipment 115 115 Accumulated depreciation and amortization (112 ) (98 ) Net other property and equipment $ 168 $ 167 During 2017, we sold $11 million of furniture, fixtures and equipment and removed the associated asset and accumulated depreciation accordingly. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Income Taxes Text Block | For the years ended December 31, income (loss) before income taxes consisted of the following: 2017 2016 2015 (In millions) U.S. $ 357 $ (1,181 ) $ (4,865 ) International 29 (27 ) (82 ) Total income (loss) before income taxes $ 386 $ (1,208 ) $ (4,947 ) For the years ended December 31, the total provision (benefit) for income taxes consisted of the following: 2017 2016 2015 (In millions) Current taxes: U.S. federal $ (79 ) $ (13 ) $ (12 ) U.S. state — — (2 ) International 1 22 31 (78 ) 9 17 Deferred taxes: U.S. federal 4 10 (1,507 ) U.S. state 37 13 (27 ) International (4 ) (10 ) (68 ) $ 37 $ 13 $ (1,602 ) Total provision (benefit) for income taxes $ (41 ) $ 22 $ (1,585 ) Taxes for the year were impacted by our ability to monetize $19 million of the alternative minimum tax (AMT) credit carryover on the 2017 U.S federal tax provision by an election to refund AMT credits in lieu of bonus depreciation. The newly enacted Tax Cuts and Jobs Act (the Tax Act) repealed the corporate AMT for tax years beginning January 1, 2018, and provides that any remaining AMT credit carryovers are refundable beginning in 2019. We had approximately $42 million of AMT credit carryovers at the end of 2017 that will be fully refunded between 2019 and 2022. The valuation allowance related to this deferred tax asset was released and a noncurrent receivable was established, which resulted in a tax benefit of $42 million for the year ended December 31, 2017. Also included in the net tax benefit for the year were refunds of $17 million related to the carryback of net operating losses to previously filed U.S. federal returns. The provision for state deferred income taxes on the consolidated statement of operations for the year ended December 31, 2017 was attributable to Oklahoma state deferred tax expense. Other state taxing jurisdictions were in a net deferred tax asset position for which a corresponding valuation allowance was recorded resulting in zero deferred tax benefit for those jurisdictions. Our effective tax rate for 2017 differs from the U.S. statutory rate primarily due to domestic and international deferred tax asset valuation allowances discussed below. The amount for state income taxes in the rate reconciliation table below is the net deferred tax expenses before valuation allowances, if any, generated from all states. This table presents a reconciliation of the United States statutory income tax rate to our effective income tax rate. 2017 2016 2015 U.S. statutory income tax rate 35.0 % 35.0 % 35.0 % State and local income taxes, net of federal effect 6.9 — 0.9 Valuation allowance, domestic (210.1 ) (35.5 ) (4.0 ) Valuation allowance, international (1.2 ) (2.4 ) (0.3 ) Foreign tax on foreign earnings 1.5 0.6 0.4 Impact of Tax Act 157.4 — — Other — 0.5 — Effective income tax rate (10.5 )% (1.8 )% 32.0 % At December 31, 2017 and 2016 respectively, the components of our deferred tax asset (liability) were as follows: 2017 (1) 2016 Deferred tax asset: Net operating loss carryforwards $ 314 $ 301 Alternative Minimum Tax credit — 73 Stock-based compensation 11 15 Oil and gas properties 15 306 Commodity derivatives 19 9 Foreign tax credit — 593 Other 3 13 Total deferred tax asset 362 1,310 Deferred tax asset valuation allowances (362 ) (1,310 ) Net deferred tax asset — — Deferred tax liability: Commodity derivatives — — Oil and gas properties (76 ) (39 ) Total deferred tax liability (76 ) (39 ) Net deferred tax liability $ (76 ) $ (39 ) _________________ (1) The December 31, 2017 deferred tax asset (liability) has been adjusted for the lower federal statutory rate under the Tax Act. At December 31, 2017 we have a net deferred tax liability in Oklahoma of $76 million . All other taxing jurisdictions are in a net deferred tax asset position, for which we recorded an offsetting full valuation allowance, as prescribed by the accounting standards. Beginning January 1, 2018, our U.S. income will be taxed at a 21 percent federal corporate rate under the Tax Act. We were required to recognize the effect of this rate change on our deferred tax assets and liabilities in 2017, the period the tax rate change was enacted. We maintain a full valuation allowance on the net deferred tax asset balance, therefore the rate change resulted in a non-cash decrease to the deferred tax asset and a corresponding and offsetting decrease in the valuation allowance balances of approximately $199 million for the year ended December 31, 2017 . As of December 31, 2017 and 2016 , we had gross net operating loss (NOL) carryforwards of approximately $1.75 billion and $849 million , respectively, for federal income tax and $1.5 billion for state income tax purposes, which may be used in future years to offset taxable income. To the extent not utilized, the federal NOL carryforwards will begin to expire during the years 2019 through 2037. As of December 31, 2017 and 2016 , we had foreign tax credits of approximately $0 million and $593 million , respectively, which would have expired during the years 2022 through 2026. During 2017, we filed amended returns to deduct $185 million of the foreign taxes paid, thereby converting the credit to a net operating loss carryforward. We are unable to utilize the remaining $408 million under the Tax Act and therefore, removed the deferred tax asset and the corresponding valuation allowance. Utilization of deferred tax assets is dependent upon generating sufficient future taxable income in the appropriate jurisdictions within the carryforward period. Estimates of future taxable income can be significantly affected by changes in oil, gas and NGL prices; estimates of the timing and amount of future production; and estimates of future operating and capital costs. Therefore, no certainty exists that we will be able to fully utilize our existing deferred tax assets. The change in our deferred tax asset valuation allowance is as follows at December 31: 2017 2016 2015 (In millions) Balance at the beginning of the year $ (1,310 ) $ (790 ) $ (549 ) Charged to provision for income taxes: U.S. state net operating loss carryforwards 7 (4 ) (1 ) U.S. federal and state valuation allowance 343 (466 ) (202 ) Foreign tax credit valuation allowance 593 (21 ) (25 ) China valuation allowance 5 (29 ) (13 ) Balance at the end of the year $ (362 ) $ (1,310 ) $ (790 ) Due to the ceiling test impairments of our oil and gas properties in prior periods, we moved from a deferred tax liability position to a deferred tax asset position in most taxing jurisdictions. We consider it more likely than not that the related tax benefits will not be realized and therefore, we recorded a full valuation allowance on our deferred tax assets of $362 million and $1.3 billion for the years ended December 31, 2017 and 2016 , respectively. The net change in the U.S. federal and state valuation allowance for 2017 of $343 million included a decrease of $199 million for the corporate tax rate reduction under the Tax Act. The net change in the U.S. federal and state valuation allowance for 2016 of $466 million included an increase of $37 million for the early adoption of the simplification of employee share-based payment transactions. The net change in the foreign tax credit valuation allowance for 2017 of $593 million included a decrease of $185 million for the conversion of the credit to a net operating loss and a decrease of $408 million for the permanent loss of the foreign tax credit under the Tax Act. We recorded a full valuation allowance on our China deferred tax assets of $37 million and $42 million for the years ended December 31, 2017 and 2016 , respectively. As of December 31, 2017 , we did not have a liability for uncertain tax positions, and as such, we did not accrue related interest or penalties. The tax years 2013 through 2016 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which we are subject. |
Accrued Liabilities
Accrued Liabilities | 12 Months Ended |
Dec. 31, 2017 | |
Accrued Liabilities, Current [Abstract] | |
Accounts Payable and Accrued Liabilities Disclosure [Text Block] | Accrued liabilities consisted of the following at December 31: 2017 2016 (In millions) Revenue payable $ 239 $ 196 Accrued capital costs 173 92 Accrued lease operating expenses 22 37 Employee incentive expense 44 48 Accrued interest on debt 67 67 Taxes payable 11 15 Other 35 43 Total accrued liabilities $ 591 $ 498 |
Asset Retirement Obligations (N
Asset Retirement Obligations (Notes) | 12 Months Ended |
Dec. 31, 2017 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligation Disclosure [Text Block] | Asset Retirement Obligations The change in our ARO for each of the three years ended December 31, is set forth below: 2017 2016 2015 (In millions) Balance at January 1 $ 156 $ 194 $ 186 Accretion expense 9 10 10 Additions (1) 3 15 6 Revisions (2) (25 ) (23 ) (2 ) Settlements (3) (10 ) (40 ) (6 ) Balance at December 31 133 156 194 Less: Current portion of ARO at December 31 (3 ) (2 ) (2 ) Total long-term ARO at December 31 $ 130 $ 154 $ 192 _________________ (1) For the year ended December 31, 2016 , additions include $8 million of abandonment obligations assumed through our Anadarko Basin acquisition. (2) Revisions are primarily due to changes in cost estimates and timing of expected abandonment. (3) For the year ended December 31, 2017 , settlements include $7 million related to the sale of our interest in the Bohai Bay field in China. For the year ended December 31, 2016 , settlements include $35 million related to the sale of our Texas assets. See Note 6 , " Oil and Gas Properties ." |
Debt
Debt | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Debt Text Block | Debt At December 31, our debt consisted of the following: 2017 2016 (In millions) Senior unsecured debt: 5¾% Senior Notes due 2022 $ 750 $ 750 5⅝% Senior Notes due 2024 1,000 1,000 5⅜% Senior Notes due 2026 700 700 Total senior unsecured debt 2,450 2,450 Debt issuance costs (16 ) (19 ) Total long-term debt $ 2,434 $ 2,431 Credit Arrangements As of December 31, 2017 , we had no borrowings under our money market lines of credit or revolving credit facility and had no letters of credit outstanding. We have a revolving credit facility that matures in June 2020 and provides borrowing capacity of $1.8 billion . As of December 31, 2017 , the largest individual loan commitment by any lender was 12% of total commitments. Subject to compliance with restrictive covenants in our credit facility, our available borrowing capacity (before any amounts drawn) under our money market lines of credit with various institutions, the availability of which is at the discretion of those financial institutions, was $125 million at December 31, 2017 . Loans under the credit facility bear interest, at our option, equal to (a) the Alternate Base Rate (as defined in the Credit Agreement), plus a margin that is based on a grid of our debt rating (100 basis points per annum at December 31, 2017 ) or (b) the Adjusted Eurodollar Rate (as defined in the Credit Agreement), plus a margin that is based on a grid of our debt rating (200 basis points per annum at December 31, 2017 ). Under our credit facility, we pay commitment fees on available but undrawn amounts based on a grid of our debt rating (37.5 basis points per annum at December 31, 2017 ). We incurred aggregate commitment fees under our credit facility of approximately $7 million , $7 million and $5 million for each of the years ended December 31, 2017 , 2016 and 2015 , respectively, which were recorded in “Interest expense” on our consolidated statement of operations and comprehensive income. We incurred approximately $3 million of financing costs related to amending our revolving credit facility in March 2016, which were also included in "Interest expense" on our consolidated statement of operations and comprehensive income. Our credit facility has restrictive financial covenants that include the maintenance of a ratio of total debt to book capitalization not to exceed 0.6 to 1.0 and the maintenance of a ratio of earnings before gain or loss on the disposition of assets, interest expense, income taxes and certain non-cash items (such as depreciation, depletion and amortization expense, unrealized gains and losses on commodity derivatives and ceiling test impairments) to interest expense of at least 2.5 to 1.0. At December 31, 2017 , we were in compliance with all of our debt covenants. Letters of credit are subject to a fronting fee of 20 basis points and annual fees based on a grid of our debt rating (200 basis points at December 31, 2017 ). The credit facility includes events of default relating to customary matters, including, among other things, nonpayment of principal, interest or other amounts; violation of covenants; inaccuracy of representations and warranties in any material respect when made; a change of control; or certain other material adverse changes in our business. Our senior notes also contain standard events of default. If any of the foregoing defaults were to occur, our lenders under the credit facility could terminate future lending commitments, and our lenders under both the credit facility and our notes could declare the outstanding borrowings due and payable. In addition, our credit facility, senior notes and substantially all of our derivative arrangements contain provisions that provide for cross defaults and acceleration of those debt and derivative instruments in certain situations. See Note 1 , " Organization and Summary of Significant Accounting Policies – Concentration of Credit Risk ," for additional details. Senior Subordinated Notes Interest on our senior notes is payable semi-annually. The notes are unsecured and unsubordinated obligations and rank equally with all of our other existing and future unsecured and unsubordinated obligations. We may redeem some or all of our senior notes at any time before their maturity at a redemption price based on a make-whole amount plus accrued and unpaid interest to the date of redemption. The indentures governing our senior notes contain covenants that may limit our ability to, among other things, incur debt secured by liens; enter into sale/leaseback transactions; and enter into merger or consolidation transactions. The indentures also provide that if any of our subsidiaries guarantee any of our indebtedness at any time in the future, then we will cause our senior notes to be equally and ratably guaranteed by that subsidiary. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies Text Block | Commitments and Contingencies We have various commitments for firm transportation, operating lease agreements for office space and other agreements. As of December 31, 2017 , future minimum payments under these non-cancelable agreements are as follows: Firm Transportation Operating Leases (Office Space) Drilling-Related Other Total (In millions) Year Ending December 31, 2018 $ 79 $ 25 $ 25 $ 18 $ 147 2019 78 23 — 14 115 2020 31 21 — 7 59 2021 21 22 — 3 46 2022 21 4 — 2 27 Thereafter 106 — — 17 123 Total minimum future payments $ 336 $ 95 $ 25 $ 61 $ 517 Firm transportation is comprised of various agreements with third parties for oil and gas gathering and transportation. Rent expense with respect to our lease commitments for office space for the years ended December 31, 2017 , 2016 and 2015 was $16 million , $21 million and $35 million , respectively. Our other agreements are primarily other equipment leases. Payments under our drilling-related contracts are accounted for as capital additions to our oil and gas properties and will be less than the gross obligation disclosed in wells in which we do not own a 100% working interest. Not included in the table above are crude oil minimum volume delivery commitments that relate to our Uinta Basin production with two Salt Lake City, Utah refiners. One delivery commitment is for approximately 15,000 barrels of oil per day through May 2020. The second commitment is for 16,000 barrels of oil per day through August 2025. As of December 31, 2017 , our delivery commitments through 2025 were as follows: Oil Year Ending December 31, (MBbls) 2018 12,220 2019 11,315 2020 8,136 2021 5,840 2022 5,840 Thereafter 15,600 Total delivery commitments 58,951 Given the volatility in oil and natural gas prices and the related impact on our 2018 planned capital investments, as well as the potential impact on development plans in future years, we could fail to deliver the minimum production required under these commitments. In the event that we are unable to meet our crude oil volume delivery commitments, we would incur deficiency fees ranging from $3.50 to $6.50 per barrel. During 2017 , 2016 and 2015 , we incurred $29 million , $16 million , and $0 million , of Uinta Basin deficiency fees. Litigation On October 19, 2017, we received notice of a request for arbitration from SapuraKencana Petroleum Berhad (SapuraKencana), the purchaser of our Malaysian business in February 2014. SapuraKencana is asserting that the Company owes approximately $89 million in damages for breach of contract and for a tax indemnity, plus interest and legal and other costs. We filed our response to the request for arbitration in December 2017. We continue to be committed to fully contesting the claims and intend to vigorously defend the Company's interest. In May 2015, a lawsuit was filed against the Company alleging certain plugging and abandonment predecessor-in-interest liabilities related to offshore assets sold by the Company in 2010. The Company responded to the petition, denied the allegations and vigorously defended the case. The court held that the Company must bear a "portion" of the plugging and abandonment costs, but the "exact percentage" of such costs should be determined in arbitration and stayed the case pending arbitration. Through settlement negotiations surrounding the arbitration proceeding, the Company and the plaintiff reached a mutual settlement on September 23, 2016 involving a cash payment by the Company totaling $18 million . The settlement was recorded under the caption "Operating expenses — Other" on our consolidated statement of operations. On October 3, 2016, the court dismissed the case with prejudice. We have been named as a defendant in a number of lawsuits and are involved in various other disputes, all arising in the ordinary course of our business, such as (a) claims from royalty owners for disputed royalty payments, (b) commercial disputes, (c) personal injury claims and (d) property damage claims. Although the outcome of these lawsuits and disputes cannot be predicted with certainty, we do not expect these matters to have a material adverse effect on our financial position, cash flows or results of operations. |
Stockholders' Equity Activity (
Stockholders' Equity Activity (Notes) | 12 Months Ended |
Dec. 31, 2017 | |
Equity [Abstract] | |
Stockholders' Equity Note Disclosure [Text Block] | Common Stock During the first quarter of 2016, we issued 34.5 million additional shares of common stock through a public equity offering for net proceeds of approximately $776 million . A portion of the proceeds was used to acquire additional properties in the Anadarko Basin STACK play and to repay borrowings under our credit facility and money market lines of credit. The remainder was available for general corporate purposes. During the first quarter of 2015, we issued 25.3 million additional shares of common stock through a public equity offering. We received net proceeds of approximately $815 million , which were used primarily to repay all borrowings under our credit facility and money market lines of credit that were outstanding at that time. Treasury Stock Upon vesting of employee restricted stock awards and restricted stock units, we typically repurchase a portion of the vested shares for payment of employee tax withholding. Such repurchases are not part of a publicly announced program to repurchase shares of our common stock. |
Earnings Per Share
Earnings Per Share | 12 Months Ended |
Dec. 31, 2017 | |
Earnings Per Share [Abstract] | |
Earnings Per Share Text Block | Basic earnings per share (EPS) is calculated by dividing net income less any applicable adjustments (the numerator) by the weighted-average number of shares of common stock (excluding unvested restricted stock and restricted stock units) outstanding during the period (the denominator). Diluted EPS incorporates the dilutive impact of outstanding stock options and unvested restricted stock and restricted stock units (using the treasury stock method). Under the treasury stock method, the amount the employee must pay for exercising stock options, the amount of unrecognized compensation expense related to unvested restricted stock awards and restricted stock units and the amount of excess tax benefits that would be recorded when the award becomes deductible are assumed to be used to repurchase shares. See Note 15 , " Stock-Based Compensation ." The following is the calculation of basic and diluted weighted-average shares outstanding and EPS for the indicated years. 2017 2016 2015 (In millions, except per share data) Net income (loss) $ 427 $ (1,230 ) $ (3,362 ) Weighted-average shares (denominator): Weighted-average shares — basic 199 193 159 Dilution effect of stock options and unvested restricted stock and restricted stock units outstanding at end of period 1 — — Weighted-average shares — diluted 200 193 159 Excluded due to anti-dilutive effect 1 2 3 Earnings (loss) per share: Basic $ 2.14 $ (6.36 ) $ (21.18 ) Diluted $ 2.13 $ (6.36 ) $ (21.18 ) |
Stock-Based Compensation
Stock-Based Compensation | 12 Months Ended |
Dec. 31, 2017 | |
Share-based Compensation [Abstract] | |
Stock-Based Compensation Text Block | For the years ended December 31, our stock-based compensation expense consisted of the following: 2017 2016 2015 (In millions) Equity awards $ 53 $ 32 $ 42 Liability awards 5 21 12 Total stock-based compensation expense 58 53 54 Capitalized in oil and gas properties (17 ) (17 ) (18 ) Net stock-based compensation expense $ 41 $ 36 $ 36 As of December 31, 2017 , we had approximately $54 million of total unrecognized stock-based compensation expense related to unvested stock-based compensation awards that vest within four years . On December 31, 2017 , the last reported sales price of our common stock on the New York Stock Exchange was $31.53 per share. During the first quarter of 2017 , we changed our qualified retirement requirements for existing market-based restricted stock units and all subsequently issued equity and liability awards. An employee becomes eligible for qualified retirement based on a combination of years of service and age. Under the revised requirements, qualified retirement allows an employee to continue vesting between 50% and 100% of awards with no additional service requirement beyond a six-month notification period. This change resulted in the accelerated recognition of stock-based compensation expense for unvested market-based restricted stock units previously issued and all subsequently issued equity and liability awards. Equity Awards Equity awards consist of service-based and market-based restricted stock and restricted stock units, stock options and stock purchase options under the Employee Stock Purchase Plan (ESPP). In May 2017, Newfield adopted the 2017 Omnibus Incentive Plan, as amended (2017 Plan), which replaced the 2011 Omnibus Stock Plan as the vehicle for granting equity-based compensation awards. The fair value of grants is determined utilizing the Black-Scholes option-pricing model for stock options and a Monte Carlo lattice-based model for our market-based restricted stock and restricted stock units. Compensation expense for equity awards is expected to be recognized on a straight-line basis over the required service periods. Shares available for grant under our 2017 Plan are reduced by 1.67 times the number of shares of restricted stock or restricted stock units awarded under the plan and are reduced by 1 times the number of shares subject to stock options awarded under the plan. At December 31, 2017, we had approximately (1) 9.5 million shares available for issuance under our 2017 Plan if all future awards are stock options, or (2) 5.7 million shares available for issuance under our 2017 Plan if all future awards are restricted stock or restricted stock units. Thus far, all awards under our 2017 Plan have been granted as restricted stock or restricted stock units. We issue common shares on the grant date for restricted stock and on the exercise or vesting date for options and restricted stock units. Restricted Stock and Restricted Stock Units. At December 31, 2017 , approximately 2.0 million shares of non-vested restricted stock awards and restricted stock units were outstanding. These shares primarily vest over one to four years and vesting is dependent upon the recipient meeting applicable service requirements. In addition, at December 31, 2017 , our employees held approximately 0.7 million shares of restricted stock units subject to performance-based vesting criteria (all of which are currently considered market-based restricted stock under authoritative accounting guidance). The following table summarizes the activity for our restricted stock and restricted stock unit activity. Service-Based Shares Weighted- Average Grant Date Fair Value per Share Market-Based Shares Weighted- Average Grant Date Fair Value per Share Total Shares (In thousands, except per share data) Non-vested shares outstanding at January 1, 2015 1,902 $ 30.79 945 $ 28.61 2,847 Granted 1,036 31.20 414 22.85 1,450 Forfeited (367 ) 21.69 (97 ) 36.72 (464 ) Vested (871 ) 32.10 (188 ) 39.42 (1,059 ) Non-vested shares outstanding at December 31, 2015 1,700 30.30 1,074 23.76 2,774 Granted 990 37.95 436 (1) 28.94 1,426 Forfeited (217 ) 29.15 (77 ) 43.04 (294 ) Vested (899 ) 29.34 (574 ) 21.36 (1,473 ) Non-vested shares outstanding at December 31, 2016 1,574 35.56 859 26.28 2,433 Granted 1,244 29.81 323 (2) 39.57 1,567 Forfeited (91 ) 34.43 (55 ) 37.14 (146 ) Vested (694 ) 34.67 (386 ) 29.43 (1,080 ) Non-vested shares outstanding at December 31, 2017 2,033 $ 32.41 741 $ 30.65 2,774 _________________ (1) In February 2016, we granted approximately 436,000 restricted stock units, which based on achievement of certain criteria, could vest within a range of 0% to 200% of shares granted upon completion of the period ending December 31, 2018. (2) In February 2017, we granted approximately 323,000 restricted stock units, which based on achievement of certain criteria, could vest within a range of 0% to 200% of shares granted upon completion of the period ending December 31, 2019. The total fair value of all restricted stock and restricted stock units that vested during the years ended December 31, 2017 , 2016 and 2015 was $35 million , $39 million and $35 million , respectively. Stock Options. Options generally expire ten years from the grant date and become exercisable at the rate of 20% per year. The exercise price of options cannot be less than the fair market value per share of our common stock on the grant date. We issue new shares of stock when stock options are exercised. No stock options have been granted since 2008, except for ESPP options as discussed in the Employee Stock Purchase Plan section below. The following table provides information about outstanding stock options. Number of Shares Underlying Options Weighted-Average Exercise Price per Share Weighted-Average Remaining Contractual Life Aggregate Intrinsic Value (1) (In thousands) (In years) (In millions) Outstanding and exercisable at: December 31, 2015 195 $ 48.45 2.1 $ — December 31, 2016 177 48.45 1.1 — December 31, 2017 155 48.45 0.1 — _________________ (1) The intrinsic value of a stock option is the amount by which the market value of our common stock at the indicated date, or at the time of exercise, exceeds the exercise price of the option. Employee Stock Purchase Plan . In May 2010, our stockholders approved the Newfield Exploration Company 2010 Employee Stock Purchase Plan with one million shares of our common stock available for issuance. In May 2017, our stockholders approved the amended and restated ESPP, increasing the number of our common stock available for issuance by an additional two million shares. Pursuant to our employee stock purchase plan, for each six-month period beginning on January 1 or July 1 during the plan term, each eligible employee has the opportunity to purchase our common stock for a purchase price equal to 85% of the lesser of the fair market value of our common stock on the first or last day of the period. Each employee may purchase up to $25,000 in common stock per calendar year. Employees of our China business are not eligible to participate in the plan. At December 31, 2017 , approximately two million shares of our common stock remained available for issuance under the current plan. The fair value of the options granted was determined using the Black-Scholes option valuation method assuming no dividends and an expected life of six months. For the years ended December 31, our ESPP issuances and valuation assumptions consisted of the following: Options Issued Weighted-Average Fair Value per Share Risk-free Interest Rate Weighted-Average Volatility (In thousands) 2015 136 $ 8.71 0.12 % 49.41 % 2016 99 10.51 0.43 47.94 2017 124 9.03 0.87 39.13 Liability Awards Liability awards consist of service-based awards that are settled in cash instead of shares, as discussed below. Cash-Settled Restricted Stock Units. The value of the cash-settled restricted stock units, and the associated stock-based compensation expense, is based on the Company's stock price at the end of each period. As of December 31, 2017 , we had a liability of $7 million related to these awards. The following table provides information about cash-settled restricted stock unit activity. Cash-Settled Restricted Stock Units (In thousands) Non-vested units outstanding at January 1, 2015 1,216 Granted 211 Forfeited (257 ) Vested (462 ) Non-vested units outstanding at December 31, 2015 708 Granted 299 Forfeited (101 ) Vested (446 ) Non-vested units outstanding at December 31, 2016 460 Granted 241 Forfeited (32 ) Vested (318 ) Non-vested units outstanding at December 31, 2017 351 |
Employee Benefit Plans
Employee Benefit Plans | 12 Months Ended |
Dec. 31, 2017 | |
Defined Contribution Plan [Abstract] | |
Compensation and Employee Benefit Plans [Text Block] | Post-Retirement Medical Plan We sponsor a post-retirement medical plan that covers all eligible retired employees until they reach age 65 . An employee may become eligible upon reaching age 55 and providing 5 years of service. At December 31, 2017 , both our accumulated benefit obligation and our accrued benefit costs were $22 million . Our net periodic benefit cost was approximately $3 million for each of the years ended December 31, 2017 , 2016 and 2015 . The expected future benefit payments under our post-retirement medical plan for the next ten years include $8 million for the five-year period 2018 through 2022 and $10 million for the five-year period 2023 through 2027. Annual Cash Incentive Compensation Plan During 2010, our Board of Directors, with the recommendation of the Compensation & Management Development Committee, approved a new annual cash incentive compensation plan for all employees (the 2011 Annual Incentive Plan). Under the 2011 Annual Incentive Plan, the Compensation & Management Development Committee determines the annual award pool for all employees based upon a number of factors including the Company’s performance against stated performance goals and in comparison with peer companies in our industry. All employees are eligible if employed on October 1 and December 31 of the performance period. Beginning with the year ended December 31, 2010, our annual cash incentive compensation is paid in a single payment to employees during the first quarter after the performance period ends. Total incentive compensation expense under the 2011 Annual Incentive Plan for the years ended December 31, 2017 , 2016 and 2015 was $31 million , $35 million and $41 million , respectively. 401(k) and Deferred Compensation Plans We sponsor a 401(k) profit sharing plan under Section 401(k) of the Internal Revenue Code. This plan covers all of our employees, excluding those of our foreign subsidiaries. We match $1.00 for each $1.00 of employee deferral, with our contribution not to exceed 8% of an employee’s salary, subject to limitations imposed by the IRS. We also sponsor a highly compensated employee deferred compensation plan. This non-qualified plan allows an eligible employee to defer a portion of his or her salary or bonus on an annual basis. We match $1.00 for each $1.00 of employee deferral, with our contribution not to exceed 8% of an employee’s salary, subject to limitations imposed by the plan. Our contribution with respect to each participant in the deferred compensation plan is reduced by the amount of contribution made by us to our 401(k) plan for that participant. Our combined contributions to these two plans were $6 million for each of the years ended December 31, 2017 and 2016 , and $7 million for the year ended December 31, 2015 . |
Restructuring Costs Restructuri
Restructuring Costs Restructuring Costs | 12 Months Ended |
Dec. 31, 2017 | |
Restructuring and Related Activities [Abstract] | |
Restructuring and Related Activities Disclosure [Text Block] | Restructuring Costs Restructuring costs include severance and related benefit costs, costs associated with abandoned office space, employee relocation costs and other associated costs. Employee severance and related benefit costs are recognized on a straight-line basis over the required service period, if any. Employee relocation costs are expensed as incurred. On the date a leased property ceases to be used, a liability for non-cancellable office-lease costs associated with restructuring is recognized and measured at fair value on our consolidated balance sheet. Fair value estimates include assumptions regarding estimated future sublease payments. These estimates could materially differ from actual results and may require revision to initial estimates of the liability. See Note 17 , " Restructuring Costs ," for additional disclosures. Restructuring Costs In April 2015 and May 2016, we announced plans to consolidate and reorganize domestic operating functions to our headquarters in The Woodlands, Texas, which resulted in a reduction of employees and closure of our offices in Denver, Colorado; North Houston (Greenspoint), Texas; and Tulsa, Oklahoma. Our decision to restructure the organization was primarily in response to the oil and gas commodity price environment. Substantially all restructuring-related costs have been recognized as expense as of December 31, 2016. Restructuring costs recorded in our consolidated statement of operations for the years ended December 31 are set forth below. Type of Restructuring Cost Location in the Consolidated Statement of Operations 2017 2016 2015 (In millions) Severance and related benefit costs Operating expenses - General and administrative $ — $ 17 $ 7 Relocation costs Operating expenses - General and administrative 2 5 5 Office-lease abandonment costs Operating expenses - General and administrative — 6 14 Other associated costs Operating expenses - Depreciation, depletion and amortization — — 1 Total $ 2 $ 28 $ 27 The following table summarizes our restructuring costs and related liability. Severance and Related Benefit Costs Office-lease Abandonment Costs (1) Relocation Costs Other Associated Costs Total (In millions) Restructuring liability at January 1, 2015 $ — $ — $ — $ — $ — Additions 7 14 5 1 27 Settlements (6 ) (1 ) (5 ) (1 ) (13 ) Revisions — — — — — Restructuring liability at December 31, 2015 $ 1 $ 13 $ — $ — $ 14 Cumulative costs as of December 31, 2015 $ 7 $ 14 $ 5 $ 1 $ 27 Restructuring liability at January 1, 2016 $ 1 $ 13 $ — $ — $ 14 Additions 17 3 5 — 25 Settlements (17 ) (5 ) (5 ) — (27 ) Revisions — 3 — — 3 Restructuring liability at December 31, 2016 $ 1 $ 14 $ — $ — $ 15 Cumulative costs as of December 31, 2016 $ 24 $ 20 $ 10 $ 1 $ 55 Restructuring liability at January 1, 2017 $ 1 $ 14 $ — $ — $ 15 Additions — — 2 — 2 Settlements (1 ) (6 ) (2 ) — (9 ) Revisions — — — — — Restructuring liability at December 31, 2017 $ — $ 8 $ — $ — $ 8 Cumulative costs as of December 31, 2017 $ 24 $ 20 $ 12 $ 1 $ 57 Expected total costs $ 24 $ 20 $ 12 $ 1 $ 57 _________________ (1) The office-lease abandonment liability will be relieved as lease payments are made and sublease income is received over the life of the lease ending 2022. |
Segment Information
Segment Information | 12 Months Ended |
Dec. 31, 2017 | |
Segment Reporting [Abstract] | |
Segment Reporting Disclosure [Text Block] | Segment Information While we only have operations in the oil and gas exploration and production industry, we are organizationally structured along geographic operating segments. Our current operating segments are the United States and China. The accounting policies of our operating segments are the same as those described in Note 1 , " Organization and Summary of Significant Accounting Policies ." The following tables provide the geographic operating segment information for the years ended December 31, 2017 , 2016 and 2015 . Domestic China Total (In millions) Year Ended December 31, 2017: Oil, gas and NGL revenues $ 1,679 $ 86 $ 1,765 Lease operating 188 27 215 Transportation and processing 300 — 300 Production and other taxes 64 — 64 Depreciation, depletion and amortization 443 24 467 Results of operations for oil and gas producing activities before tax 684 35 719 Other revenues 2 — 2 General and administrative 194 6 200 Other 5 1 6 Allocated income tax (benefit) (1) 180 17 Net income (loss) from oil and gas properties $ 307 $ 11 Total revenues 1,767 Total operating expenses 1,252 Income (loss) from operations 515 Interest expense, net of interest income, capitalized interest and other (82 ) Commodity derivative income (expense) (47 ) Income (loss) from operations before income taxes $ 386 Total assets $ 4,875 $ 86 $ 4,961 Additions to long-lived assets $ 1,288 $ 1 $ 1,289 _________________ (1) Allocated income tax based on estimated combined federal and state statutory tax rates in effect during the period, comprised of 37% for domestic and 60% for China. Domestic China Total (In millions) Year Ended December 31, 2016: Oil, gas and NGL revenues $ 1,251 $ 217 $ 1,468 Lease operating 189 55 244 Transportation and processing 272 — 272 Production and other taxes 41 1 42 Depreciation, depletion and amortization 458 114 572 Ceiling test and other impairments 962 66 1,028 Results of operations for oil and gas producing activities before tax (671 ) (19 ) (690 ) Other revenues 4 — 4 General and administrative 205 8 213 Other 20 — 20 Allocated income tax (benefit) (1) (330 ) (16 ) Net income (loss) from oil and gas properties $ (562 ) $ (11 ) Total revenues 1,472 Total operating expenses 2,391 Income (loss) from operations (919 ) Interest expense, net of interest income, capitalized interest and other (98 ) Commodity derivative income (expense) (191 ) Income (loss) from operations before income taxes $ (1,208 ) Total assets $ 4,166 $ 146 $ 4,312 Additions to long-lived assets $ 1,369 $ 2 $ 1,371 _________________ (1) Allocated income tax based on estimated combined federal and state statutory tax rates in effect during the period, comprised of 37% for domestic and 60% for China. Domestic China Total (In millions) Year Ended December 31, 2015: Oil, gas and NGL revenues $ 1,288 $ 262 $ 1,550 Lease operating 231 54 285 Transportation and processing 212 — 212 Production and other taxes 45 1 46 Depreciation, depletion and amortization 754 163 917 Ceiling test and other impairments 4,786 118 4,904 Results of operations for oil and gas producing activities before tax (4,740 ) (74 ) (4,814 ) Other revenues 7 — 7 General and administrative 237 7 244 Other 9 1 10 Allocated income tax (benefit) (1) (1,842 ) (49 ) Net income (loss) from oil and gas properties $ (3,137 ) $ (33 ) Total revenues 1,557 Total operating expenses 6,618 Income (loss) from operations (5,061 ) Interest expense, net of interest income, capitalized interest and other (145 ) Commodity derivative income (expense) 259 Income (loss) from operations before income taxes $ (4,947 ) Total assets $ 4,452 $ 316 $ 4,768 Additions to long-lived assets $ 1,645 $ 100 $ 1,745 _________________ (1) Allocated income tax based on estimated combined federal and state statutory tax rates in effect during the period, comprised of 37% % for domestic and 60% for China. |
Supplemental Cash Flows Informa
Supplemental Cash Flows Information | 12 Months Ended |
Dec. 31, 2017 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Cash Flows Information Text Block | The following table presents information about supplemental cash flows for each of the three years ended December 31: 2017 2016 2015 (In millions) Cash Payments: Interest payments $ 84 $ 97 $ 119 Income tax payments (refunds) (2 ) 17 25 Non-cash investing and financing activities excluded from the statement of cash flows: (Increase) decrease in receivables for property sales $ — $ 6 $ 6 (Increase) decrease in accrued capital expenditures (81 ) 33 225 (Increase) decrease in asset retirement costs 31 46 (4 ) |
Quarterly Results of Operations
Quarterly Results of Operations | 12 Months Ended |
Dec. 31, 2017 | |
Quarterly Financial Information Disclosure [Abstract] | |
Quarterly Financial Information Text Block | The results of operations by quarter for the indicated periods are as follows: 2017 Quarter Ended March 31 June 30 September 30 December 31 (In millions, except per share data) Oil, gas and NGL revenues $ 417 $ 402 $ 439 $ 509 Income (loss) from operations 121 99 112 183 Net income (loss) 147 98 87 95 Basic earnings (loss) per share (1) 0.74 0.49 0.44 0.47 Diluted earnings (loss) per share (1) 0.73 0.49 0.44 0.47 2016 Quarter Ended March 31 June 30 September 30 December 31 (In millions, except per share data) Oil, gas and NGL revenues $ 284 $ 381 $ 392 $ 415 Ceiling test and other impairments 506 522 — — Income (loss) from operations (2) (578 ) (498 ) 45 112 Net income (loss) (2) (624 ) (667 ) 48 13 Basic earnings (loss) per share (1) (3.52 ) (3.36 ) 0.24 0.07 Diluted earnings (loss) per share (1) (3.52 ) (3.36 ) 0.24 0.07 _________________ (1) The sum of the individual quarterly earnings (loss) per share may not agree with year-to-date earnings (loss) per share as each quarterly computation is based on the income or loss for that quarter and the weighted-average number of shares outstanding during that quarter. (2) Income (loss) from operations and Net income (loss) for the third quarter of 2016 include a legal settlement of $ 18 million . See Note 12 , " Commitments and Contingencies — Litigation " for additional information. Net income increased quarter over quarter by $8 million for the period ended December 31, 2017, driven by higher revenues partially offset by hedging losses. Tax benefits of $45 million were recognized in the fourth quarter of 2017, compared to $26 million in the prior quarter. |
Organization and Summary of S27
Organization and Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Organization and Principles of Consolidation | Organization and Principles of Consolidation We are an independent energy company engaged in the exploration, development and production of crude oil, natural gas and natural gas liquids (NGLs). Our U.S. operations are onshore and focus primarily on large scale, liquids-rich resource plays in the Anadarko and Arkoma basins of Oklahoma, the Williston Basin of North Dakota and the Uinta Basin of Utah. In addition, we have oil assets offshore China. Our consolidated financial statements include the accounts of Newfield Exploration Company, a Delaware corporation, and its subsidiaries. We proportionately consolidate our interests in oil and natural gas exploration and production joint ventures and partnerships in accordance with industry practice. All significant intercompany balances and transactions have been eliminated. Unless otherwise specified or the context otherwise requires, all references in these notes to "Newfield," "we," "us," "our" or the "Company" are to Newfield Exploration Company and its subsidiaries. |
Dependence on Oil and Gas Prices | Risks and Uncertainties As an independent oil and natural gas producer, our revenue, profitability and future rate of growth are substantially dependent on prevailing prices for oil, natural gas and NGLs. Historically, the energy markets have been very volatile, and there can be no assurance that commodity prices will not be subject to wide fluctuations in the future. A substantial or extended decline in commodity prices could have a material adverse effect on our financial position, results of operations, cash flows, access to capital and on the quantities of oil, natural gas and NGL reserves that we can economically produce. Other risks and uncertainties that could affect us in a volatile commodity price environment include, but are not limited to, counterparty credit risk for our receivables, responsibility for decommissioning liabilities for offshore interests we no longer own, inability to access credit markets, regulatory risks and our ability to meet financial ratios and covenants in our financing agreements. |
Use of Estimates | Use of Estimates The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America (U.S. GAAP) requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities; disclosure of contingent assets and liabilities at the date of the financial statements; the reported amounts of revenues and expenses during the reporting period; and the quantities and values of proved oil, natural gas and NGL reserves used in calculating depletion and assessing impairment of our oil and gas properties. Actual results could differ significantly from these estimates. Our most significant estimates are associated with the quantities of proved oil, natural gas and NGL reserves, the timing and amount of transfers of our unevaluated properties into our amortizable full cost pool, the recoverability of our deferred tax assets and the fair value of our derivative contracts. |
Restructuring and Related Activities Disclosure [Text Block] | Restructuring Costs Restructuring costs include severance and related benefit costs, costs associated with abandoned office space, employee relocation costs and other associated costs. Employee severance and related benefit costs are recognized on a straight-line basis over the required service period, if any. Employee relocation costs are expensed as incurred. On the date a leased property ceases to be used, a liability for non-cancellable office-lease costs associated with restructuring is recognized and measured at fair value on our consolidated balance sheet. Fair value estimates include assumptions regarding estimated future sublease payments. These estimates could materially differ from actual results and may require revision to initial estimates of the liability. See Note 17 , " Restructuring Costs ," for additional disclosures. Restructuring Costs In April 2015 and May 2016, we announced plans to consolidate and reorganize domestic operating functions to our headquarters in The Woodlands, Texas, which resulted in a reduction of employees and closure of our offices in Denver, Colorado; North Houston (Greenspoint), Texas; and Tulsa, Oklahoma. Our decision to restructure the organization was primarily in response to the oil and gas commodity price environment. Substantially all restructuring-related costs have been recognized as expense as of December 31, 2016. Restructuring costs recorded in our consolidated statement of operations for the years ended December 31 are set forth below. Type of Restructuring Cost Location in the Consolidated Statement of Operations 2017 2016 2015 (In millions) Severance and related benefit costs Operating expenses - General and administrative $ — $ 17 $ 7 Relocation costs Operating expenses - General and administrative 2 5 5 Office-lease abandonment costs Operating expenses - General and administrative — 6 14 Other associated costs Operating expenses - Depreciation, depletion and amortization — — 1 Total $ 2 $ 28 $ 27 The following table summarizes our restructuring costs and related liability. Severance and Related Benefit Costs Office-lease Abandonment Costs (1) Relocation Costs Other Associated Costs Total (In millions) Restructuring liability at January 1, 2015 $ — $ — $ — $ — $ — Additions 7 14 5 1 27 Settlements (6 ) (1 ) (5 ) (1 ) (13 ) Revisions — — — — — Restructuring liability at December 31, 2015 $ 1 $ 13 $ — $ — $ 14 Cumulative costs as of December 31, 2015 $ 7 $ 14 $ 5 $ 1 $ 27 Restructuring liability at January 1, 2016 $ 1 $ 13 $ — $ — $ 14 Additions 17 3 5 — 25 Settlements (17 ) (5 ) (5 ) — (27 ) Revisions — 3 — — 3 Restructuring liability at December 31, 2016 $ 1 $ 14 $ — $ — $ 15 Cumulative costs as of December 31, 2016 $ 24 $ 20 $ 10 $ 1 $ 55 Restructuring liability at January 1, 2017 $ 1 $ 14 $ — $ — $ 15 Additions — — 2 — 2 Settlements (1 ) (6 ) (2 ) — (9 ) Revisions — — — — — Restructuring liability at December 31, 2017 $ — $ 8 $ — $ — $ 8 Cumulative costs as of December 31, 2017 $ 24 $ 20 $ 12 $ 1 $ 57 Expected total costs $ 24 $ 20 $ 12 $ 1 $ 57 _________________ (1) The office-lease abandonment liability will be relieved as lease payments are made and sublease income is received over the life of the lease ending 2022. |
Revenue Recognition | Revenue Recognition All of our oil, natural gas and NGLs are sold at market-based prices adjusted for location and quality differentials to a variety of purchasers. We record revenue when we deliver our production to the customer and collectability is reasonably assured. Revenues from the production of oil, natural gas and NGLs on properties in which we have joint ownership are recorded under the sales method. Under the sales method, the Company and other joint owners may sell more or less than their entitled share of production. Should the Company’s excess sales exceed our share of estimated remaining recoverable reserves, a liability is recorded. |
Foreign Currency | Foreign Currency The functional currency for our China operations is the U.S. dollar. Gains and losses incurred on transactions in a currency other than the U.S. dollar are recorded under the caption "Other income (expense) — Other, net" on our consolidated statement of operations. |
Cash and Cash Equivalents | Cash and Cash Equivalents Cash and cash equivalents include highly liquid investments with a maturity of three months or less when acquired and are stated at cost, which approximates fair value. We invest cash in excess of near-term capital and operating requirements in U.S. Treasury Notes, Eurodollar time deposits and money market funds, which are classified as cash and cash equivalents on our consolidated balance sheet. |
Cash and Cash Equivalents, Restricted Cash and Cash Equivalents, Policy [Policy Text Block] | Restricted Cash Restricted cash consists of amounts held in escrow accounts to satisfy future plug and abandonment obligations for our China operations. These amounts are restricted as to their current use and will be released as we plug and abandon wells and facilities in China. Consistent with our other plug and abandonment activities, changes in restricted cash are included in cash flows from operating activities in our consolidated statement of cash flows. |
Investments | Investments Long-term investments consist of debt and equity securities, a majority of which are classified as "available-for-sale" and stated at fair value. Accordingly, unrealized gains and losses and the related deferred income tax effects are excluded from earnings and reported in other comprehensive income within our consolidated statement of stockholders' equity. The portion of accumulated other comprehensive income within our consolidated statement of stockholders' equity related to investments was $3 million at December 31, 2017 and $1 million at December 31, 2016 and 2015 . Realized gains or losses are computed based on specific identification of the securities sold. We regularly assess our investments for impairment and consider any impairment to be other than temporary if we intend to sell the security, it is more likely than not that we will be required to sell the security, or we do not expect to recover our cost of the security. |
Allowance for Doubtful Accounts | Allowance for Doubtful Accounts We routinely assess material trade and other receivables to determine their collectability. Many of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of related joint interest billings. Generally, our oil and gas receivables are collected within 45 to 60 days of production. We accrue a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected. |
Other Current Assets [Policy Text Block] | Other Current Assets Other current assets primarily consist of federal income tax refunds receivable, capital and lease operating expense prepayments and other prepaid items, including but not limited to, rent and insurance. For the years ended December 31, 2017 and 2016 , federal income tax refunds receivable were $53 million and $24 million , respectively. See Note 8, " Income Taxes ," for further discussion. |
Inventories | Inventories Inventories primarily consist of tubular goods and well equipment held for use in our oil and natural gas operations and oil produced but not sold in our China operations. Inventories are carried at the lower of cost or net realizable value. Substantially all of the crude oil from our offshore operations in China is produced into floating storage facilities and sold periodically as barge quantities accumulate. The carrying value of oil inventory is the sum of related production costs and depletion expense. See Note 3 , " Inventories ," for further discussion. |
Oil and Gas Properties | Oil and Gas Properties We use the full cost method of accounting for our oil and gas activities. Under this method, all costs incurred in the acquisition, exploration and development of oil and gas properties, including salaries, benefits, interest and other internal costs directly attributable to these activities, are capitalized into country-based cost centers. Proceeds from the sale of oil and gas properties are applied to reduce the costs in the applicable cost center unless the reduction would significantly alter the relationship between capitalized costs and proved reserves, in which case a gain or loss is recognized. Capitalized costs and estimated future development costs are amortized using a unit-of-production method based on proved reserves associated with the applicable cost center. For each cost center, the net capitalized costs of oil and gas properties are limited to the lower of the unamortized cost or the cost center ceiling. A particular cost center ceiling is equal to the sum of: • the present value ( 10% per annum discount rate) of estimated future net revenues from proved reserves using oil, natural gas and NGL reserve estimation requirements, which require use of the unweighted average first-day-of-the-month commodity prices for the prior 12 months (SEC pricing), adjusted for market differentials applicable to our reserves (including the effects of derivative contracts that are designated for hedge accounting, if any); plus • the costs of properties not included in the costs being amortized, if any; less • related income tax effects. If net capitalized costs of oil and gas properties exceed the cost center ceiling, we are subject to a ceiling test impairment to the extent of such excess. If required, a ceiling test impairment reduces earnings and stockholders’ equity in the period of occurrence and, holding other factors constant, results in lower depreciation, depletion and amortization expense in future periods. The risk that we will be required to impair the carrying value of our oil and gas properties increases when oil, natural gas and NGL prices decrease significantly for a prolonged period, or if we have substantial downward revisions in our estimated proved reserves. Costs associated with unevaluated properties are excluded from our full cost pool until we have evaluated the properties or impairment is indicated. The costs associated with unevaluated leasehold acreage, related seismic data and capitalized interest and direct internal costs are initially excluded from our full cost pool. Leasehold costs are either transferred to our full cost pool with the costs of drilling a well on the lease or are assessed at least annually for possible impairment or reduction in value. Leasehold costs are transferred to our full cost pool to the extent a reduction in value has occurred, or a charge is made against earnings if the costs were incurred in a country for which a reserve base has not been established. See Note 6 , " Oil and Gas Properties ," for a detailed discussion regarding our oil and gas property and our asset acquisitions and sales transactions. |
Other Property and Equipment | Other Property and Equipment Furniture, fixtures and equipment are recorded at cost and depreciated using the straight-line method over their estimated useful lives, which range from three to seven years. Gathering systems and equipment are recorded at cost and depreciated using the straight-line method over their estimated useful lives of 25 years. |
Accounting for Asset Retirement Obligations | Asset Retirement Obligations If a reasonable estimate of the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells can be made, we record a liability (an asset retirement obligation or ARO) on our consolidated balance sheet and capitalize the present value of the asset retirement cost in oil and gas properties in the period in which the ARO is incurred. Settlements include payments made to satisfy the AROs, as well as transfer of the AROs to purchasers of our divested properties. In general, the amount of the initial recorded ARO and the costs capitalized will equal the estimated future costs to satisfy the abandonment obligation assuming normal operation of the asset, using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, which is then discounted back to the date that the abandonment obligation was incurred using the credit adjusted risk-free rate for our Company. After recording these amounts, the ARO is accreted to its future estimated value and the original capitalized costs are depreciated on a unit-of-production basis within the related full cost pool. Both the accretion and depreciation are included in depreciation, depletion and amortization expense on our consolidated statement of operations. See Note 10 , " Asset Retirement Obligations ," for further discussion. |
Contingencies | Contingencies We are subject to legal proceedings, claims, liabilities and environmental matters that arise in the ordinary course of business. We accrue for losses when such losses are considered probable and the amounts can be reasonably estimated. See Note 12 , " Commitments and Contingencies ," for a more detailed discussion regarding our contingencies. |
Environmental Matters | Environmental Matters Environmental costs that relate to current operations are expensed as incurred. Remediation costs that relate to an existing condition caused by past operations are accrued when it is probable that those costs will be incurred and can be reasonably estimated based upon evaluations of currently available facts related to each site. |
Income Taxes | Income Taxes We use the liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are determined by applying tax regulations existing at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in our financial statements. We assess the available positive and negative evidence to estimate if sufficient taxable income will be generated to utilize deferred tax assets. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. We also evaluate potential uncertain tax positions, and if necessary, establish accruals for such items. See Note 8 , " Income Taxes ," for further discussion. |
Stock-Based Compensation | Stock-Based Compensation We apply a fair value-based method of accounting for stock-based compensation, which requires recognition in the financial statements of the cost of services received in exchange for equity and liability awards. For equity awards, compensation expense is based on the fair value on the grant or modification date and is recognized in our financial statements over the applicable service period. The fair value of our service based restricted stock and restricted stock units are based on the Company's stock price on the date of grant. We utilize the Black-Scholes option-pricing model to measure the fair value of stock options and a Monte Carlo lattice-based model for our market-based restricted stock units. We also have cash-settled restricted stock units that are accounted for under the liability method, which requires us to recognize the fair value of each award based on the Company's stock price at the end of each period. See Note 15 , " Stock-Based Compensation ," for a full discussion of our stock-based compensation. |
Concentration of Credit Risk | Concentration of Credit Risk We operate a substantial portion of our oil and gas properties. As the operator of a property, we make full payment for costs associated with the property and seek reimbursement from the other joint interest owners in the property for their share of those costs. In addition, when warranted, we require prepayments from our joint interest owners for drilling and completion projects. Our joint interest owners consist primarily of independent oil and gas producers whose ability to reimburse us could be negatively impacted by adverse market conditions. The purchasers of our oil, gas and NGL production consist primarily of independent marketers, major oil and gas companies, refiners and gas pipeline companies. We perform credit evaluations of the purchasers of our production and monitor their financial condition on an ongoing basis. Based on our evaluations and monitoring, we obtain cash escrows, letters of credit or parental guarantees from some purchasers. All of our derivative transactions were carried out in the over-the-counter market and are not typically subject to margin-deposit requirements. We monitor the credit ratings of our derivative counterparties on an ongoing basis and have netting arrangements that provide for offsetting payables against receivables by counterparty. Although we have entered into derivative contracts with multiple counterparties to mitigate our exposure to any individual counterparty, if any of our counterparties were to default on its obligations to us under the derivative contracts or seek bankruptcy protection, it could have a material adverse effect on our ability to fund our planned activities and could result in a larger percentage of our future production being subject to commodity price volatility. In addition, in poor economic environments and tight financial markets, the risk of a counterparty default is heightened and fewer counterparties may participate in derivative transactions, which could result in greater concentration of our exposure to any one counterparty or a larger percentage of our future production being subject to commodity price changes. The use of derivative transactions involves the risk that the counterparties, which generally are financial institutions, will be unable to meet the financial terms of such transactions. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty, and we have netting arrangements with all of our counterparties that provide for offsetting payables against receivables by counterparty. At December 31, 2017 , 10 of our 15 counterparties accounted for approximately 82% of our contracted volumes, with the largest counterparty accounting for approximately 12% . At December 31, 2017 , approximately 79% of our volumes subject to derivative instruments are with lenders under our credit facility. Our credit facility, senior notes and substantially all of our derivative instruments contain provisions that provide for cross defaults and acceleration of those debt and derivative instruments in certain situations. |
Major Customers | Major Customers None of our customers accounted for 10% or more of our total revenues in 2017 . During 2016 , China National Offshore Oil Corporation Ltd. accounted for 12% of our total revenues. During 2015 , China National Offshore Oil Corporation Ltd., MidCon Gathering LLC and Sunoco Logistics Partners Operations GP LLC accounted for 13% , 11% and 10% , respectively, of our total revenues. We believe that the loss of a major customer would not have a material adverse effect on us because alternative purchasers are available. |
Derivative Financial Instruments | Derivative Financial Instruments Our derivative instruments are recorded on the consolidated balance sheet at fair value as either an asset or a liability with changes in fair value recognized currently in earnings. While we utilize our derivative instruments to manage the price risk attributable to our expected oil, gas and NGL production, we have elected not to designate our derivative instruments as accounting hedges under the accounting guidance. The related cash flow impact of our derivative activities is reflected as cash flows from operating activities unless the derivatives are determined to have a significant financing element at inception, in which case they are classified within financing activities. See Note 4 , " Derivative Financial Instruments ," for a more detailed discussion of our derivative activities. |
Offsetting Fair Value | Offsetting Assets and Liabilities Our derivative financial instruments are subject to master netting arrangements and are reflected on our consolidated balance sheet accordingly. See Note 4 , " Derivative Financial Instruments ," for details regarding the gross amounts, as well as the impact of our netting arrangements on our net derivative position. |
New Accounting Requirements | New Accounting Requirements In May 2014, the Financial Accounting Standards Board (FASB) issued guidance regarding the accounting for revenue from contracts with customers. The guidance is effective for interim and annual periods beginning after December 15, 2017 and may be applied retrospectively or using a modified retrospective approach to adjust retained earnings (deficit). We will adopt the guidance in the first quarter of 2018 using the modified retrospective approach to adjust retained earnings (deficit). We have completed the process of evaluating our current revenue recognition policies to the new requirements for each of our revenue categories and have not identified any material differences in the amount and timing of revenue recognition. In November 2016, the FASB issued guidance regarding the classification and presentation of changes in restricted cash on the statement of cash flows. The guidance requires that a statement of cash flows explains the change during the period in the total of cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents using a retrospective approach. The guidance is effective for interim and annual periods beginning after December 15, 2017. Adoption of this standard will impact our cash flow from operations in periods with changes in restricted cash. In January 2016, the FASB issued guidance regarding several broad topics related to the recognition and measurement of financial assets and liabilities. The guidance is effective for interim and annual periods beginning after December 15, 2017. We do not expect this guidance to have a material impact on our financial statements. In February 2016, the FASB issued guidance regarding the accounting for leases. The guidance requires recognition of most leases on the balance sheet. The guidance requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The guidance is effective for interim and annual periods beginning after December 15, 2018. We are currently evaluating the impact of this guidance on our financial statements. |
Accounts Receivable (Tables)
Accounts Receivable (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Accounts Receivable, Net, Current [Abstract] | |
Schedule of Accounts, Notes, Loans and Financing Receivable [Table Text Block] | Accounts receivable consisted of the following at December 31: 2017 2016 (In millions) Revenue $ 175 $ 163 Joint interest 108 53 Other 25 32 Reserve for doubtful accounts (16 ) (16 ) Total accounts receivable, net $ 292 $ 232 Reserve for doubtful accounts at December 31, 2017 and 2016 includes an allowance for $15 million related to the sale of our Malaysia operations in 2014. See Note 12, " Commitments and Contingencies " to our consolidated financial statements in Item 8 of this report for additional details regarding our Malaysia litigation. |
Derivative Financial Instrume29
Derivative Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Derivative Instruments and Hedges, Assets [Abstract] | |
Outstanding contracts that are not designated for hedge accounting | At December 31, 2017 , we had outstanding derivative positions as set forth in the tables below. Crude Oil NYMEX Contract Price Per Bbl Collars Estimated Fair Value Period and Type of Instrument Volume in MBbls Swaps Puts (Weighted Average) Floors Ceilings (In millions) 2018: Swaptions (1) — $ 59.00 $ — $ — $ — $ (1 ) Fixed-price swaps 2,733 51.54 — — — (21 ) Fixed-price swaps with sold puts 644 Fixed-price swaps 56.78 — — — (1 ) Sold puts (2) — 44.00 — — — Collars 2,002 50.59 56.70 (9 ) Collars with sold puts: 14,315 Collars — — 48.42 56.42 (62 ) Sold puts — 39.46 — — (2 ) 2019: Collars with sold puts: 10,566 Collars — — 50.59 57.13 (15 ) Sold puts — 40.60 — — (11 ) Total $ (122 ) _________________ (1) During the fourth quarter of 2017, we sold crude oil swaption contracts that, if exercised on their expiration date in the first quarter of 2018, would protect 273,000 Bbls of second quarter 2018 production from future commodity price volatility. These contracts give the counterparties the option to enter into swap contracts with us at $59.00 /bbl for second quarter 2018. (2) For the fixed-price swaps with sold puts, if the market price remains below our sold puts at contract settlement, we will receive the market price plus the difference between our swaps and our sold puts. Natural Gas Period and Type of Instrument NYMEX Contract Price Per MMBtu Collars Volume in MMMBtus Swaps (Weighted Average) Puts (Weighted Average) Floors (Weighted Average) Ceilings (Weighted Average) Estimated Fair Value Asset (Liability) (In millions) 2018: Fixed-price swaps 42,100 $ 2.99 $ — $ — $ — $ 7 Collars 23,500 — — 3.08 3.61 7 Collars with sold puts 6,420 Collars — — 2.87 3.32 1 Sold puts — 2.30 — — — 2019: Fixed-price swaps 3,650 2.91 — — — Collars 9,000 — 3.00 3.47 1 Total $ 16 Natural Gas Liquids (Propane) Period and Type of Instrument Mont Belvieu Contract Price Per Gallon Volume in MBbls Swaps (Weighted Average) Estimated Fair Value Asset (Liability) (In millions) 2018: Fixed-price swaps 1,184 $ 0.81 $ (2 ) Total $ (2 ) |
Derivative financial instruments recorded in balance sheet | We had derivative financial instruments recorded in our consolidated balance sheet as assets (liabilities) at their respective estimated fair value, as set forth below. Derivative Assets Derivative Liabilities Gross Fair Value Offset in Balance Sheet Balance Sheet Location Gross Fair Value Offset in Balance Sheet Balance Sheet Location Current Noncurrent Current Noncurrent December 31, 2017 (In millions) (In millions) Oil positions $ 48 $ (48 ) $ — $ — $ (170 ) $ 48 $ (96 ) $ (26 ) Natural gas positions 22 (6 ) 15 1 (6 ) 6 — — NGL positions — — — — (2 ) — (2 ) — Total $ 70 $ (54 ) $ 15 $ 1 $ (178 ) $ 54 $ (98 ) $ (26 ) December 31, 2016 Oil positions $ 226 $ (151 ) $ 75 $ — $ (197 ) $ 151 $ (46 ) $ — Natural gas positions 10 (10 ) — — (64 ) 10 (51 ) (3 ) NGL positions — — — — — — — — Total $ 236 $ (161 ) $ 75 $ — $ (261 ) $ 161 $ (97 ) $ (3 ) |
Schedule of Derivative Instruments, Gain (Loss) in Statement of Operations [Table Text Block] | The amount of gain (loss) recognized in "Commodity derivative income (expense)" in our consolidated statement of operations and comprehensive income related to our derivative financial instruments follows: Year Ended December 31, 2017 2016 2015 (In millions) Derivatives not designated as hedging instruments: Realized gain (loss) on oil positions $ 48 $ 199 $ 375 Realized gain (loss) on natural gas positions (12 ) 2 130 Realized gain (loss) on NGL positions — — — Total realized gain (loss) 36 201 505 Unrealized gain (loss) on oil positions (152 ) (316 ) (165 ) Unrealized gain (loss) on natural gas positions 71 (76 ) (81 ) Unrealized gain (loss) on NGL positions (2 ) — — Total unrealized gain (loss) (83 ) (392 ) (246 ) Total $ (47 ) $ (191 ) $ 259 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Fair value by measurement classification and type Table | The following table summarizes the valuation of our assets and liabilities that are measured at fair value on a recurring basis. Fair Value Measurement Classification Quoted Prices in Active Markets for Identical Assets or (Liabilities) (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total (In millions) As of December 31, 2017: Money market fund investments $ 162 $ — $ — $ 162 Deferred compensation plan assets 7 — — 7 Equity securities available-for-sale 12 — — 12 Oil, gas and NGL derivative contracts — (108 ) — (108 ) Stock-based compensation liability awards (7 ) — — (7 ) Total $ 174 $ (108 ) $ — $ 66 As of December 31, 2016: Money market fund investments $ 320 $ — $ — $ 320 Deferred compensation plan assets 6 — — 6 Equity securities available-for-sale 9 — — 9 Oil and gas derivative swap contracts — 50 — 50 Oil and gas derivative option contracts — — (75 ) (75 ) Stock-based compensation liability awards (11 ) — — (11 ) Total $ 324 $ 50 $ (75 ) $ 299 |
Fair value changes level 3 Table | The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the indicated periods. Derivatives Stock-Based Compensation Total (In millions) Balance at January 1, 2015 $ (381 ) $ (3 ) $ (384 ) Unrealized gains (losses) included in earnings (217 ) 3 (214 ) Purchases, issuances, sales and settlements: Settlements 290 — 290 Transfers into Level 3 — — — Transfers out of Level 3 — — — Balance at December 31, 2015 $ (308 ) $ — $ (308 ) Change in unrealized gains or losses included in earnings relating to Level 3 instruments still held at December 31, 2015 $ (143 ) $ 3 $ (140 ) Balance at January 1, 2016 $ (308 ) $ — $ (308 ) Unrealized gains (losses) included in earnings (33 ) — (33 ) Purchases, issuances, sales and settlements: Settlements 220 — 220 Transfers into Level 3 — — — Transfers out of Level 3 (1) 46 — 46 Balance at December 31, 2016 $ (75 ) $ — $ (75 ) Change in unrealized gains or losses included in earnings relating to Level 3 instruments still held at December 31, 2016 $ 13 $ — $ 13 Balance at January 1, 2017 $ (75 ) $ — $ (75 ) Unrealized gains (losses) included in earnings (17 ) — (17 ) Purchases, issuances, sales and settlements: Settlements 30 — 30 Transfers into Level 3 — — — Transfers out of Level 3 (2) 62 — 62 Balance at December 31, 2017 $ — $ — $ — Change in unrealized gains or losses included in earnings relating to Level 3 instruments still held at December 31, 2017 $ — $ — $ — _________________ (1) During the second quarter of 2016, we transferred $46 million of derivative option contracts out of the Level 3 category as a result of our Level 3 swaptions being exercised by the counterparties as swaps in June 2016. (2) During the third quarter of 2017, we transferred $62 million of derivative option contracts out of the Level 3 hierarchy into Level 2 hierarchy as a result of our ability to derive volatility inputs from directly observable sources. |
Estimated fair value of the debt instrument at the balance sheet date | The estimated fair value of our notes, based on quoted prices in active markets (Level 1) as of December 31, was as follows: 2017 2016 (In millions) 5¾% Senior Notes due 2022 $ 802 $ 789 5⅝% Senior Notes due 2024 1,089 1,044 5⅜% Senior Notes due 2026 739 714 |
Oil and Gas Properties (Tables)
Oil and Gas Properties (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Oil and Gas Property [Abstract] | |
Capitalized Costs Relating to Oil and Gas Producing Activities and Other PPE [Table Text Block] | At December 31, oil and gas properties consisted of the following: 2017 2016 (In millions) Proved $ 23,272 $ 21,998 Unproved 1,200 1,238 Gross oil and gas properties 24,472 23,236 Accumulated depreciation, depletion and amortization (10,032 ) (9,587 ) Accumulated impairment (10,509 ) (10,509 ) Net oil and gas properties $ 3,931 $ 3,140 |
Costs incurred by year for oil and gas properties not subject to amortization | Costs withheld from amortization as of December 31, 2017 consisted of the following: Costs Incurred In 2017 2016 2015 2014 Total (In millions) Acquisition costs $ 108 $ 483 $ 274 $ 46 $ 911 Exploration costs — — — — — Capitalized internal cost 38 49 32 15 134 Capitalized interest 61 51 33 10 155 Total costs withheld from amortization $ 207 $ 583 $ 339 $ 71 $ 1,200 |
Other Property and Equipment 32
Other Property and Equipment Other Property and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment [Table Text Block] | At December 31, other property and equipment consisted of the following: 2017 2016 (In millions) Furniture, fixtures and equipment $ 165 $ 150 Gathering systems and equipment 115 115 Accumulated depreciation and amortization (112 ) (98 ) Net other property and equipment $ 168 $ 167 During 2017, we sold $11 million of furniture, fixtures and equipment and removed the associated asset and accumulated depreciation accordingly. |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Income (loss) before income taxes | For the years ended December 31, income (loss) before income taxes consisted of the following: 2017 2016 2015 (In millions) U.S. $ 357 $ (1,181 ) $ (4,865 ) International 29 (27 ) (82 ) Total income (loss) before income taxes $ 386 $ (1,208 ) $ (4,947 ) |
Total provision (benefit) for income taxes | For the years ended December 31, the total provision (benefit) for income taxes consisted of the following: 2017 2016 2015 (In millions) Current taxes: U.S. federal $ (79 ) $ (13 ) $ (12 ) U.S. state — — (2 ) International 1 22 31 (78 ) 9 17 Deferred taxes: U.S. federal 4 10 (1,507 ) U.S. state 37 13 (27 ) International (4 ) (10 ) (68 ) $ 37 $ 13 $ (1,602 ) Total provision (benefit) for income taxes $ (41 ) $ 22 $ (1,585 ) |
Provision for income taxes using federal statutory rate | Taxes for the year were impacted by our ability to monetize $19 million of the alternative minimum tax (AMT) credit carryover on the 2017 U.S federal tax provision by an election to refund AMT credits in lieu of bonus depreciation. The newly enacted Tax Cuts and Jobs Act (the Tax Act) repealed the corporate AMT for tax years beginning January 1, 2018, and provides that any remaining AMT credit carryovers are refundable beginning in 2019. We had approximately $42 million of AMT credit carryovers at the end of 2017 that will be fully refunded between 2019 and 2022. The valuation allowance related to this deferred tax asset was released and a noncurrent receivable was established, which resulted in a tax benefit of $42 million for the year ended December 31, 2017. Also included in the net tax benefit for the year were refunds of $17 million related to the carryback of net operating losses to previously filed U.S. federal returns. The provision for state deferred income taxes on the consolidated statement of operations for the year ended December 31, 2017 was attributable to Oklahoma state deferred tax expense. Other state taxing jurisdictions were in a net deferred tax asset position for which a corresponding valuation allowance was recorded resulting in zero deferred tax benefit for those jurisdictions. Our effective tax rate for 2017 differs from the U.S. statutory rate primarily due to domestic and international deferred tax asset valuation allowances discussed below. The amount for state income taxes in the rate reconciliation table below is the net deferred tax expenses before valuation allowances, if any, generated from all states. This table presents a reconciliation of the United States statutory income tax rate to our effective income tax rate. 2017 2016 2015 U.S. statutory income tax rate 35.0 % 35.0 % 35.0 % State and local income taxes, net of federal effect 6.9 — 0.9 Valuation allowance, domestic (210.1 ) (35.5 ) (4.0 ) Valuation allowance, international (1.2 ) (2.4 ) (0.3 ) Foreign tax on foreign earnings 1.5 0.6 0.4 Impact of Tax Act 157.4 — — Other — 0.5 — Effective income tax rate (10.5 )% (1.8 )% 32.0 % |
Components of deferred tax asset and deferred tax liability | At December 31, 2017 and 2016 respectively, the components of our deferred tax asset (liability) were as follows: 2017 (1) 2016 Deferred tax asset: Net operating loss carryforwards $ 314 $ 301 Alternative Minimum Tax credit — 73 Stock-based compensation 11 15 Oil and gas properties 15 306 Commodity derivatives 19 9 Foreign tax credit — 593 Other 3 13 Total deferred tax asset 362 1,310 Deferred tax asset valuation allowances (362 ) (1,310 ) Net deferred tax asset — — Deferred tax liability: Commodity derivatives — — Oil and gas properties (76 ) (39 ) Total deferred tax liability (76 ) (39 ) Net deferred tax liability $ (76 ) $ (39 ) |
Roll forward of deferred tax asset valuation allowance | The change in our deferred tax asset valuation allowance is as follows at December 31: 2017 2016 2015 (In millions) Balance at the beginning of the year $ (1,310 ) $ (790 ) $ (549 ) Charged to provision for income taxes: U.S. state net operating loss carryforwards 7 (4 ) (1 ) U.S. federal and state valuation allowance 343 (466 ) (202 ) Foreign tax credit valuation allowance 593 (21 ) (25 ) China valuation allowance 5 (29 ) (13 ) Balance at the end of the year $ (362 ) $ (1,310 ) $ (790 ) |
Accrued Liabilities (Tables)
Accrued Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Accrued Liabilities, Current [Abstract] | |
Schedule of Accrued Liabilities [Table Text Block] | Accrued liabilities consisted of the following at December 31: 2017 2016 (In millions) Revenue payable $ 239 $ 196 Accrued capital costs 173 92 Accrued lease operating expenses 22 37 Employee incentive expense 44 48 Accrued interest on debt 67 67 Taxes payable 11 15 Other 35 43 Total accrued liabilities $ 591 $ 498 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of Change in Asset Retirement Obligation [Table Text Block] | The change in our ARO for each of the three years ended December 31, is set forth below: 2017 2016 2015 (In millions) Balance at January 1 $ 156 $ 194 $ 186 Accretion expense 9 10 10 Additions (1) 3 15 6 Revisions (2) (25 ) (23 ) (2 ) Settlements (3) (10 ) (40 ) (6 ) Balance at December 31 133 156 194 Less: Current portion of ARO at December 31 (3 ) (2 ) (2 ) Total long-term ARO at December 31 $ 130 $ 154 $ 192 _________________ (1) For the year ended December 31, 2016 , additions include $8 million of abandonment obligations assumed through our Anadarko Basin acquisition. (2) Revisions are primarily due to changes in cost estimates and timing of expected abandonment. (3) For the year ended December 31, 2017 , settlements include $7 million related to the sale of our interest in the Bohai Bay field in China. For the year ended December 31, 2016 , settlements include $35 million related to the sale of our Texas assets. See Note 6 , " Oil and Gas Properties ." |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Debt Instrument [Line Items] | |
Debt | At December 31, our debt consisted of the following: 2017 2016 (In millions) Senior unsecured debt: 5¾% Senior Notes due 2022 $ 750 $ 750 5⅝% Senior Notes due 2024 1,000 1,000 5⅜% Senior Notes due 2026 700 700 Total senior unsecured debt 2,450 2,450 Debt issuance costs (16 ) (19 ) Total long-term debt $ 2,434 $ 2,431 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |
Sep. 30, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | |
Commitments and Contingencies Disclosure [Abstract] | |||
Future minimum payments under non-cancellable agreements | As of December 31, 2017 , future minimum payments under these non-cancelable agreements are as follows: Firm Transportation Operating Leases (Office Space) Drilling-Related Other Total (In millions) Year Ending December 31, 2018 $ 79 $ 25 $ 25 $ 18 $ 147 2019 78 23 — 14 115 2020 31 21 — 7 59 2021 21 22 — 3 46 2022 21 4 — 2 27 Thereafter 106 — — 17 123 Total minimum future payments $ 336 $ 95 $ 25 $ 61 $ 517 | ||
Oil and gas production volume delivery commitments | As of December 31, 2017 , our delivery commitments through 2025 were as follows: Oil Year Ending December 31, (MBbls) 2018 12,220 2019 11,315 2020 8,136 2021 5,840 2022 5,840 Thereafter 15,600 Total delivery commitments 58,951 | ||
Loss Contingency, Damages Paid, Value | $ 18 | $ 18 | |
Loss Contingency, Damages Sought, Value | $ 89 |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Earnings Per Share [Abstract] | |
Earnings Per Share Table | The following is the calculation of basic and diluted weighted-average shares outstanding and EPS for the indicated years. 2017 2016 2015 (In millions, except per share data) Net income (loss) $ 427 $ (1,230 ) $ (3,362 ) Weighted-average shares (denominator): Weighted-average shares — basic 199 193 159 Dilution effect of stock options and unvested restricted stock and restricted stock units outstanding at end of period 1 — — Weighted-average shares — diluted 200 193 159 Excluded due to anti-dilutive effect 1 2 3 Earnings (loss) per share: Basic $ 2.14 $ (6.36 ) $ (21.18 ) Diluted $ 2.13 $ (6.36 ) $ (21.18 ) |
Stock-Based Compensation (Table
Stock-Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Share-based Compensation [Abstract] | |
Schedule of Stock Based Compensation Expense Table | For the years ended December 31, our stock-based compensation expense consisted of the following: 2017 2016 2015 (In millions) Equity awards $ 53 $ 32 $ 42 Liability awards 5 21 12 Total stock-based compensation expense 58 53 54 Capitalized in oil and gas properties (17 ) (17 ) (18 ) Net stock-based compensation expense $ 41 $ 36 $ 36 |
Restricted Stock and Restricted Stock Unit Activity Table | The following table summarizes the activity for our restricted stock and restricted stock unit activity. Service-Based Shares Weighted- Average Grant Date Fair Value per Share Market-Based Shares Weighted- Average Grant Date Fair Value per Share Total Shares (In thousands, except per share data) Non-vested shares outstanding at January 1, 2015 1,902 $ 30.79 945 $ 28.61 2,847 Granted 1,036 31.20 414 22.85 1,450 Forfeited (367 ) 21.69 (97 ) 36.72 (464 ) Vested (871 ) 32.10 (188 ) 39.42 (1,059 ) Non-vested shares outstanding at December 31, 2015 1,700 30.30 1,074 23.76 2,774 Granted 990 37.95 436 (1) 28.94 1,426 Forfeited (217 ) 29.15 (77 ) 43.04 (294 ) Vested (899 ) 29.34 (574 ) 21.36 (1,473 ) Non-vested shares outstanding at December 31, 2016 1,574 35.56 859 26.28 2,433 Granted 1,244 29.81 323 (2) 39.57 1,567 Forfeited (91 ) 34.43 (55 ) 37.14 (146 ) Vested (694 ) 34.67 (386 ) 29.43 (1,080 ) Non-vested shares outstanding at December 31, 2017 2,033 $ 32.41 741 $ 30.65 2,774 The following table provides information about cash-settled restricted stock unit activity. Cash-Settled Restricted Stock Units (In thousands) Non-vested units outstanding at January 1, 2015 1,216 Granted 211 Forfeited (257 ) Vested (462 ) Non-vested units outstanding at December 31, 2015 708 Granted 299 Forfeited (101 ) Vested (446 ) Non-vested units outstanding at December 31, 2016 460 Granted 241 Forfeited (32 ) Vested (318 ) Non-vested units outstanding at December 31, 2017 351 |
Stock Option Activity Table | The following table provides information about outstanding stock options. Number of Shares Underlying Options Weighted-Average Exercise Price per Share Weighted-Average Remaining Contractual Life Aggregate Intrinsic Value (1) (In thousands) (In years) (In millions) Outstanding and exercisable at: December 31, 2015 195 $ 48.45 2.1 $ — December 31, 2016 177 48.45 1.1 — December 31, 2017 155 48.45 0.1 — _________________ (1) The intrinsic value of a stock option is the amount by which the market value of our common stock at the indicated date, or at the time of exercise, exceeds the exercise price of the option. |
Employee Stock Purchase Plan [Table Text Block] | For the years ended December 31, our ESPP issuances and valuation assumptions consisted of the following: Options Issued Weighted-Average Fair Value per Share Risk-free Interest Rate Weighted-Average Volatility (In thousands) 2015 136 $ 8.71 0.12 % 49.41 % 2016 99 10.51 0.43 47.94 2017 124 9.03 0.87 39.13 |
Restructuring Costs Restructu40
Restructuring Costs Restructuring Costs (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Restructuring and Related Activities [Abstract] | |
Restructuring and Related Costs [Table Text Block] | Restructuring costs recorded in our consolidated statement of operations for the years ended December 31 are set forth below. Type of Restructuring Cost Location in the Consolidated Statement of Operations 2017 2016 2015 (In millions) Severance and related benefit costs Operating expenses - General and administrative $ — $ 17 $ 7 Relocation costs Operating expenses - General and administrative 2 5 5 Office-lease abandonment costs Operating expenses - General and administrative — 6 14 Other associated costs Operating expenses - Depreciation, depletion and amortization — — 1 Total $ 2 $ 28 $ 27 |
Schedule of Restructuring Reserve by Type of Cost [Table Text Block] | The following table summarizes our restructuring costs and related liability. Severance and Related Benefit Costs Office-lease Abandonment Costs (1) Relocation Costs Other Associated Costs Total (In millions) Restructuring liability at January 1, 2015 $ — $ — $ — $ — $ — Additions 7 14 5 1 27 Settlements (6 ) (1 ) (5 ) (1 ) (13 ) Revisions — — — — — Restructuring liability at December 31, 2015 $ 1 $ 13 $ — $ — $ 14 Cumulative costs as of December 31, 2015 $ 7 $ 14 $ 5 $ 1 $ 27 Restructuring liability at January 1, 2016 $ 1 $ 13 $ — $ — $ 14 Additions 17 3 5 — 25 Settlements (17 ) (5 ) (5 ) — (27 ) Revisions — 3 — — 3 Restructuring liability at December 31, 2016 $ 1 $ 14 $ — $ — $ 15 Cumulative costs as of December 31, 2016 $ 24 $ 20 $ 10 $ 1 $ 55 Restructuring liability at January 1, 2017 $ 1 $ 14 $ — $ — $ 15 Additions — — 2 — 2 Settlements (1 ) (6 ) (2 ) — (9 ) Revisions — — — — — Restructuring liability at December 31, 2017 $ — $ 8 $ — $ — $ 8 Cumulative costs as of December 31, 2017 $ 24 $ 20 $ 12 $ 1 $ 57 Expected total costs $ 24 $ 20 $ 12 $ 1 $ 57 |
Segment Information (Tables)
Segment Information (Tables) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Segment Reporting [Abstract] | |||
Segment Information Table | Domestic China Total (In millions) Year Ended December 31, 2017: Oil, gas and NGL revenues $ 1,679 $ 86 $ 1,765 Lease operating 188 27 215 Transportation and processing 300 — 300 Production and other taxes 64 — 64 Depreciation, depletion and amortization 443 24 467 Results of operations for oil and gas producing activities before tax 684 35 719 Other revenues 2 — 2 General and administrative 194 6 200 Other 5 1 6 Allocated income tax (benefit) (1) 180 17 Net income (loss) from oil and gas properties $ 307 $ 11 Total revenues 1,767 Total operating expenses 1,252 Income (loss) from operations 515 Interest expense, net of interest income, capitalized interest and other (82 ) Commodity derivative income (expense) (47 ) Income (loss) from operations before income taxes $ 386 Total assets $ 4,875 $ 86 $ 4,961 Additions to long-lived assets $ 1,288 $ 1 $ 1,289 _________________ (1) Allocated income tax based on estimated combined federal and state statutory tax rates in effect during the period, comprised of 37% for domestic and 60% for China. | Domestic China Total (In millions) Year Ended December 31, 2016: Oil, gas and NGL revenues $ 1,251 $ 217 $ 1,468 Lease operating 189 55 244 Transportation and processing 272 — 272 Production and other taxes 41 1 42 Depreciation, depletion and amortization 458 114 572 Ceiling test and other impairments 962 66 1,028 Results of operations for oil and gas producing activities before tax (671 ) (19 ) (690 ) Other revenues 4 — 4 General and administrative 205 8 213 Other 20 — 20 Allocated income tax (benefit) (1) (330 ) (16 ) Net income (loss) from oil and gas properties $ (562 ) $ (11 ) Total revenues 1,472 Total operating expenses 2,391 Income (loss) from operations (919 ) Interest expense, net of interest income, capitalized interest and other (98 ) Commodity derivative income (expense) (191 ) Income (loss) from operations before income taxes $ (1,208 ) Total assets $ 4,166 $ 146 $ 4,312 Additions to long-lived assets $ 1,369 $ 2 $ 1,371 _________________ (1) Allocated income tax based on estimated combined federal and state statutory tax rates in effect during the period, comprised of 37% for domestic and 60% for China. | Domestic China Total (In millions) Year Ended December 31, 2015: Oil, gas and NGL revenues $ 1,288 $ 262 $ 1,550 Lease operating 231 54 285 Transportation and processing 212 — 212 Production and other taxes 45 1 46 Depreciation, depletion and amortization 754 163 917 Ceiling test and other impairments 4,786 118 4,904 Results of operations for oil and gas producing activities before tax (4,740 ) (74 ) (4,814 ) Other revenues 7 — 7 General and administrative 237 7 244 Other 9 1 10 Allocated income tax (benefit) (1) (1,842 ) (49 ) Net income (loss) from oil and gas properties $ (3,137 ) $ (33 ) Total revenues 1,557 Total operating expenses 6,618 Income (loss) from operations (5,061 ) Interest expense, net of interest income, capitalized interest and other (145 ) Commodity derivative income (expense) 259 Income (loss) from operations before income taxes $ (4,947 ) Total assets $ 4,452 $ 316 $ 4,768 Additions to long-lived assets $ 1,645 $ 100 $ 1,745 _________________ (1) Allocated income tax based on estimated combined federal and state statutory tax rates in effect during the period, comprised of 37% % for domestic and 60% for China. |
Supplemental Cash Flows Infor42
Supplemental Cash Flows Information (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Cash Flows Information Schedule (Table) | The following table presents information about supplemental cash flows for each of the three years ended December 31: 2017 2016 2015 (In millions) Cash Payments: Interest payments $ 84 $ 97 $ 119 Income tax payments (refunds) (2 ) 17 25 Non-cash investing and financing activities excluded from the statement of cash flows: (Increase) decrease in receivables for property sales $ — $ 6 $ 6 (Increase) decrease in accrued capital expenditures (81 ) 33 225 (Increase) decrease in asset retirement costs 31 46 (4 ) |
Quarterly Results of Operatio43
Quarterly Results of Operations (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule of Quarterly Financial Information Table | The results of operations by quarter for the indicated periods are as follows: 2017 Quarter Ended March 31 June 30 September 30 December 31 (In millions, except per share data) Oil, gas and NGL revenues $ 417 $ 402 $ 439 $ 509 Income (loss) from operations 121 99 112 183 Net income (loss) 147 98 87 95 Basic earnings (loss) per share (1) 0.74 0.49 0.44 0.47 Diluted earnings (loss) per share (1) 0.73 0.49 0.44 0.47 2016 Quarter Ended March 31 June 30 September 30 December 31 (In millions, except per share data) Oil, gas and NGL revenues $ 284 $ 381 $ 392 $ 415 Ceiling test and other impairments 506 522 — — Income (loss) from operations (2) (578 ) (498 ) 45 112 Net income (loss) (2) (624 ) (667 ) 48 13 Basic earnings (loss) per share (1) (3.52 ) (3.36 ) 0.24 0.07 Diluted earnings (loss) per share (1) (3.52 ) (3.36 ) 0.24 0.07 _________________ (1) The sum of the individual quarterly earnings (loss) per share may not agree with year-to-date earnings (loss) per share as each quarterly computation is based on the income or loss for that quarter and the weighted-average number of shares outstanding during that quarter. (2) Income (loss) from operations and Net income (loss) for the third quarter of 2016 include a legal settlement of $ 18 million . See Note 12 , " Commitments and Contingencies — Litigation " for additional information. Net income increased quarter over quarter by $8 million for the period ended December 31, 2017, driven by higher revenues partially offset by hedging losses. Tax benefits of $45 million were recognized in the fourth quarter of 2017, compared to $26 million in the prior quarter. |
Organization and Summary of S44
Organization and Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Income Taxes Receivable, Current | $ 53 | $ 24 | |
Discount rate | 10.00% | ||
Property, Plant and Equipment, Useful Life | 25 years | ||
Short-term investments | $ 0 | 25 | |
Accumulated Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax | $ 3 | 1 | $ 1 |
Primary Derivative Counterparties | 10 | ||
Total Derivative Counterparties | 15 | ||
ConcentrationOfCounterpartiesUnderCreditFacility | 79.00% | ||
Percentage of contracted volumes held by the largest counterparty. | 12.00% | ||
Percent of future hedged production with primary counterparties | 82.00% | ||
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Share-based Compensation Cost | $ 11 | $ 15 | |
Revenue, Major Customer [Line Items] | |||
Concentration Risk, Percentage | 0.00% | ||
Minimum [Member] | |||
Property, Plant and Equipment, Useful Life | 3 years | ||
Maximum [Member] | |||
Property, Plant and Equipment, Useful Life | 7 years | ||
Sunoco Logistics Partners [Member] | |||
Revenue, Major Customer [Line Items] | |||
Concentration Risk, Percentage | 10.00% | ||
MidCon Gathering LLC [Member] | |||
Revenue, Major Customer [Line Items] | |||
Concentration Risk, Percentage | 11.00% | ||
China National Offshore Oil Corporation [Member] | |||
Revenue, Major Customer [Line Items] | |||
Concentration Risk, Percentage | 12.00% | 13.00% |
Accounts Receivable (Details)
Accounts Receivable (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Accounts Notes And Loans Receivable [Line Items] | ||
Accounts receivable, net | $ 292 | $ 232 |
Allowance for Doubtful Accounts Receivable, Current | (16) | (16) |
Malaysia Reserve for Doubtful Accounts Allowance | 15 | 15 |
Loss Contingency, Damages Sought, Value | 89 | |
Revenue [Member] | ||
Accounts Notes And Loans Receivable [Line Items] | ||
Accounts receivable, net | 175 | 163 |
Oil and Gas Joint Interest Billing [Member] | ||
Accounts Notes And Loans Receivable [Line Items] | ||
Accounts receivable, net | 108 | 53 |
Other accounts receivable [Member] | ||
Accounts Notes And Loans Receivable [Line Items] | ||
Accounts receivable, net | $ 25 | $ 32 |
Inventories Inventories (Detail
Inventories Inventories (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017USD ($)MBbls | Dec. 31, 2016USD ($)MBbls | Dec. 31, 2015USD ($) | |
Inventory Disclosure [Abstract] | |||
Inventory Write-down | $ | $ 2 | $ 1 | $ 5 |
Crude Oil Inventory | MBbls | 0 | 11,500 |
Derivative Financial Instrume47
Derivative Financial Instruments (Textuals) (Details) $ in Millions | Dec. 31, 2017USD ($)MMBTU$ / MMBTU$ / gallon$ / bblMBbls | Dec. 31, 2016USD ($) |
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | $ 70 | $ 236 |
Derivative Asset, Fair Value, Gross Liability | (54) | (161) |
Derivative Asset, Current | 15 | 75 |
Derivative Asset, Noncurrent | 1 | 0 |
Derivative Liability, Fair Value, Gross Liability | (178) | (261) |
Derivative Liability, Fair Value, Gross Asset | 54 | 161 |
Derivative Liability, Current | (98) | (97) |
Derivative Liability, Noncurrent | (26) | (3) |
Crude Oil [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 48 | 226 |
Derivative Asset, Fair Value, Gross Liability | (48) | (151) |
Derivative Asset, Current | 0 | 75 |
Derivative Asset, Noncurrent | 0 | 0 |
Derivative Liability, Fair Value, Gross Liability | (170) | (197) |
Derivative Liability, Fair Value, Gross Asset | 48 | 151 |
Derivative Liability, Current | (96) | (46) |
Derivative Liability, Noncurrent | (26) | 0 |
Derivative Instruments Not Designated as Hedging Instruments, Liability, at Fair Value | (122) | |
Natural Gas [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 22 | 10 |
Derivative Asset, Fair Value, Gross Liability | (6) | (10) |
Derivative Asset, Current | 15 | 0 |
Derivative Asset, Noncurrent | 1 | 0 |
Derivative Liability, Fair Value, Gross Liability | (6) | (64) |
Derivative Liability, Fair Value, Gross Asset | 6 | 10 |
Derivative Liability, Current | 0 | (51) |
Derivative Liability, Noncurrent | 0 | (3) |
Derivative Asset, Fair Value, Total | 16 | |
Natural Gas Liquids [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 |
Derivative Asset, Fair Value, Gross Liability | 0 | 0 |
Derivative Asset, Current | 0 | 0 |
Derivative Asset, Noncurrent | 0 | 0 |
Derivative Liability, Fair Value, Gross Liability | (2) | 0 |
Derivative Liability, Fair Value, Gross Asset | 0 | 0 |
Derivative Liability, Current | (2) | 0 |
Derivative Liability, Noncurrent | 0 | $ 0 |
Derivative Instruments Not Designated as Hedging Instruments, Liability, at Fair Value | $ (2) | |
Year2018 [Member] | Crude Oil [Member] | Swaption [Member] | ||
Derivative [Line Items] | ||
Volume in MBbls | MBbls | 273,000 | |
Derivative, Swap Type, Average Fixed Price | $ / bbl | 59 | |
Derivative Instruments Not Designated as Hedging Instruments, Liability, at Fair Value | $ (1) | |
Year2018 [Member] | Crude Oil [Member] | Swap [Member] | ||
Derivative [Line Items] | ||
Volume in MBbls | MBbls | 2,733 | |
Derivative, Swap Type, Average Fixed Price | $ / bbl | 51.54 | |
Derivative Instruments Not Designated as Hedging Instruments, Liability, at Fair Value | $ (21) | |
Year2018 [Member] | Crude Oil [Member] | Fixed Price Swaps With Sold Puts [Member] | ||
Derivative [Line Items] | ||
Volume in MBbls | MBbls | 644 | |
Year2018 [Member] | Crude Oil [Member] | Fixed Price Swaps with Sold Puts - Put [Member] | ||
Derivative [Line Items] | ||
Derivative Average Additional Put Price | $ / bbl | 44 | |
Derivative Instruments Not Designated as Hedging Instruments, Liability, at Fair Value | $ 0 | |
Year2018 [Member] | Crude Oil [Member] | Fixed Price Swaps with Sold Puts - Swap [Member] | ||
Derivative [Line Items] | ||
Derivative, Swap Type, Average Fixed Price | $ / bbl | 56.78 | |
Derivative Instruments Not Designated as Hedging Instruments, Liability, at Fair Value | $ (1) | |
Year2018 [Member] | Crude Oil [Member] | Collars [Member] | ||
Derivative [Line Items] | ||
Volume in MBbls | MBbls | 2,002 | |
Derivative, Weighted Average Floor Price | $ / bbl | 50.59 | |
Derivative, Average Cap Price | $ / bbl | 56.70 | |
Derivative Instruments Not Designated as Hedging Instruments, Liability, at Fair Value | $ (9) | |
Year2018 [Member] | Crude Oil [Member] | Collars With Sold Puts [Member] | ||
Derivative [Line Items] | ||
Volume in MBbls | MBbls | 14,315 | |
Year2018 [Member] | Crude Oil [Member] | Collars with Sold Puts - Collar [Member] | ||
Derivative [Line Items] | ||
Derivative, Weighted Average Floor Price | $ / bbl | 48.42 | |
Derivative, Average Cap Price | $ / bbl | 56.42 | |
Derivative Instruments Not Designated as Hedging Instruments, Liability, at Fair Value | $ (62) | |
Year2018 [Member] | Crude Oil [Member] | Collars with Sold Puts - Sold Put [Member] | ||
Derivative [Line Items] | ||
Derivative Average Additional Put Price | $ / bbl | 39.46 | |
Derivative Instruments Not Designated as Hedging Instruments, Liability, at Fair Value | $ (2) | |
Year2018 [Member] | Natural Gas [Member] | Swap [Member] | ||
Derivative [Line Items] | ||
Derivative, Swap Type, Average Fixed Price | $ / MMBTU | 2.99 | |
Derivative Asset, Fair Value, Total | $ 7 | |
Volume In Mmbtus | MMBTU | 42,100,000 | |
Year2018 [Member] | Natural Gas [Member] | Collars [Member] | ||
Derivative [Line Items] | ||
Derivative, Weighted Average Floor Price | $ / MMBTU | 3.08 | |
Derivative, Average Cap Price | $ / MMBTU | 3.61 | |
Derivative Asset, Fair Value, Total | $ 7 | |
Volume In Mmbtus | MMBTU | 23,500,000 | |
Year2018 [Member] | Natural Gas [Member] | Collars With Sold Puts [Member] | ||
Derivative [Line Items] | ||
Volume In Mmbtus | MMBTU | 6,420,000 | |
Year2018 [Member] | Natural Gas [Member] | Collars with Sold Puts - Collar [Member] | ||
Derivative [Line Items] | ||
Derivative, Weighted Average Floor Price | $ / MMBTU | 2.87 | |
Derivative, Average Cap Price | $ / MMBTU | 3.32 | |
Derivative Asset, Fair Value, Total | $ 1 | |
Year2018 [Member] | Natural Gas [Member] | Collars with Sold Puts - Sold Put [Member] | ||
Derivative [Line Items] | ||
Derivative Average Additional Put Price | $ / MMBTU | 2.30 | |
Derivative Asset, Fair Value, Total | $ 0 | |
Year2018 [Member] | Natural Gas Liquids [Member] | Swap [Member] | ||
Derivative [Line Items] | ||
Volume in MBbls | MBbls | 1,184,000 | |
Derivative, Swap Type, Average Fixed Price | $ / gallon | 0.81 | |
Derivative Instruments Not Designated as Hedging Instruments, Liability, at Fair Value | $ (2) | |
Year2019 [Member] | Crude Oil [Member] | Collars With Sold Puts [Member] | ||
Derivative [Line Items] | ||
Volume in MBbls | MBbls | 10,566 | |
Year2019 [Member] | Crude Oil [Member] | Collars with Sold Puts - Collar [Member] | ||
Derivative [Line Items] | ||
Derivative, Weighted Average Floor Price | $ / bbl | 50.59 | |
Derivative, Average Cap Price | $ / bbl | 57.13 | |
Derivative Instruments Not Designated as Hedging Instruments, Liability, at Fair Value | $ (15) | |
Year2019 [Member] | Crude Oil [Member] | Collars with Sold Puts - Sold Put [Member] | ||
Derivative [Line Items] | ||
Derivative Average Additional Put Price | $ / bbl | 40.6 | |
Derivative Instruments Not Designated as Hedging Instruments, Liability, at Fair Value | $ (11) | |
Year2019 [Member] | Natural Gas [Member] | Swap [Member] | ||
Derivative [Line Items] | ||
Derivative, Swap Type, Average Fixed Price | $ / MMBTU | 2.91 | |
Derivative Instruments Not Designated as Hedging Instruments, Liability, at Fair Value | $ 0 | |
Volume In Mmbtus | MMBTU | 3,650,000 | |
Year2019 [Member] | Natural Gas [Member] | Collars [Member] | ||
Derivative [Line Items] | ||
Derivative, Weighted Average Floor Price | $ / MMBTU | 3 | |
Derivative, Average Cap Price | $ / MMBTU | 3.47 | |
Derivative Asset, Fair Value, Total | $ 1 | |
Volume In Mmbtus | MMBTU | 9,000,000 |
Derivative Financial Instrume48
Derivative Financial Instruments Recorded in Balance Sheet (Details) $ in Millions | Dec. 31, 2017USD ($)MMBTU$ / MMBTU$ / bbl | Dec. 31, 2016USD ($) |
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Gross Liability | $ (178) | $ (261) |
Derivative Liability, Fair Value, Gross Asset | 54 | 161 |
Derivative Asset, Fair Value, Gross Liability | (54) | (161) |
Derivative Asset Not Designated As Hedging Instrument, Fair Value | 70 | 236 |
Derivative Asset, Current | 15 | 75 |
Derivative Asset, Noncurrent | 1 | 0 |
Derivative Liability, Current | (98) | (97) |
Derivative Liability, Noncurrent | (26) | (3) |
Derivative Liability Not Designated as Hedging Instrument Fair Value | (178) | (261) |
Crude Oil [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Gross Liability | (170) | (197) |
Derivative Liability, Fair Value, Gross Asset | 48 | 151 |
Derivative Asset, Fair Value, Gross Liability | (48) | (151) |
Derivative Asset Not Designated As Hedging Instrument, Fair Value | 48 | 226 |
Derivative Asset, Current | 0 | 75 |
Derivative Asset, Noncurrent | 0 | 0 |
Derivative Liability, Fair Value, Total | (122) | |
Derivative Liability, Current | (96) | (46) |
Derivative Liability, Noncurrent | (26) | 0 |
Derivative Liability Not Designated as Hedging Instrument Fair Value | (170) | (197) |
Natural Gas [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Gross Liability | (6) | (64) |
Derivative Liability, Fair Value, Gross Asset | 6 | 10 |
Derivative Asset, Fair Value, Gross Liability | (6) | (10) |
Derivative Asset Not Designated As Hedging Instrument, Fair Value | 22 | 10 |
Derivative Asset, Current | 15 | 0 |
Derivative Asset, Noncurrent | 1 | 0 |
Derivative Asset, Fair Value, Total | (16) | |
Derivative Liability, Current | 0 | (51) |
Derivative Liability, Noncurrent | 0 | (3) |
Derivative Liability Not Designated as Hedging Instrument Fair Value | (6) | $ (64) |
Year2018 [Member] | Collars [Member] | Crude Oil [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Total | $ (9) | |
Derivative, Average Floor Price | $ / bbl | 50.59 | |
Derivative, Average Cap Price | $ / bbl | 56.70 | |
Year2018 [Member] | Collars [Member] | Natural Gas [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Total | $ (7) | |
Volume In Mmbtus | MMBTU | 23,500,000 | |
Derivative, Average Floor Price | $ / MMBTU | 3.08 | |
Derivative, Average Cap Price | $ / MMBTU | 3.61 | |
Year2018 [Member] | Collars With Sold Puts [Member] | Natural Gas [Member] | ||
Derivative [Line Items] | ||
Volume In Mmbtus | MMBTU | 6,420,000 | |
Year2018 [Member] | Collars with Sold Puts - Collar [Member] | Crude Oil [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Total | $ (62) | |
Derivative, Average Floor Price | $ / bbl | 48.42 | |
Derivative, Average Cap Price | $ / bbl | 56.42 | |
Year2018 [Member] | Collars with Sold Puts - Collar [Member] | Natural Gas [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Total | $ (1) | |
Derivative, Average Floor Price | $ / MMBTU | 2.87 | |
Derivative, Average Cap Price | $ / MMBTU | 3.32 | |
Year2018 [Member] | Collars with Sold Puts - Sold Put [Member] | Crude Oil [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Total | $ (2) | |
Derivative Average Additional Put Price | $ / bbl | 39.46 | |
Year2018 [Member] | Collars with Sold Puts - Sold Put [Member] | Natural Gas [Member] | ||
Derivative [Line Items] | ||
Derivative Average Additional Put Price | $ / MMBTU | 2.30 | |
Derivative Asset, Fair Value, Total | $ 0 | |
Year2018 [Member] | Swap [Member] | Crude Oil [Member] | ||
Derivative [Line Items] | ||
Derivative, Swap Type, Average Fixed Price | $ / bbl | 51.54 | |
Derivative Liability, Fair Value, Total | $ (21) | |
Year2018 [Member] | Swap [Member] | Natural Gas [Member] | ||
Derivative [Line Items] | ||
Derivative, Swap Type, Average Fixed Price | $ / MMBTU | 2.99 | |
Derivative Asset, Fair Value, Total | $ (7) | |
Volume In Mmbtus | MMBTU | 42,100,000 | |
Year2019 [Member] | Collars [Member] | Natural Gas [Member] | ||
Derivative [Line Items] | ||
Derivative Asset, Fair Value, Total | $ (1) | |
Volume In Mmbtus | MMBTU | 9,000,000 | |
Derivative, Average Floor Price | $ / MMBTU | 3 | |
Derivative, Average Cap Price | $ / MMBTU | 3.47 | |
Year2019 [Member] | Collars with Sold Puts - Collar [Member] | Crude Oil [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Total | $ (15) | |
Derivative, Average Floor Price | $ / bbl | 50.59 | |
Derivative, Average Cap Price | $ / bbl | 57.13 | |
Year2019 [Member] | Collars with Sold Puts - Sold Put [Member] | Crude Oil [Member] | ||
Derivative [Line Items] | ||
Derivative Liability, Fair Value, Total | $ (11) | |
Derivative Average Additional Put Price | $ / bbl | 40.6 | |
Year2019 [Member] | Swap [Member] | Natural Gas [Member] | ||
Derivative [Line Items] | ||
Derivative, Swap Type, Average Fixed Price | $ / MMBTU | 2.91 | |
Derivative Liability, Fair Value, Total | $ 0 | |
Volume In Mmbtus | MMBTU | 3,650,000 |
Amount of Gain Loss Recognized
Amount of Gain Loss Recognized in Income Related to Derivative Financial Instruments (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net [Abstract] | |||
Realized Gain (Loss) on Derivatives | $ 36 | $ 201 | $ 505 |
Unrealized Gain (Loss) on Derivatives | (83) | (392) | (246) |
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net | (47) | (191) | 259 |
Crude Oil [Member] | |||
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net [Abstract] | |||
Realized Gain (Loss) on Derivatives | 48 | 199 | 375 |
Unrealized Gain (Loss) on Derivatives | (152) | (316) | (165) |
Natural Gas [Member] | |||
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net [Abstract] | |||
Realized Gain (Loss) on Derivatives | (12) | 2 | 130 |
Unrealized Gain (Loss) on Derivatives | 71 | (76) | (81) |
Natural Gas Liquids [Member] | |||
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net [Abstract] | |||
Realized Gain (Loss) on Derivatives | 0 | 0 | 0 |
Unrealized Gain (Loss) on Derivatives | $ (2) | $ 0 | $ 0 |
Fair Value Measurements (Textua
Fair Value Measurements (Textuals) (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Money Market Funds, at Carrying Value | $ 162 | $ 320 |
Deferred Compensation Plan Assets | 7 | 6 |
Available-for-sale Securities | 12 | 9 |
Derivative Liability | (108) | |
Obligations, Fair Value Disclosure | (7) | (11) |
Assets, Fair Value Disclosure | 66 | 299 |
Swap [Member] | ||
Derivative Assets | 50 | |
Commodity Option [Member] | ||
Derivative Liability | (75) | |
Quoted Prices In Active Markets for Identical Assets or Liabilities, Fair Value Inputs (Level 1) [Member] | ||
Money Market Funds, at Carrying Value | 162 | 320 |
Deferred Compensation Plan Assets | 7 | 6 |
Available-for-sale Securities | 12 | 9 |
Derivative Assets | 0 | |
Obligations, Fair Value Disclosure | (7) | (11) |
Assets, Fair Value Disclosure | 174 | 324 |
Quoted Prices In Active Markets for Identical Assets or Liabilities, Fair Value Inputs (Level 1) [Member] | Swap [Member] | ||
Derivative Assets | 0 | |
Quoted Prices In Active Markets for Identical Assets or Liabilities, Fair Value Inputs (Level 1) [Member] | Commodity Option [Member] | ||
Derivative Assets | 0 | |
Fair Value, Inputs, Level 2 [Member] | ||
Money Market Funds, at Carrying Value | 0 | 0 |
Deferred Compensation Plan Assets | 0 | 0 |
Available-for-sale Securities | 0 | 0 |
Derivative Liability | 108 | |
Obligations, Fair Value Disclosure | 0 | 0 |
Assets, Fair Value Disclosure | 50 | |
Financial and Nonfinancial Liabilities, Fair Value Disclosure | 108 | |
Fair Value, Inputs, Level 2 [Member] | Swap [Member] | ||
Derivative Assets | 50 | |
Fair Value, Inputs, Level 2 [Member] | Commodity Option [Member] | ||
Derivative Assets | 0 | |
Fair Value, Inputs, Level 3 [Member] | ||
Money Market Funds, at Carrying Value | 0 | 0 |
Deferred Compensation Plan Assets | 0 | 0 |
Available-for-sale Securities | 0 | 0 |
Derivative Assets | 0 | |
Obligations, Fair Value Disclosure | 0 | 0 |
Financial and Nonfinancial Liabilities, Fair Value Disclosure | $ 0 | (75) |
Fair Value, Inputs, Level 3 [Member] | Swap [Member] | ||
Derivative Assets | 0 | |
Fair Value, Inputs, Level 3 [Member] | Commodity Option [Member] | ||
Derivative Liability | $ (75) |
Reconciliation of Changes in Fa
Reconciliation of Changes in Fair Value of Financial Assets and Liabilities Classified as Level Three In Fair Value Hierarchy (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||
Sep. 30, 2017 | Jun. 30, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||||
Fair Value, Measurement with Unobservable Inputs Reconciliations, Recurring Basis, Liability Value | $ 0 | $ (75) | $ (308) | $ (384) | ||
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Gain (Loss) Included in Earnings | (17) | (33) | (214) | |||
Liability Settlements | 30 | 220 | 290 | |||
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3 | 0 | 0 | 0 | |||
Fair Value, Measurement with Unobservable Inputs Reconciliation, Liability, Transfers out of Level 3 | 62 | 46 | 0 | |||
Fair Value, Liabilities Measured on Recurring Basis, Change in Unrealized Gain (Loss) | 0 | 13 | (140) | |||
Derivative Financial Instruments, Liabilities [Member] | ||||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||||
Fair Value, Measurement with Unobservable Inputs Reconciliations, Recurring Basis, Liability Value | 0 | (75) | (308) | (381) | ||
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Gain (Loss) Included in Earnings | (17) | (33) | (217) | |||
Liability Settlements | 30 | 220 | 290 | |||
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3 | 0 | 0 | 0 | |||
Fair Value, Measurement with Unobservable Inputs Reconciliation, Liability, Transfers out of Level 3 | $ 62 | $ 46 | 62 | 46 | 0 | |
Fair Value, Liabilities Measured on Recurring Basis, Change in Unrealized Gain (Loss) | 0 | 13 | (143) | |||
Stock Compensation Plan [Member] | ||||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||||
Fair Value, Measurement with Unobservable Inputs Reconciliations, Recurring Basis, Liability Value | 0 | 0 | 0 | $ (3) | ||
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Gain (Loss) Included in Earnings | 0 | 0 | 3 | |||
Liability Settlements | 0 | 0 | 0 | |||
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3 | 0 | 0 | 0 | |||
Fair Value, Measurement with Unobservable Inputs Reconciliation, Liability, Transfers out of Level 3 | 0 | 0 | 0 | |||
Fair Value, Liabilities Measured on Recurring Basis, Change in Unrealized Gain (Loss) | $ 0 | $ 0 | $ 3 |
Fair Value of Debt _Details_
Fair Value of Debt [Details] - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
5.75 %Senior Notes Due 2022 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Fair value of debt | $ 802 | $ 789 |
5.625% Senior Notes Due 2024 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Fair value of debt | 1,089 | 1,044 |
Senior Notes Due 2026 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Fair value of debt | $ 739 | $ 714 |
Oil and Gas Properties (Details
Oil and Gas Properties (Details) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016USD ($)$ / MMBTU$ / bbl | Sep. 30, 2016USD ($)$ / MMBTU$ / bbl | Jun. 30, 2016USD ($)$ / MMBTU$ / bbl | Mar. 31, 2016USD ($)$ / MMBTU$ / bbl | Dec. 31, 2015USD ($)$ / MMBTU$ / bbl | Sep. 30, 2015USD ($)$ / MMBTU$ / bbl | Jun. 30, 2015USD ($)$ / MMBTU$ / bbl | Mar. 31, 2015USD ($)$ / MMBTU$ / bbl | Dec. 31, 2017USD ($)$ / MMBTU$ / bbl | Dec. 31, 2016USD ($)$ / MMBTU$ / bbl | Dec. 31, 2015USD ($)$ / MMBTU$ / bbl | |
Oil and gas properties: | |||||||||||
Capitalized Costs, Proved Properties | $ 21,998 | $ 23,272 | $ 21,998 | ||||||||
Capitalized Costs, Oil and Gas Producing Activities, Gross | 23,236 | 24,472 | 23,236 | ||||||||
Capitalized Costs, Accumulated Depreciation, Depletion, Amortization and Valuation Allowance Relating to Oil and Gas Producing Activities | (9,587) | (10,032) | (9,587) | ||||||||
Capitalized Costs, Accumulated Impairment Relating to Oil and Gas Producing Activities | (10,509) | (10,509) | (10,509) | ||||||||
Capitalized Costs, Oil and Gas Producing Activities, Net | 3,140 | 3,931 | 3,140 | ||||||||
Cost of oil and gas properties not subject to amortization | |||||||||||
Acquisition costs | 911 | ||||||||||
Exploration costs | 0 | ||||||||||
Capitalized internal costs | 134 | ||||||||||
Capitalized interest | 155 | ||||||||||
Capitalized Costs of Unproved Properties Excluded from Amortization, Cumulative | $ 1,238 | 1,200 | 1,238 | ||||||||
Oil and Gas Assets (Textuals) [Abstract] | |||||||||||
Capitalization Of Internal Costs | $ 124 | $ 121 | $ 107 | ||||||||
Asset Impairment Charges | $ 4 | ||||||||||
Unweighted average commodity price of oil based on first day of month prices for prior twelve months | $ / bbl | 42.82 | 41.73 | 43.14 | 46.23 | 50.11 | 59.09 | 71.56 | 82.60 | 51.34 | 42.82 | 50.11 |
Unweighted average commodity price of natural gas based on first day of month prices for prior twelve months | $ / MMBTU | 2.48 | 2.28 | 2.24 | 2.40 | 2.59 | 3.06 | 3.39 | 3.88 | 2.98 | 2.48 | 2.59 |
Unamortized Costs Capitalized Less Related Deferred Income Taxes Exceed Ceiling Limitation Expense Gross | $ 0 | $ 0 | $ 522 | $ 506 | $ 702 | $ 1,889 | $ 1,521 | $ 788 | $ 1,028 | $ 4,900 | |
Unamortized Costs Capitalized Less Related Deferred Income Taxes Exceed Ceiling Limitations, Expense | 0 | 0 | 522 | 506 | 651 | 1,222 | 958 | 496 | 1,028 | 3,327 | |
Proceeds from Sale of Oil and Gas Property and Equipment | $ 96 | 405 | 90 | ||||||||
Value of Assets acquired | 110 | 486 | 125 | ||||||||
Asset Retirement Obligation, Liabilities Incurred | 3 | 15 | 6 | ||||||||
Anadarko Basin Acquisition [Member] | |||||||||||
Oil and Gas Assets (Textuals) [Abstract] | |||||||||||
Value of Assets acquired | 476 | ||||||||||
Costs Incurred, Acquisition of Unproved Oil and Gas Properties | 398 | ||||||||||
Costs Incurred, Acquisition of Oil and Gas Properties with Proved Reserves | 86 | ||||||||||
Texas Asset Sale [Member] | |||||||||||
Oil and Gas Assets (Textuals) [Abstract] | |||||||||||
Proceeds from Sale of Oil and Gas Property and Equipment | 380 | ||||||||||
UNITED STATES | |||||||||||
Oil and Gas Assets (Textuals) [Abstract] | |||||||||||
Unamortized Costs Capitalized Less Related Deferred Income Taxes Exceed Ceiling Limitation Expense Gross | 0 | 0 | 501 | 461 | 656 | 1,817 | 1,521 | 788 | 962 | 4,782 | |
Unamortized Costs Capitalized Less Related Deferred Income Taxes Exceed Ceiling Limitations, Expense | 0 | 0 | 501 | 461 | 620 | 1,193 | 958 | 496 | 962 | 3,267 | |
China [Member] | |||||||||||
Oil and Gas Assets (Textuals) [Abstract] | |||||||||||
Unamortized Costs Capitalized Less Related Deferred Income Taxes Exceed Ceiling Limitation Expense Gross | 0 | 0 | 21 | 45 | 46 | 72 | 0 | 0 | 66 | 118 | |
Unamortized Costs Capitalized Less Related Deferred Income Taxes Exceed Ceiling Limitations, Expense | $ 0 | $ 0 | $ 21 | $ 45 | $ 31 | $ 29 | $ 0 | $ 0 | 66 | 60 | |
Proceeds from Sale of Oil and Gas Property and Equipment | 32 | ||||||||||
Costs Incurred in 2017 not subject to amortization Member [Member] | |||||||||||
Cost of oil and gas properties not subject to amortization | |||||||||||
Acquisition costs | 108 | ||||||||||
Exploration costs | 0 | ||||||||||
Capitalized internal costs | 38 | ||||||||||
Capitalized interest | 61 | ||||||||||
Capitalized Costs of Unproved Properties Excluded from Amortization, Cumulative | 207 | ||||||||||
Costs incurred in 2016 not subject to amortization [Member] | |||||||||||
Cost of oil and gas properties not subject to amortization | |||||||||||
Acquisition costs | 483 | ||||||||||
Exploration costs | 0 | ||||||||||
Capitalized internal costs | 49 | ||||||||||
Capitalized interest | 51 | ||||||||||
Capitalized Costs of Unproved Properties Excluded from Amortization, Cumulative | 583 | ||||||||||
Costs incurred in 2015 not subject to amortization [Member] | |||||||||||
Cost of oil and gas properties not subject to amortization | |||||||||||
Acquisition costs | 274 | ||||||||||
Exploration costs | 0 | ||||||||||
Capitalized internal costs | 32 | ||||||||||
Capitalized interest | 33 | ||||||||||
Capitalized Costs of Unproved Properties Excluded from Amortization, Cumulative | 339 | ||||||||||
Costs incurred in 2014 not subject to amortization [Member] | |||||||||||
Cost of oil and gas properties not subject to amortization | |||||||||||
Acquisition costs | 46 | ||||||||||
Exploration costs | 0 | ||||||||||
Capitalized internal costs | 15 | ||||||||||
Capitalized interest | 10 | ||||||||||
Capitalized Costs of Unproved Properties Excluded from Amortization, Cumulative | 71 | ||||||||||
Other Property [Member] | |||||||||||
Oil and Gas Assets (Textuals) [Abstract] | |||||||||||
Proceeds from Sale of Oil and Gas Property and Equipment | 72 | 39 | 90 | ||||||||
Value of Assets acquired | $ 100 | $ 7 | $ 125 |
Oil and Gas Properties Ceiling
Oil and Gas Properties Ceiling Test Impairment (Details) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016USD ($)$ / MMBTU$ / bbl | Sep. 30, 2016USD ($)$ / MMBTU$ / bbl | Jun. 30, 2016USD ($)$ / MMBTU$ / bbl | Mar. 31, 2016USD ($)$ / MMBTU$ / bbl | Dec. 31, 2015USD ($)$ / MMBTU$ / bbl | Sep. 30, 2015USD ($)$ / MMBTU$ / bbl | Jun. 30, 2015USD ($)$ / MMBTU$ / bbl | Mar. 31, 2015USD ($)$ / MMBTU$ / bbl | Dec. 31, 2016USD ($)$ / MMBTU$ / bbl | Dec. 31, 2015USD ($)$ / MMBTU$ / bbl | Dec. 31, 2017$ / MMBTU$ / bbl | |
Ceiling Test Impairment [Line Items] | |||||||||||
Unweighted average commodity price of oil based on first day of month prices for prior twelve months | $ / bbl | 42.82 | 41.73 | 43.14 | 46.23 | 50.11 | 59.09 | 71.56 | 82.60 | 42.82 | 50.11 | 51.34 |
Unweighted average commodity price of natural gas based on first day of month prices for prior twelve months | $ / MMBTU | 2.48 | 2.28 | 2.24 | 2.40 | 2.59 | 3.06 | 3.39 | 3.88 | 2.48 | 2.59 | 2.98 |
Unamortized Costs Capitalized Less Related Deferred Income Taxes Exceed Ceiling Limitation Expense Gross | $ 0 | $ 0 | $ 522 | $ 506 | $ 702 | $ 1,889 | $ 1,521 | $ 788 | $ 1,028 | $ 4,900 | |
Unamortized Costs Capitalized Less Related Deferred Income Taxes Exceed Ceiling Limitations, Expense | 0 | 0 | 522 | 506 | 651 | 1,222 | 958 | 496 | 1,028 | 3,327 | |
UNITED STATES | |||||||||||
Ceiling Test Impairment [Line Items] | |||||||||||
Unamortized Costs Capitalized Less Related Deferred Income Taxes Exceed Ceiling Limitation Expense Gross | 0 | 0 | 501 | 461 | 656 | 1,817 | 1,521 | 788 | 962 | 4,782 | |
Unamortized Costs Capitalized Less Related Deferred Income Taxes Exceed Ceiling Limitations, Expense | 0 | 0 | 501 | 461 | 620 | 1,193 | 958 | 496 | 962 | 3,267 | |
China [Member] | |||||||||||
Ceiling Test Impairment [Line Items] | |||||||||||
Unamortized Costs Capitalized Less Related Deferred Income Taxes Exceed Ceiling Limitation Expense Gross | 0 | 0 | 21 | 45 | 46 | 72 | 0 | 0 | 66 | 118 | |
Unamortized Costs Capitalized Less Related Deferred Income Taxes Exceed Ceiling Limitations, Expense | $ 0 | $ 0 | $ 21 | $ 45 | $ 31 | $ 29 | $ 0 | $ 0 | $ 66 | $ 60 |
Other Property and Equipment 55
Other Property and Equipment Other Property and Equipment (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Property, Plant and Equipment [Line Items] | ||
Proceeds from Sale of Other Assets, Investing Activities | $ 11 | |
Accumulated depreciation and amortization | (112) | $ (98) |
Net other property and equipment | 168 | 167 |
Furniture and Fixtures [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Other property and equipment | 165 | 150 |
Gas Gathering and Processing Equipment [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Other property and equipment | $ 115 | $ 115 |
Income Taxes (Details)
Income Taxes (Details) - USD ($) | 3 Months Ended | 12 Months Ended | ||||
Dec. 31, 2017 | Sep. 30, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
EffectiveTaxRateReconciliation [Line Items] | ||||||
State and local income taxes, net of federal effect | 6.90% | 0.00% | 0.90% | |||
Effective Income Tax Rate Reconciliation, Foreign Income Tax Rate Differential, Percent | 1.50% | 0.60% | 0.40% | |||
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Percent | 157.40% | 0.00% | 0.00% | |||
Effective Income Tax Rate Reconciliation, Other Adjustments, Percent | 0.00% | 0.50% | 0.00% | |||
Effective Income Tax Rate Reconciliation, Percent | (10.50%) | (1.80%) | 32.00% | |||
Amount computed using the statutory rate | $ 0.35 | $ 0.35 | $ 0.35 | |||
Income (loss) before income taxes | 386,000,000 | (1,208,000,000) | (4,947,000,000) | |||
Current Income Tax Expense (Benefit), Continuing Operations [Abstract] | ||||||
U.S. federal | (79,000,000) | (13,000,000) | (12,000,000) | |||
U.S. state | 0 | 0 | (2,000,000) | |||
Foreign | 1,000,000 | 22,000,000 | 31,000,000 | |||
Current Income Tax Expense (Benefit) | $ 45,000,000 | $ 26,000,000 | (78,000,000) | 9,000,000 | 17,000,000 | |
Deferred taxes: | ||||||
U.S. federal | 4,000,000 | 10,000,000 | (1,507,000,000) | |||
U.S. state | 37,000,000 | 13,000,000 | (27,000,000) | |||
Foreign | (4,000,000) | (10,000,000) | (68,000,000) | |||
Deferred Income Tax Expense (Benefit) | 37,000,000 | 13,000,000 | (1,602,000,000) | |||
Total income tax provision (benefit) | (41,000,000) | 22,000,000 | (1,585,000,000) | |||
Components of Deferred Tax Assets and Liabilities [Abstract] | ||||||
Alternative minimum tax credit | 42,000,000 | 42,000,000 | ||||
Deferred tax asset: | ||||||
Net operating loss carryforwards | 314,000,000 | 314,000,000 | 301,000,000 | |||
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax | 0 | 0 | 73,000,000 | |||
Stock compensation | 11,000,000 | 11,000,000 | 15,000,000 | |||
Deferred Tax Assets, Property, Plant and Equipment | 15,000,000 | 15,000,000 | 306,000,000 | |||
Deferred Tax Assets, Derivative Instruments | 19,000,000 | 19,000,000 | 9,000,000 | |||
Foreign tax credit | 0 | 0 | (593,000,000) | |||
Other | 3,000,000 | 3,000,000 | 13,000,000 | |||
Deferred Tax Assets, Gross | 362,000,000 | 362,000,000 | 1,310,000,000 | |||
Valuation Allowance | (362,000,000) | (362,000,000) | (1,310,000,000) | $ (790,000,000) | $ (549,000,000) | |
Deferred tax asset | 0 | 0 | 0 | |||
Deferred tax liability: | ||||||
Commodity derivatives | 0 | 0 | 0 | |||
Deferred Tax Liabilities, Property, Plant and Equipment | (76,000,000) | (76,000,000) | (39,000,000) | |||
Deferred Tax Liabilities, Gross | (76,000,000) | (76,000,000) | (39,000,000) | |||
Deferred tax liability | (76,000,000) | (76,000,000) | (39,000,000) | |||
Unrecognized Tax Benefits, Income Tax Penalties Accrued | 0 | 0 | ||||
Internal Revenue Service (IRS) [Member] | ||||||
Operating Loss Carryforwards [Line Items] | ||||||
Operating Loss Carryforwards | 1,750,000,000 | 1,750,000,000 | $ 849,000,000 | |||
State and Local Jurisdiction [Member] | ||||||
Operating Loss Carryforwards [Line Items] | ||||||
Operating Loss Carryforwards | $ 1,500,000,000 | 1,500,000,000 | ||||
Future Statutory Rate [Member] | ||||||
Amount computed using the statutory rate | $ 0.21 | |||||
Domestic [Member] | ||||||
EffectiveTaxRateReconciliation [Line Items] | ||||||
Net effect of different tax rates in non-U.S. jurisdictions | (210.10%) | (35.50%) | (4.00%) | |||
Income (loss) before income taxes | $ 357,000,000 | $ (1,181,000,000) | $ (4,865,000,000) | |||
Foreign [Member] | ||||||
EffectiveTaxRateReconciliation [Line Items] | ||||||
Net effect of different tax rates in non-U.S. jurisdictions | (1.20%) | (2.40%) | (0.30%) | |||
Income (loss) before income taxes | $ 29,000,000 | $ (27,000,000) | $ (82,000,000) | |||
Refund of NOL [Member] | ||||||
Components of Current Income Tax Expense | 17,000,000 | |||||
Tax Credit Carryforward, Name [Domain] | ||||||
Components of Current Income Tax Expense | 19,000,000 | |||||
Conversion of Tax Credits [Member] | ||||||
Deferred tax asset: | ||||||
Change in Deferred Tax Asset | (185,000,000) | |||||
Loss of Tax Credits [Member] | ||||||
Deferred tax asset: | ||||||
Change in Deferred Tax Asset | $ (408,000,000) |
Income Taxes- DTA Valuation Rol
Income Taxes- DTA Valuation Rollforward (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Valuation Allowance [Line Items] | |||
Document Fiscal Year Focus | 2,017 | ||
Current Federal Tax Expense (Benefit) | $ (79) | $ (13) | $ (12) |
Balance at the beginning of the year | (1,310) | (790) | (549) |
Balance at the end of the year | (362) | (1,310) | (790) |
State and Local Jurisdiction [Member] | |||
Valuation Allowance [Line Items] | |||
Valuation Allowance, Deferred Tax Asset, Change in Amount | 7 | (4) | (1) |
Domestic Tax Authority [Member] | |||
Valuation Allowance [Line Items] | |||
Valuation Allowance, Deferred Tax Asset, Change in Amount | 343 | (466) | (202) |
Foreign [Member] | |||
Valuation Allowance [Line Items] | |||
Valuation Allowance, Deferred Tax Asset, Change in Amount | 593 | (21) | (25) |
China [Member] | |||
Valuation Allowance [Line Items] | |||
Balance at the beginning of the year | (42) | ||
Valuation Allowance, Deferred Tax Asset, Change in Amount | 5 | (29) | $ (13) |
Balance at the end of the year | (37) | $ (42) | |
Tax Credit Carryforward, Name [Domain] | |||
Valuation Allowance [Line Items] | |||
Components of Current Income Tax Expense | 42 | ||
Tax Act Impact [Member] | |||
Valuation Allowance [Line Items] | |||
Valuation Allowance, Deferred Tax Asset, Change in Amount | 199 | ||
DTA Valuation Allowance Share Based Payments [Member] | |||
Valuation Allowance [Line Items] | |||
Valuation Allowance, Deferred Tax Asset, Change in Amount | 37 | ||
Conversion of Tax Credits [Member] | |||
Valuation Allowance [Line Items] | |||
Change in Deferred Tax Asset | (185) | ||
Valuation Allowance, Deferred Tax Asset, Change in Amount | 185 | ||
Loss of Tax Credits [Member] | |||
Valuation Allowance [Line Items] | |||
Change in Deferred Tax Asset | (408) | ||
Valuation Allowance, Deferred Tax Asset, Change in Amount | $ 408 |
Accrued Liabilities (Details)
Accrued Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Accrued Liabilities [Line Items] | ||
Accrued liabilities | $ 591 | $ 498 |
Revenue payable [Member] | ||
Accrued Liabilities [Line Items] | ||
Accrued liabilities | 239 | 196 |
Accrued capital costs [Member] | ||
Accrued Liabilities [Line Items] | ||
Accrued liabilities | 173 | 92 |
Accrued lease operating expenses [Member] | ||
Accrued Liabilities [Line Items] | ||
Accrued liabilities | 22 | 37 |
Employee incentive expense [Member] | ||
Accrued Liabilities [Line Items] | ||
Accrued liabilities | 44 | 48 |
Accrued interest on debt [Member] | ||
Accrued Liabilities [Line Items] | ||
Accrued liabilities | 67 | 67 |
Taxes payable [Member] | ||
Accrued Liabilities [Line Items] | ||
Accrued liabilities | 11 | 15 |
Other accrued liabilities [Member] | ||
Accrued Liabilities [Line Items] | ||
Accrued liabilities | $ 35 | $ 43 |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Change in asset retirement obligations [Line Items] | ||||
Document Fiscal Year Focus | 2,017 | |||
Asset Retirement Obligation | $ 133 | $ 156 | $ 194 | $ 186 |
Asset Retirement Obligation, Accretion Expense | 9 | 10 | 10 | |
Asset Retirement Obligation, Liabilities Incurred | 3 | 15 | 6 | |
Asset Retirement Obligation, Revision of Estimate | (25) | (23) | (2) | |
Asset Retirement Obligation, Liabilities Settled | 10 | 40 | 6 | |
Asset Retirement Obligation, Current | (3) | (2) | (2) | |
Asset Retirement Obligations, Noncurrent | 130 | 154 | $ 192 | |
Anadarko Basin Acquisition [Member] | ||||
Change in asset retirement obligations [Line Items] | ||||
Asset Retirement Obligation, Liabilities Incurred | 8 | |||
Bohai Bay Sale [Member] | ||||
Change in asset retirement obligations [Line Items] | ||||
Asset retirement obligation liabilities settled through property sales | $ 7 | |||
Texas Asset Sale [Member] | ||||
Change in asset retirement obligations [Line Items] | ||||
Asset retirement obligation liabilities settled through property sales | $ 35 |
Debt (Details)
Debt (Details) - USD ($) | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Debt Instrument [Line Items] | ||||
Long-term debt | $ (2,434,000,000) | $ (2,431,000,000) | ||
Debt issuance costs | (16,000,000) | (19,000,000) | ||
Payments of Debt Issuance Costs | 0 | 0 | $ 8,000,000 | |
Early Repayment of Subordinated Debt | $ 0 | 0 | 700,000,000 | |
Payments of Financing Costs | $ 3,000,000 | |||
Debt (Textuals) | ||||
Largest individual loan commitment by any lender of total commitments | 12.00% | |||
Percent added to prime rate based on grid of our debt rating | 1.00% | |||
Percentage added to LIBOR based on grid of our debt rating | 2.00% | |||
Commitment fee percentage on unused capacity of line of credit | 0.375% | |||
Commitment fees incurred | $ 7,000,000 | 7,000,000 | $ 5,000,000 | |
Ratio of Indebtedness to Net Capital 1 | 0.6 | |||
Ratio of total debt to earnings before gain or loss on disposition of assets, interest expense, income taxes and noncash items | 2.5 | |||
Letters of Credit Outstanding, Amount | $ 0 | |||
Issuance fees percentage on letter of credit | 0.20% | |||
Percentage based on a grid of our debt rating on which letters of credit fees are based. | 2.00% | |||
Ratio of earnings before gain or loss on the disposition of assets, interest expense, income taxes and noncash items to interest expense | 2.5 | |||
5.75 %Senior Notes Due 2022 [Member] | ||||
Debt Instrument [Line Items] | ||||
Long-term debt | $ (750,000,000) | $ (750,000,000) | ||
Debt Instrument, Interest Rate, Stated Percentage | 5.75% | 5.75% | ||
5.625% Senior Notes Due 2024 [Member] | ||||
Debt Instrument [Line Items] | ||||
Long-term debt | $ (1,000,000,000) | $ (1,000,000,000) | ||
Debt Instrument, Interest Rate, Stated Percentage | 5.625% | 5.625% | ||
Senior Notes Due 2026 [Member] | ||||
Debt Instrument [Line Items] | ||||
Long-term debt | $ (700,000,000) | $ (700,000,000) | ||
Debt Instrument, Interest Rate, Stated Percentage | 5.375% | 5.375% | ||
Total senior unsecured debt | ||||
Debt Instrument [Line Items] | ||||
Long-term debt | $ (2,450,000,000) | $ (2,450,000,000) | ||
Revolving Credit Facility [Member] | ||||
Debt Instrument [Line Items] | ||||
Line of Credit Facility, Maximum Borrowing Capacity | 1,800,000,000 | |||
Line of Credit Facility, Amount Outstanding | 0 | |||
Money market lines of credit [Member] | ||||
Debt Instrument [Line Items] | ||||
Line of Credit Facility, Fair Value of Amount Outstanding | 0 | |||
Line of Credit Facility, Current Borrowing Capacity | $ 125,000,000 |
Commitments and Contingencies61
Commitments and Contingencies (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Future minimum payments under non-cancellable agreements | |||
Next FY | $ 147 | ||
2 Years | 115 | ||
3 Years | 59 | ||
4 years | 46 | ||
5 Years | 27 | ||
Thereafter | 123 | ||
Total minimum future payments | 517 | ||
Commitments and Contingencies (Textuals) [Abstract] | |||
Rent expense under lease commitments | 16 | $ 21 | $ 35 |
Firm Transportation [Member] | |||
Future minimum payments under non-cancellable agreements | |||
Next FY | 79 | ||
2 Years | 78 | ||
3 Years | 31 | ||
4 years | 21 | ||
5 Years | 21 | ||
Thereafter | 106 | ||
Total minimum future payments | 336 | ||
Operating Leases [Member] | |||
Future minimum payments under non-cancellable agreements | |||
Next FY | 25 | ||
2 Years | 23 | ||
3 Years | 21 | ||
4 years | 22 | ||
5 Years | 4 | ||
Thereafter | 0 | ||
Total minimum future payments | 95 | ||
Drilling-Related Leases [Member] | |||
Future minimum payments under non-cancellable agreements | |||
Next FY | 25 | ||
2 Years | 0 | ||
3 Years | 0 | ||
4 years | 0 | ||
5 Years | 0 | ||
Thereafter | 0 | ||
Total minimum future payments | 25 | ||
Other Commitments [Member] | |||
Future minimum payments under non-cancellable agreements | |||
Next FY | 18 | ||
2 Years | 14 | ||
3 Years | 7 | ||
4 years | 3 | ||
5 Years | 2 | ||
Thereafter | 17 | ||
Total minimum future payments | $ 61 |
Delivery Commitments (Details)
Delivery Commitments (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017USD ($)bbls$ / bblMBbls | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Delivery Commitments [Line Items] | |||
Delivery Commitments, Current | 12,220 | ||
Delivery Commitments, Due In Two Years | 11,315 | ||
Delivery Commitments, Due In Three Years | 8,136 | ||
Delivery Commitments, Due In Four Years | 5,840 | ||
Delivery Commitments, Due In Five Years | 5,840 | ||
Delivery Commitments, Due Thereafter | 15,600 | ||
Total Delivery Commitments | 58,951 | ||
Deficiency fees | $ | $ 29 | $ 16 | $ 0 |
Minimum [Member] | |||
Delivery Commitments [Line Items] | |||
Deficiency fees per barrel | $ / bbl | 3.50 | ||
Maximum [Member] | |||
Delivery Commitments [Line Items] | |||
Deficiency fees per barrel | $ / bbl | 6.50 | ||
2017 to 2025 [Member] | |||
Delivery Commitments [Line Items] | |||
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbls | 16,000 | ||
2017 to 2020 [Member] | |||
Delivery Commitments [Line Items] | |||
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbls | 15,000 |
Stockholders' Equity Activity63
Stockholders' Equity Activity (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||
Mar. 31, 2016 | Mar. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Equity, Class of Treasury Stock [Line Items] | |||||
Document Fiscal Year Focus | 2,017 | ||||
Stock Issued During Period, Shares, New Issues | 34,500,000 | 25,300,000 | |||
Proceeds from Issuance of Common Stock | $ 776 | $ 815 | $ 3 | $ 779 | $ 819 |
Common Stock, Shares Authorized | 300,000,000 | 300,000,000 |
Earnings Per Share (Details)
Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Income (numerator): | |||||||||||
Net income (loss) | $ 95 | $ 87 | $ 98 | $ 147 | $ 13 | $ 48 | $ (667) | $ (624) | $ 427 | $ (1,230) | $ (3,362) |
Weighted average shares (denominator): | |||||||||||
Weighted average shares - basic | 199 | 193 | 159 | ||||||||
Dilution effect of stock options and unvested restricted stock and restricted stock units outstanding at end of period | 1 | 0 | 0 | ||||||||
Weighted average shares - diluted | 200 | 193 | 159 | ||||||||
Basic -- | |||||||||||
Earnings (Loss) Per Share, Basic | $ 0.47 | $ 0.44 | $ 0.49 | $ 0.74 | $ 0.07 | $ 0.24 | $ (3.36) | $ (3.52) | $ 2.14 | $ (6.36) | $ (21.18) |
Diluted -- | |||||||||||
Earnings (Loss) Per Share, Diluted | $ 0.47 | $ 0.44 | $ 0.49 | $ 0.73 | $ 0.07 | $ 0.24 | $ (3.36) | $ (3.52) | $ 2.13 | $ (6.36) | $ (21.18) |
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block] | The following is the calculation of basic and diluted weighted-average shares outstanding and EPS for the indicated years. 2017 2016 2015 (In millions, except per share data) Net income (loss) $ 427 $ (1,230 ) $ (3,362 ) Weighted-average shares (denominator): Weighted-average shares — basic 199 193 159 Dilution effect of stock options and unvested restricted stock and restricted stock units outstanding at end of period 1 — — Weighted-average shares — diluted 200 193 159 Excluded due to anti-dilutive effect 1 2 3 Earnings (loss) per share: Basic $ 2.14 $ (6.36 ) $ (21.18 ) Diluted $ 2.13 $ (6.36 ) $ (21.18 ) | ||||||||||
Earnings Per Share (Textuals) [Abstract] | |||||||||||
Incremental shares attributable to the assumed exercise of outstanding stock options and the assumed vesting of unvested restricted stock and restricted stock units | 1 | 2 | 3 |
Stock-Based Compensation (Detai
Stock-Based Compensation (Details) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | ||||
Mar. 31, 2017shares | Mar. 31, 2016shares | Dec. 31, 2017USD ($)$ / sharesshares | Dec. 31, 2016USD ($)shares | Dec. 31, 2015USD ($)shares | Dec. 31, 2014USD ($)shares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Document Fiscal Year Focus | 2,017 | |||||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost | $ | $ 58 | $ 53 | $ 54 | |||
Total stock-based compensation expense | $ | 41 | 36 | 36 | |||
Capitalized in oil and gas properties | $ | $ 17 | $ 17 | $ 18 | |||
Share-based Compensation Arrangement by Share-based Payment Award, Number of Additional Shares Authorized | 2,000,000 | |||||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period | 1,567,000 | 1,426,000 | 1,450,000 | |||
Number of restricted stock shares vested | 1,080,000 | 1,473,000 | 1,059,000 | |||
Number of restricted stock shares outstanding | 2,774,000 | 2,433,000 | 2,774,000 | 2,847,000 | ||
Fair value of units vested during the period | $ | $ 35 | $ 39 | $ 35 | |||
Share Based Compensation Arrangement Exercise Rate | 20.00% | |||||
Nonvested Awards, Total Compensation Cost Not yet Recognized | $ | $ 54 | |||||
Liability Value | $ | 0 | 75 | 308 | $ 384 | ||
Liability Settlements | $ | 30 | 220 | 290 | |||
Obligations, Fair Value Disclosure | $ | $ 7 | 11 | ||||
Stock-Based Compensation (Textuals) [Abstract] | ||||||
Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition | 4 years | |||||
Last reported sales price of our common stock on the New York Stock Exchange per share | $ / shares | $ 31.53 | |||||
Equity [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost | $ | $ 53 | 32 | 42 | |||
Liability [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost | $ | $ 5 | $ 21 | $ 12 | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period | 241,000 | 299,000 | 211,000 | |||
Number of restricted stock shares vested | 318,000 | 446,000 | 462,000 | |||
Number of restricted stock shares outstanding | 351,000 | 460,000 | 708,000 | 1,216,000 | ||
Obligations, Fair Value Disclosure | $ | $ 7 | |||||
Stock Options [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Reduction factor multiplied by number of shares awarded | 1 | |||||
Additional shares available for issuance | 9,500,000 | |||||
Service - Based Shares [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period | 1,244,000 | 990,000 | 1,036,000 | |||
Number of restricted stock shares vested | 694,000 | 899,000 | 871,000 | |||
Number of restricted stock shares outstanding | 2,033,000 | 1,574,000 | 1,700,000 | 1,902,000 | ||
Performance Market Based Shares [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period | 323,000 | 436,000 | 323,000 | 436,000 | 414,000 | |
Number of restricted stock shares vested | 386,000 | 574,000 | 188,000 | |||
Number of restricted stock shares outstanding | 741,000 | 859,000 | 1,074,000 | 945,000 | ||
Restricted Stock [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Reduction factor multiplied by number of shares awarded | 1.67 | |||||
Additional shares available for issuance | 5,700,000 | |||||
Minimum [Member] | Performance Market Based Shares [Member] | ||||||
Stock-Based Compensation (Textuals) [Abstract] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage | 0.00% | 0.00% | ||||
Minimum [Member] | Qualified Retiree [Member] | ||||||
Stock-Based Compensation (Textuals) [Abstract] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage | 50.00% | |||||
Maximum [Member] | Performance Market Based Shares [Member] | ||||||
Stock-Based Compensation (Textuals) [Abstract] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage | 200.00% | 200.00% | ||||
Maximum [Member] | Qualified Retiree [Member] | ||||||
Stock-Based Compensation (Textuals) [Abstract] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage | 100.00% |
Stock-Based Compensation- Stock
Stock-Based Compensation- Stock Option Activity (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract] | |||
Outstanding, Beginning Balance, Number of Shares Underlying Options | 177 | 195 | |
Outstanding, Ending Balance, Number of Shares Underlying Options | 155 | 177 | 195 |
Outstanding, Beginning Balance, Weighted Average Exercise Price per Share | $ 48.45 | $ 48.45 | |
Outstanding, Ending Balance, Weighted Average Exercise Price per Share | $ 48.45 | $ 48.45 | $ 48.45 |
Options Outstanding, Weighted Average Remaining Contractual Life (In years) | 1 month 6 days | 1 year 1 month 6 days | 2 years 1 month 6 days |
Outstanding, Beginning Balance, Aggregate Intrinsic Value | $ 0 | $ 0 | |
Outstanding, Ending Balance, Aggregate Intrinsic Value | $ 0 | $ 0 | $ 0 |
Stock-Based Compensation- Sto67
Stock-Based Compensation- Stock Option Summary (Details) - $ / shares shares in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | |||
Options Outstanding, Number of Shares Underlying Options | 155 | 177 | 195 |
Options Outstanding, Weighted Average Remaining Contractual Life (In years) | 1 month 6 days | 1 year 1 month 6 days | 2 years 1 month 6 days |
Options Outstanding, Weighted Average Exercise Price per Share | $ 48.45 | $ 48.45 | $ 48.45 |
Stock-Based Compensation- Restr
Stock-Based Compensation- Restricted Stock and Restricted Stock Units Activity (Details) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | |||
Mar. 31, 2017 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Obligations, Fair Value Disclosure | $ (7) | $ (11) | |||
Non-vested shares outstanding, Beginning balance | 2,433,000 | 2,774,000 | 2,433,000 | 2,774,000 | 2,847,000 |
Granted | 1,567,000 | 1,426,000 | 1,450,000 | ||
Forfeited | (146,000) | (294,000) | (464,000) | ||
Vested | (1,080,000) | (1,473,000) | (1,059,000) | ||
Non-vested shares outstanding, Ending balance | 2,774,000 | 2,433,000 | 2,774,000 | ||
Qualified Retiree [Member] | Minimum [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage | 50.00% | ||||
Qualified Retiree [Member] | Maximum [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage | 100.00% | ||||
Performance Market Based Shares [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Non-vested shares outstanding, Beginning balance | 859,000 | 1,074,000 | 859,000 | 1,074,000 | 945,000 |
Granted | 323,000 | 436,000 | 323,000 | 436,000 | 414,000 |
Forfeited | (55,000) | (77,000) | (97,000) | ||
Vested | (386,000) | (574,000) | (188,000) | ||
Non-vested shares outstanding, Ending balance | 741,000 | 859,000 | 1,074,000 | ||
Non-vested shares outstanding, Weighted Average Grant Date Fair Value per Share, Beginning balance | $ 26.28 | $ 23.76 | $ 26.28 | $ 23.76 | $ 28.61 |
Granted, Weighted Average Grant Date Fair Value per Share | 39.57 | 28.94 | 22.85 | ||
Forfeited, Weighted Average Grant Date Fair Value per Share | 37.14 | 43.04 | 36.72 | ||
Vested, Weighted Average Grant Date Fair Value per Share | 29.43 | 21.36 | 39.42 | ||
Non-vested shares outstanding, Weighted Average Grant Date Fair Value per Share, Ending balance | $ 30.65 | $ 26.28 | $ 23.76 | ||
Performance Market Based Shares [Member] | Minimum [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage | 0.00% | 0.00% | |||
Performance Market Based Shares [Member] | Maximum [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage | 200.00% | 200.00% | |||
Service - Based Shares [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Non-vested shares outstanding, Beginning balance | 1,574,000 | 1,700,000 | 1,574,000 | 1,700,000 | 1,902,000 |
Granted | 1,244,000 | 990,000 | 1,036,000 | ||
Forfeited | (91,000) | (217,000) | (367,000) | ||
Vested | (694,000) | (899,000) | (871,000) | ||
Non-vested shares outstanding, Ending balance | 2,033,000 | 1,574,000 | 1,700,000 | ||
Non-vested shares outstanding, Weighted Average Grant Date Fair Value per Share, Beginning balance | $ 35.56 | $ 30.30 | $ 35.56 | $ 30.30 | $ 30.79 |
Granted, Weighted Average Grant Date Fair Value per Share | 29.81 | 37.95 | 31.20 | ||
Forfeited, Weighted Average Grant Date Fair Value per Share | 34.43 | 29.15 | 21.69 | ||
Vested, Weighted Average Grant Date Fair Value per Share | 34.67 | 29.34 | 32.10 | ||
Non-vested shares outstanding, Weighted Average Grant Date Fair Value per Share, Ending balance | $ 32.41 | $ 35.56 | $ 30.30 | ||
Liability [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Obligations, Fair Value Disclosure | $ (7) | ||||
Non-vested shares outstanding, Beginning balance | 460,000 | 708,000 | 460,000 | 708,000 | 1,216,000 |
Granted | 241,000 | 299,000 | 211,000 | ||
Forfeited | (32,000) | (101,000) | (257,000) | ||
Vested | (318,000) | (446,000) | (462,000) | ||
Non-vested shares outstanding, Ending balance | 351,000 | 460,000 | 708,000 |
Stock-Based Compensation- Emplo
Stock-Based Compensation- Employee Stock Purchase Plan (Details) - Employee Stock [Member] - USD ($) | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2010 | |
Employee Stock Ownership Plan (ESOP) Disclosures [Line Items] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Percentage of Market Price, Purchase Date | 85.00% | |||
Maximum amount of common stock that an employee can purchase under Employee Stock Purchase Plan in any calendar year | $ 25,000 | |||
Additional shares available for issuance | 2,000,000 | 1,000,000 | ||
Options To Purchase Common Stock Shares | 124,000 | 99,000 | 136,000 | |
Weighted average fair value of each option | $ 9.03 | $ 10.51 | $ 8.71 | |
Expected volatility | 39.13% | 47.94% | 49.41% | |
Risk-free weighted average interest rate | 0.87% | 0.43% | 0.12% |
Employee Benefit Plans (Details
Employee Benefit Plans (Details) | 12 Months Ended | ||
Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Defined Contribution Plan [Abstract] | |||
Maximum age for retire employees to be covered under post-retirement medical plan | 65 | ||
Plan Eligibility Minimum Age | 55 | ||
Plan Eligibility Minimum Service | 5 | ||
Defined Benefit Plan, Benefit Obligation | $ 22,000,000 | ||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) | 3,000,000 | $ 3,000,000 | $ 3,000,000 |
Expected future benefit payments in years one through five for post-retirement medical plan | 8,000,000 | ||
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter | 10,000,000 | ||
Other Labor-related Expenses | 31,000,000 | 35,000,000 | 41,000,000 |
Employer matching contribution for each $1 of employee deferral | $ 1 | ||
Employee contribution to be matched by the Company | 8.00% | ||
Defined Contribution Plan, Employer Discretionary Contribution Amount | $ 6,000,000 | $ 6,000,000 | $ 7,000,000 |
Restructuring Costs Restructu71
Restructuring Costs Restructuring Costs (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Restructuring Reserve [Roll Forward] | ||||
Restructuring Charges | $ 2 | $ 28 | $ 27 | |
Restructuring Reserve | 8 | 15 | 14 | $ 0 |
Restructuring and Related Cost, Incurred Cost | 2 | 25 | 27 | |
Payments for Restructuring | (9) | (27) | (13) | |
Restructuring Reserve, Accrual Adjustment | 0 | 3 | 0 | |
Restructuring and Related Cost, Cost Incurred to Date | 57 | 55 | 27 | |
Restructuring and Related Cost, Expected Cost | 57 | |||
Employee Severance [Member] | ||||
Restructuring Reserve [Roll Forward] | ||||
Restructuring Reserve | 0 | 1 | 1 | 0 |
Restructuring and Related Cost, Incurred Cost | 0 | 17 | 7 | |
Payments for Restructuring | (1) | (17) | (6) | |
Restructuring Reserve, Accrual Adjustment | 0 | 0 | 0 | |
Restructuring and Related Cost, Cost Incurred to Date | 24 | 24 | 7 | |
Restructuring and Related Cost, Expected Cost | 24 | |||
Employee Relocation [Member] | ||||
Restructuring Reserve [Roll Forward] | ||||
Restructuring Reserve | 0 | 0 | 0 | 0 |
Restructuring and Related Cost, Incurred Cost | 2 | 5 | 5 | |
Payments for Restructuring | (2) | (5) | (5) | |
Restructuring Reserve, Accrual Adjustment | 0 | 0 | 0 | |
Restructuring and Related Cost, Cost Incurred to Date | 12 | 10 | 5 | |
Restructuring and Related Cost, Expected Cost | 12 | |||
Contract Termination [Member] | ||||
Restructuring Reserve [Roll Forward] | ||||
Restructuring Reserve | 8 | 14 | 13 | 0 |
Restructuring and Related Cost, Incurred Cost | 0 | 3 | 14 | |
Payments for Restructuring | (6) | (5) | (1) | |
Restructuring Reserve, Accrual Adjustment | 0 | 3 | 0 | |
Restructuring and Related Cost, Cost Incurred to Date | 20 | 20 | 14 | |
Restructuring and Related Cost, Expected Cost | 20 | |||
Other Restructuring [Member] | ||||
Restructuring Reserve [Roll Forward] | ||||
Restructuring Reserve | 0 | 0 | 0 | $ 0 |
Restructuring and Related Cost, Incurred Cost | 0 | 0 | 1 | |
Restructuring Reserve, Settled without Cash | 0 | 0 | (1) | |
Restructuring Reserve, Accrual Adjustment | 0 | 0 | 0 | |
Restructuring and Related Cost, Cost Incurred to Date | 1 | 1 | 1 | |
Restructuring and Related Cost, Expected Cost | 1 | |||
General and Administrative Expense [Member] | Employee Severance [Member] | ||||
Restructuring Reserve [Roll Forward] | ||||
Restructuring Charges | 0 | 17 | 7 | |
General and Administrative Expense [Member] | Employee Relocation [Member] | ||||
Restructuring Reserve [Roll Forward] | ||||
Restructuring Charges | 2 | 5 | 5 | |
General and Administrative Expense [Member] | Contract Termination [Member] | ||||
Restructuring Reserve [Roll Forward] | ||||
Restructuring Charges | 0 | 6 | 14 | |
Depreciation Depletion and Amortization [Member] | Other Restructuring [Member] | ||||
Restructuring Reserve [Roll Forward] | ||||
Restructuring Charges | $ 0 | $ 0 | $ 1 |
Segment Information (Details)
Segment Information (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Segment Information [Line Items] | |||||||||||
Oil, gas and NGL revenues | $ 509 | $ 439 | $ 402 | $ 417 | $ 415 | $ 392 | $ 381 | $ 284 | $ 1,767 | $ 1,472 | $ 1,557 |
Oil, gas and NGL revenue, excluding Other Revenue | 1,765 | 1,468 | 1,550 | ||||||||
Operating expenses: | |||||||||||
Lease operating | 215 | 244 | 285 | ||||||||
Transportation and processing | 300 | 272 | 212 | ||||||||
Production and other taxes | 64 | 42 | 46 | ||||||||
Depreciation, depletion and amortization | 467 | 572 | 917 | ||||||||
Results of Oil and Gas Operating before tax | 719 | (690) | (4,814) | ||||||||
Other Non Oil and Gas Revenue | 2 | 4 | 7 | ||||||||
General and administrative | 200 | 213 | 244 | ||||||||
Impairment of Oil and Gas Properties | 0 | 0 | 522 | 506 | 0 | 1,028 | 4,904 | ||||
Other | 6 | 20 | 10 | ||||||||
Total income tax provision (benefit) | (41) | 22 | (1,585) | ||||||||
Total operating expenses | 1,252 | 2,391 | 6,618 | ||||||||
Income (loss) from operations | 183 | $ 112 | $ 99 | $ 121 | 112 | $ 45 | $ (498) | $ (578) | 515 | (919) | (5,061) |
Interest expenses, net of interest income, capitalized interest and other | (82) | (98) | (145) | ||||||||
Commodity derivative income (expense) | 47 | 191 | (259) | ||||||||
Income (loss) before income taxes | 386 | (1,208) | (4,947) | ||||||||
Total assets | 4,961 | 4,312 | 4,961 | 4,312 | 4,768 | ||||||
Additions to long-lived assets | 1,289 | 1,371 | 1,745 | ||||||||
UNITED STATES | |||||||||||
Segment Information [Line Items] | |||||||||||
Oil, gas and NGL revenue, excluding Other Revenue | 1,679 | 1,251 | 1,288 | ||||||||
Operating expenses: | |||||||||||
Lease operating | 188 | 189 | 231 | ||||||||
Transportation and processing | 300 | 272 | 212 | ||||||||
Production and other taxes | 64 | 41 | 45 | ||||||||
Depreciation, depletion and amortization | 443 | 458 | 754 | ||||||||
Results of Oil and Gas Operating before tax | 684 | (671) | (4,740) | ||||||||
Other Non Oil and Gas Revenue | 2 | 4 | 7 | ||||||||
General and administrative | 194 | 205 | 237 | ||||||||
Impairment of Oil and Gas Properties | 962 | 4,786 | |||||||||
Other | 5 | 20 | 9 | ||||||||
Total income tax provision (benefit) | 180 | (330) | (1,842) | ||||||||
Net Income Loss From Oil And Gas Properties | 307 | (562) | (3,137) | ||||||||
Total assets | 4,875 | 4,166 | 4,875 | 4,166 | 4,452 | ||||||
Additions to long-lived assets | $ 1,288 | $ 1,369 | $ 1,645 | ||||||||
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 37.00% | 37.00% | 37.00% | ||||||||
China [Member] | |||||||||||
Segment Information [Line Items] | |||||||||||
Oil, gas and NGL revenue, excluding Other Revenue | $ 86 | $ 217 | $ 262 | ||||||||
Operating expenses: | |||||||||||
Lease operating | 27 | 55 | 54 | ||||||||
Transportation and processing | 0 | 0 | 0 | ||||||||
Production and other taxes | 0 | 1 | 1 | ||||||||
Depreciation, depletion and amortization | 24 | 114 | 163 | ||||||||
Results of Oil and Gas Operating before tax | 35 | (19) | (74) | ||||||||
Other Non Oil and Gas Revenue | 0 | 0 | 0 | ||||||||
General and administrative | 6 | 8 | 7 | ||||||||
Impairment of Oil and Gas Properties | 66 | 118 | |||||||||
Other | 1 | 0 | 1 | ||||||||
Total income tax provision (benefit) | 17 | (16) | (49) | ||||||||
Net Income Loss From Oil And Gas Properties | 11 | (11) | (33) | ||||||||
Total assets | $ 86 | $ 146 | 86 | 146 | 316 | ||||||
Additions to long-lived assets | $ 1 | $ 2 | $ 100 | ||||||||
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 60.00% | 60.00% | 60.00% |
Supplemental Cash Flows Infor73
Supplemental Cash Flows Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Cash Payments [Abstract] | |||
Interest payments, net of capitalized interest | $ 84 | $ 97 | $ 119 |
Proceeds from Income Tax Refunds | 2 | ||
Income tax payments | (17) | (25) | |
Increase (Decrease) in Other Receivables | 0 | 6 | 6 |
Non Cash Items Excluded From Statement of Cash Flows [Abstract] | |||
(Increase) decrease in accrued capital expenditures | (81) | 33 | 225 |
Increase in asset retirement costs | $ 31 | $ 46 | $ (4) |
Quarterly Results of Operatio74
Quarterly Results of Operations (Details) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Oil, gas and NGL revenues | $ 509 | $ 439 | $ 402 | $ 417 | $ 415 | $ 392 | $ 381 | $ 284 | $ 1,767 | $ 1,472 | $ 1,557 |
Ceiling test and other impairments | 0 | 0 | 522 | 506 | 0 | 1,028 | 4,904 | ||||
Income (loss) from operations | 183 | 112 | 99 | 121 | 112 | 45 | (498) | (578) | 515 | (919) | (5,061) |
Net Income (Loss) Attributable to Parent | $ 95 | $ 87 | $ 98 | $ 147 | $ 13 | $ 48 | $ (667) | $ (624) | $ 427 | $ (1,230) | $ (3,362) |
Earnings (Loss) Per Share, Basic | $ 0.47 | $ 0.44 | $ 0.49 | $ 0.74 | $ 0.07 | $ 0.24 | $ (3.36) | $ (3.52) | $ 2.14 | $ (6.36) | $ (21.18) |
Earnings (Loss) Per Share, Diluted | $ 0.47 | $ 0.44 | $ 0.49 | $ 0.73 | $ 0.07 | $ 0.24 | $ (3.36) | $ (3.52) | $ 2.13 | $ (6.36) | $ (21.18) |
Loss Contingency, Damages Paid, Value | $ 18 | $ 18 | |||||||||
Change in Net Income | $ 8 | ||||||||||
Current Income Tax Expense (Benefit) | $ 45 | $ 26 | $ (78) | $ 9 | $ 17 |